Manual on PROTECTION OF GENERATORS, GENERATOR TRANSFORMERS AND 220 kV AND 400 kV NETWORKS
PUBLICATION NO. 274 (Revised)
Editors C.V.J.VARMA P.K. LAL ----__
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CENTRAL BOARD OF IRRIGATION AND POWER Malcha Marg, Chanakyapuri, New Delhi 110 021 New Delhi
November 1999
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LIST OF CONTENTS
Page Foreword
iii
Introduction
1
Section 1
Generator and Generator Transformer Protection
2
Section 2
Line Protection
19
Section 3
Auto Reclosure
23
Section 4
Transformer Protection
26
Section 5
Reactor Protection
29
Section 6
Bus Bar Protection
31
Section 7
Local Breaker Back-up (Breaker fail) Protection
33
Sectiorl 8
Fault Locator, Disturbance Recording and Event Logging Equipment
35
Section 9
Guidelines for Protection System Engineering
38
Section 1 0
CT, CVT Locations
41
Section 11
Commissioning Tests & Maintenance Recommendations
Section 12
Test Equipments
Section 13
Reference Standards
Section 1
GENERATOR AND GENERATOR TRANSFORMER PROTECTION 1.0
GENERAL
1.1
Generators are designed to run at a high load factor for a large number of years and permit certain incidences of abnormal working conditions. The machine and its auxiliaries are supervised by monitoring devices to keep the incidences of abnormal working conditions down t o a minimum. Despite the monitoring, electrical and mechanical faults may occur, and the generators must be provided with protective relays, which, in case of a fault, quickly initiate a disconnection of the machine from the system and, if necessary, initiate a complete shut down of the machine.
1.2
Recommendations contained herein for electrical protective systems of generator and generator transformer are intended t o be used for generators of 10 MVA and above. It describes t h e requirements of various protections, special comments t o help in determining application of these protections, for units of various types and sizes, setting criteria and tripping principles.
The protection requirements of machines used in pumped storage schemes need further attention and the recommendations given below do not cover these details. 1.2.1 Generator can be connected t o the primary transmission system in following two ways:
1. Unit Scheme In this scheme no switchgear is provided between the generator and generator transformer which are treated as a unit. A unit auxiliary transformer is tapped off at the interconnection, for the supply of power to the auxiliary plant. 11. Generator Circuit Breaker Scheme In this scheme, a generator circuit breaker is provided between the generator and generator transformer:
1.3 -
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In view of generator unit being a complex system, various electrical hazards require consideration. These are given below: Stator insulation failure Overvoltage Rotor faults Loss of synchronism Over/under frequency Overload Unbalanced loading Loss of excitation Reverse power Inadvertent energisation of generator
1.4
Following a r e the various protections recommended for the generator and generator transformer protection. Type of Fault
GENERATOR STATOR Short Circuits
Asymmetry Stator overload Earth fault stator Loss of excitation Out of step ~onitoring
Blade fatigue Inter turn fault Mag. Circuits Higher voltage Accidential energisation Monitoring GENERATOR ROTOR Rotor ground GENERATOR TRANSFORMER Short circuits
Ground fault Overhang
Protection Functions
ANSI Device No.
Generator differential Overall differential Minimum impedance (alternatively Over current/under voltage)
87 G 8 7 GT 21 G 51/27 G 46 G 51 G 64 GI 6 4 G2 40 G 98 G 32 G/37 G
Negative sequence Overload 95% stator earth fault 100% stator earth fault Loss of excitation Pole slip Low forward powerheverse power (Double protection for large generators) Minimum frequency Over voltage or over current Overfluxing volt/Hz Over voltage Dead machine PT fuse failure
81 G 95 G 99 G 59 G 27/50 G 60 G 64 F 8 7 GT 51 GT 87 T 51 NGT 87 NT 8 7 HV
UNIT AUXILIARY TRANSFORMER Short circuit 87 UAT 51 UAT 5 1 NUAT Ground fault 6 4 UAT
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Rotor earth fault Overall differential Overcurrent Transformer differential Earth fault over-current Restricted earth fault HV winding cum overhang differential Transformer differential Over-current Residual over-current Restricted earth fault
The transformer guards like Buchholtz protection, Winding temperature high, Oil temperature high, 2tc. are also important and shall be provided as per transformer manufacturer's recommendations.
1.5
Recommendations regarding selection of the generator protections for units of different types and sizes are summarised in the table given below:
RECOMMENDED PROTECTIONS FOR GENERATORS Hydro Turbines
Steam/Gas Turbines
Functions <
Small (< 1 0 MVA)
Medium (10-100 MVA)
Large (> 100 MVA)
Small (< 10 MVA)
Medium (10-100 MVA)
Large (> 100 MVA)
Differential
Y
Y
Y
Y
Y
Y
95%Stator E/F
Y
Y
Y
Y
Y
Y
100% Stator E/F
N
Y/N
Y
N
Y/N
Y
Interturn Faults
Y
Y
Y
Y
Y
Y
Bacltup Impedance
N
Y
Y
N
Y
Y
Voltage Controlled O/C
Y
N
N
Y
N
N
Negative Sequence
Y
Y
Y
Y
Y
Y
Field Failure
Y
Y
Y
Y
Y
Y
Reverse Power
Y
Y
Y
Y
Y
Y
Pole Slipping
N
N
Y
N
N
Y
Overload
N
N
N
Y
Y
Y
Over voltage
Y
Y
Y
Y
Y
Y
Under frequency
Y
Y
Y
Y
Y
Y
Dead Machine
N
N
Y
N
N
Y
Rotor Earth Fault
Y
Y
Y
Y
Y
Y
Overfluxing
N
Y
Y
N
Y
Y
2.0
DETAILED REQUIREMENTS
2.1
Generator Stator
2.1.1 Generator Differential Protection (87 G) This is a unit type protection, instantaneous in operation, covering the stator winding for phase to phase faults. The generator differential relay is not sensitive to single phase to earth faults due to the high neutral earthing .resistance arrangement.
As this protection operates for generator internal faults, opening the generator breaker in class-A eliminates the system in-feed to the fault (if the unit is synchronised). For all machines of ratings 1 0 MVA and above, this protection shall be provided. Requirements: (i) Be triple pole type with individual phase indication (ii) Have operating time less than 30 milliseconds at 2 times setting (iii) Be high or low impedance principle based
(iv) Operating current 5 to 10% of nominal current (v) High stability against maximum through fault condition, CT saturation, harmonics and DC transients (vi) Be provided with suitable voltage dependent resistors across the relay to limit the voltage to safe level, in case of high impedance type relay 2.1.2 Generator-Transformer differential protection (87 GT) This is a unit type protection with coverage from the generator terminals up to the HV breaker and the generator transformer HV terminals. It will detect phase faults on both sides of the generator transformer and single phase to earth faults of the HV side only (the earth fault current on the LV side is very small, due to the high neutral earthing resistance). Generator transformer differential relays have harmonic restraint circuits to prevent incorrect operation when the generator and unit transformers are energised from the system. This shall be provided for all machines of rating 1 0 MVA above. The protection need not include Unit Auxiliary Transformer (UAT) in its zone and UAT should be covered by a separate protection. In case of breaker-and-half switching scheme, 'the CT's associated with main and tie breakers shall be connected to separate bias winding and these shall not be paralleled in order to avoid false operation due to dissimilar CT transient response. Requirements:
(iii)
(vi) (vii) (viii)
Be triple pole type with individual phase indication Have through fault restraint features for external faults with an adjustable or multi-bias setting Have,magnetizing inrush restraint features and also be stable for inrush under normal over fluxing conditions, magnetising inrush proof feature shall not be achieved through any intentional time delay e.g. use of timers to block relay operation Shall have unrestrained instantaneous highset overcurrent unit operation which is unaffected by inrush Have one bias winding per phase and per CT input (However UAT CT need not have separate input and may be paralled with the Generator CT) Have an adjustable operating current Have an operating time not greater than 3 0 milli seconds at 5 times setting Have facility for ratio and phase angle correction either through auxiliary transformer or through in built provisions.
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2.1.3 Backup Protections for Short Circuits This shall be provided for all machines of 1 0 MVA and above. Voltage restrained over current relay may be used in place of minimum impedance relay in case of machines with rating less than 1 0 MVA. 2.1.3.1
Backup impedance protection (21 G)
This operates for phase faults in the unit, in the HV yard or in the adjacent transmission lines, with a suitable delay, for cases when the corresponding main protection fails to operate. The impedance measured by the relay is influenced by the relay connection, the fault type and generator and system source impedance for faults on the high voltage side of the delta-star connected generator transformer. A circular characteristic the center of which corresponds to connection position of VT should be used for this reason. The impedance relay shall have fuse-fail interlock. Requirements Be triple pole type Be of single step under impedance type Shall have two adjustable definite time delay relays of 0.5-5 seconds Be suitable for measuring two and three phase faults within a set distance from the point of installation (v) Shall be able to operate for fault currents down to 0.3 In.
(i) (ii) (iii) (iv)
Setting Recommendations The impedance relay shall have reach setting to cover the longest HV outgoing line or 70% of rated generator load impedance. - Time relay of step 1 - 0.5 sec. - Time relay of step 2 shall be set to coordinate with third zone time of distance relay or back up o/c relay of the outgoing line
2.1.3.2 Overcurrent/Undervoltage protection (51/27) G Requirements (i) Be triple pole type (ii) Shall be able to operate when the fault current from the generator terminals becomes
low due to excitation system characteristic (iii) Shall have under voltage criteria !iv) Shall reset to de-energised position if under-voltage criteria disappears 2.1.4 Negative Phase Sequence Protection (46G) The negative phase sequence protection safeguards the generator rotor against over heating caused by the induced double frequency (100 Hz) currents when negative phase sequence currents are present in the stator. The negative phase sequence current can appear due to unbalanced single phase loads or transmission line unsymmetrical faults. This shall be provided for all machines of ratings 1 0 MVA and above. Requirements: (i) Be triple pole type
(ii) Have an alarm unit and a trip unit (iii) Have a continuously adjustable negative sequence current setting (iv) Have alarm unit range covering negative phase sequence current of 5-10% of generator rated current continuously adjustable (v) Have a definite time setting range of 1-10 secs. associated with an alarm unit (vi) Have a trip unit with a variable time current characteristics matching with the generator I22t characteristic Setting Recommendations The relays should be set to the NPS capability of the generator. The NPS capability of the machine varies considerably from one machine to another. Alarm unit shall be set at 50% of continuous withstand capability value of the machine and time delay for alarm can be 3 Secs. 2 . 1 . 5 Generator Overload Protection (51G) Overload relay is used as an additional check of the stator winding temperature. This may be provided for hydro units where there are high head variations and connected for alarm. It may also be connected for run back. In case of thermal set there is no chance of thermal overloading as the machine is provided with number of limiters and therefore is not recommended. Requirements: (i) Be single pole type (ii) Be of definite time over-current type (iii) Have a continuously adjustable setting range of 50-200%
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(iv). Have a drop-off/pick-up ratio greater than 95% (v) Have an adjustable time setting range of 2.5 to 2 5 sec. 2.1.6 Generato; Stator Earth Fault Protection The high neutral earthing resistance arrangement limits the generator earth fault current to less than 1 0 amperes, thus minimising damage to the core laminations. Although a single phase to earth fault is not critical, it requires clearance within a short time, due to the following: - It may develop into a phase to phase fault (due to presence of ionised air). - If a second earth fault occurs the current is no longer limited by the earthing resistor. - Fire may result from the earth fault arc.
Two different types of stator earth fault relays are recommended both installed in the secondary circuit of the generator. 2.1.6.1 0-95% stator earth fault protection (64G1) This protection zone is limited to approximately 95% of the stator winding due to the danger of false tripping. This shall be voltage relay monitoring the voltage developed across the earthing resistor by the neutral return current. This is normally used as back up protection. It also covers the generator bus, low voltage winding of the unit transformer and the high voltage winding of the UAT. When connected to open delta winding of generator PT, the protection shall be blocked for PT fuse failure.
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For faults within 10% of the generator neutral, the resulting current is not enough to operate the relay. This shall be provided for all machines of ratings 1 0 MVA and above. Requirements: (i) Single pole type (ii) Shall have independently adjustable voltage and time setting (iii) Suitable to protect 95% of stator winding
(iv) Be suitable for operation from broken-delta voltage transformers or neutral grounding transformer secondary (v) Shall be insensitive to 3rd harmonic voltage Setting Recommendations Pick up voltage of the relay - 5% of maximum neutral voltage Time delay - 0.3 to 0.5 secs. 2.1.6.2 100% stator earth fault protection (64G2) This protects the whole stator winding and the generator neutral. The relay generally operates on the principle of low frequency signal injection into the secondary of the earthing transformer, detecting the corresponding current if an earth fault occurs. The relay is set in terms of insulation resistance. This is normally used as the main protection. Alternatively, a protection based on change in magnitude/distribution of 3rd harmonic voltage caused by an earth fault is used. When provided, this shall have voltage check or - current check unit as applicable, to prevent faulty operation of the relay at generator stand still or during the machine running down period. This protection shall always be provided for machine above 1 0 0 MVA. The option is left to the utility depending upon the importance of the machine for machines of smaller sizes. Low frequency current injection based relays are recommended for machines of 200 MVA and above. ,
The 95-100% relay if separately available, may be connected for alarm and operator can take the machine out. Requirements: (i) Be suitable to protect 100% of stator winding (ii) Be insensitive to external faults, transients and inherent harmonic currents. (iii) Shall be based on low frequency current injection principle/alternatively shall operate
on the principle of detecting change in the magnitude/distribution of 3rd harmonic voltage caused by an earth fault. (iv) Have continuously adjustable time delay range 1-10 seconds (v) If based on injection principle - shall continuously monitor ground circuit - shall continuously monitor injection signal and injection equipment - shall be in service at standstill, startup and stop (vi) If based on 3rd harmonic voltage principle - shall have under voltage or over current check
Setting Recommendations 100% stator earth fault relay (Injection Principle) Pick up level of the relay = 500 ohms time delay - 2 seconds (Greater than 3rd zone of distance relay) 100% stator earth fault relay (3rd harmonics principle)
- Setting - Time delay -
Voltage check unit Current check unit
0.45 V (should be checked w.r.t. 3rd harmonic voltage generated by the machine) 2.0 sec. 80% of rated voltage 20% of rated current
2.1.7 Loss of Excitation Protection (40G) A conlplete loss of excitation may occur as a result of unintentional opening of the field breaker, an open circuit or a short circuit of the main field or a fault in AVR. When a generator with sufficient active load loses the field current, it goes out of synchronism and starts -to run asynchronously at a speed higher than the system absorbing reactive power for the excitation from the system. Under these conditions the stator end regions and part of the rotor get over heated. This is recommended for machines of all sizes above 1 0 MVA. Requirements: (i) Have mho characteristic lying in 3rd and 4th quadrant of impedance diagram with
adjustable reach and off set. Alternatively, this protection shall be based on directional current unit with setting range to match generator capability curve (ii) Shall have an under voltage relay and/or over current relay as an additional check (iii) Shall have timer with adjustable range of 1-10 seconds to distinguish loss of excitation from power swings Setting Recommendations: (i) For off set mho type relay - Diameter of mho circle - ( xd - x'a/2 - Off set of the mho circle from origin - X'd/2 - Time delay = 1.0 sec. - Under voltage relay = 70% (ii) For directional current type relay
- Direction current relay is set to match with the generator capability curve in 4th quadrant - Time delay 0.5 to 1 sec. - Under voltage 70% - Over current 110-115%
2.1.8 Pole Slipping Protection (98G) The loss of field protection shall be supplemented by an additional out of step function which detects all pole slips.
Pole slipping of generators with respect to the system, can be caused by a number of conditions leading to an increase in rotor angular position beyond the generator transient stability limits. Some of the causes of pole slipping are: (a) (b) (c) (d) (e)
Large network disturbances Faults on the electrical network close to the generator Weak tie between the network and the generator (tripping of transmission lines) Loss of generator field (field winding or excitation supply failure) Operating the generator in an excessive under excited mode
This is recommended for machines of 1 0 0 MVA and above. For hydro machines utilities can decide depending on machine parameters.
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Requirements: (i) Shall be capable of detecting a power swing which can lead to instability in addition to
being able to detect an actual pole slip (ii) By varying size of the characteristic it shall be possible to ensure that a trip command is given to the circuit breakers in such a way that separation of the poles occurs at a controlled angle at any time. Setting Recommendations (a) If the source of oscillation lies within a generatorhransformer unit, the machine has to be isolated from the network after the first'slip. Forward reach of relay characteristics shall cover generator/generator transformer. Tripping in this zone shall be in the first pole slip. The reach of this zone is 0.7 T . (b) If the source of oscillation lies outside the unit in the network, the generator should not
be switched off or atleast not until several pole slips have occurred. 2.1.9 Low forward power/reverse power interlock relays (32G/37G) I 1
The low forward power interlock is recommended for thermal machines and reverse power protection may be used for hydro machines to protect against motoring.
1
When the steam flow through turbine is interrupted by closing the ESVs or the governor valves, the remaining energy stored in the set is delivered to the system and the machine enters into a motoring condition drawing power from the system to supply its losses while keeping the turbo alternator shaft at synchronous speed. - The low forward power relay detects that the unit is motoring and must therefore be
shutdown
- Tripping for mechanical faults and abnormal conditions For faults in the turbine or boiler, the turbine protection closes the ESVs. For abnormal conditions, the generator protection closes the ESVs. When the generator develops low forward power, the relay after a short time delay trips the generator breaker. A protection field suppression signal may also be required if the AVR does not have a built-in facility to reduce the generator field current as the speed decreases, to avoid overfluxing conditions. Requirements: (i) Be single phase power measuring type
(ii) Have a' power setting of approximately 0.5% - 1% of rated active power of generator unit (iii) Have independent time delay relay with setting range of 1-10 seconds and 0-20 seconds
respectively on pick up (iv) Have one more common timer with a pick up setting range 5-50 seconds for annunciation that the Turbo generator set has started motoring (v) Have suitable arrangement for preventing the operation of this protection during start up and synchronising of the unit (vi) Shall be provided with possibility of angle correction to facilitate measurement of power accurately Setting Recommendations:
- low forward power relay pickup < 0.05 x Pn - timer t l - 2 seconds, t2 - 2 seconds 2.1.10 Under-frequency protection (81G) The under frequency protection
- Prevents the steam turbine and generator from exceeding the permissible operating time at reduced frequencies - Ensures that the generating unit is separated from the network at a preset value of frequency that is less than the final stage of system load shedding - Prevents the AVR from exciting the machine at reduced speeds when some protective relays may not perform at all - Prevent over fluxing of the generator. The over fluxing relay is used to protect against small overfluxing for long periods while the over voltage and under frequency relays also protect against large over fluxing for short times The stator under frequency relay measures the frequency of the stator terminal voltage Though under frequency tripping is recornmended by turbine manufactures, care should be taken by grid operating personnel in ensuring that machines are not run at lower frequencies and instead resort to means like load shedding in the event of overload. Requirements: (i) Have one alarm stage and two tripping stages (ii) Shall have setting of range of 4 5 Hz - 55 Hz with a least count of 0.1 Hz for each stage (iii) Timer for alarm stage have a range of 0 . 5 to 5 second with a least count of 0.5 second.
Timers for each tripping stage shall have range of 1 to 1 0 seconds with a least count of 0 . 1 second (iv) Shall have undervoltage blocking Setting Recommendations
- Stator under frequency relay pick up level = 48.5 Hz -
Time delay for alarm - 2 Sec.
For time delay setting of tripping stages recommendations of turbine manufacturers may be followed. 2.1.11 Inter turn fault protection (95G) It is generally considered difficult to obtain reliable protection against short circuit of one turn if the stator winding has large number of turns per phase.
Inter turn fault protection is recommended only for machines where there is a split winding and all the six terminals are brought out on the neutral side. For generator with split neutrals, conventional inter-turn fault protective scheme comprises a time delayed low set over-current relay which senses the current flowing in the connection between the neutrals of the stator winding. Alternatively a split phase differential protection may be used. Requirements (i) Over current relay with time delay (ii) Over current relay shall have built in filters t o reject higher harmonics
(iii) Range of over current shall be selected depending on maximum spill current for external fault Setting Recommendation Overcurrent relay shall be set t o maximum unbalanced current in case of external fault. Time delay 0.2 - 0 . 4 seconds 2.1.12 Generator Transformer Over Fluxing Protection (99 GT) Overfluxing protection is provided to safeguard the generator, generator transformer and unit auxiliary transformer against operation at flux densities which may cause accumulative damage to the core. From the fundamental equation V = 4.44 x f x n x 4, the level of flux is proportional t o the ratio of terminal voltage to frequency (v/f). This ratio is monitored by the protective relay. An over fluxing condition is more likely t o occur while the generator is separated from the system and the speed is allowed t o drop, but it can also happen with the machine on load if the tap changer of the generator transformer (HV side) is on a low tap position and the excitation of the generator is manually increased. In this case the increased generator terminal voltage knay cause over fluxing tripping at nominal frequency. The over fluxing protection operates with a time delay after which the tripping functions are executed. This protection must b e provided for generator-transformers of size 1 0 MVA and above. Requirements (i) Shall be phase to phase connected. (ii) Shall operate o n the principle of measurement of voltage io frequency ratio. (iii) Have inverse time characteristics compatible with generator transformer over fluxing
withstand capability for tripping. (iv) Provide an independent alarm with a definite time delay of value of V/f between 100% t o 130% of rated value. (v) Have a high resetting ratio of 98% or better. Setting Recommendations: The overfluxing capability of the transformer must be checked and the characteristic matched accordingly for both alarm and trip.
2.1.13 Generator Over Voltage Protection (59G) An over voltage on the terminals of the generator can damage the insulation of the generator, bus ducting, breakers, generator transformer and auxiliary equipment such as voltage transformers, excitation transformer etc. This should be provided for machines of all sizes, hydro and thermal Requirements: (i) Be single pole type/or triple pole type (ii) Shall have two separately adjustable stages (iii) Have a continuously adjustable setting range of 1 0 0 - 140% of rated voltage (iv) Have a drop off to pick up ratio greater than 95% (v) Have a continuously variable time delay setting range of 0.5 - 5 seconds for one relay and 2 to 2 0 seconds for the other relay.
Setting Recommendations: Stage 1 Over voltage relay pick up - 1.15 x Vn Timers t 1 - 1 0 seconds Stage 2 Over voltage relay pick up - 1.3 x Vn Timer t 2 - 0 . 5 seconds 2.1.14 Dead machine protection (27/50G) Despite existence of interlocking schemes, a number of generators have been inadvertently energized while at stand still or on turning gear. The generator and rotor may get damaged beyond repair under this condition. Other protective relays like loss of excitation, back up impedance, reverse power would operate with delays and this is not admissible. The dead machine protection permits fast tripping. This should be installed in switchyard panel rather than in generator panel to ensure that protection is available during maintenance periods when the generator protection can be rendered inoperative by switching off the DC supply to the panel. This protection is recommended for all-machines of size 1 0 0 MVA and above. The protection is connected to trip generator breakers, generator transformer breaker and the HV Bus. Requirements:
- 20 In) to initiate instantaneous tripping if generator terminal voltage is below set value. (ii) Shall have under voltage relays of range (0.2-1 Un) to permit operation of over current relays when voltage is low (iii) Shall have timers with adjustable range (0-605) to avoid operation of protection for nearby fault when the machine is in service. (iv) Shall be secure against voltage transients at closing (i) Shall consist of 3 high speed over current relays of range (0.02
Setting Recommendations: Overcurrent relay Under voltage relay Activation of relay
For Weak System 1-2 pu 20% to 40% rated voltage 2 0 Seconds after dead time
For Strong System 3-4 pu 50% to 70% of rated voltage 2 0 Seconds after dead time
2.1.15 Generator VT fuse failure monitoring (60G) This has t o be provided for all the machines since it is required for blocking of relays which can mal-operate in the event of PT fuse blowing in primary side or secondary side. Requirements: (i) Be triple pole type (ii) Be able to detect fuse failure in both primary and secondary side of VT (iii) Have a fixed setting of 70% of rated voltage and have a time delay of 4 0 t o 5 0 milli-
seconds o n pick up (iv) Be of voltage balance or equivalent type (v) Have sufficient contacts t o block tripping of those relays which are voltage dependent and give alarm 2.1.16 Rotor ground fault protection This protection shall be provided for machines of all sizes. It is recommended that the protection is connected only for alarm and the operator may take the machine out at the earliest opportunity after the first earth fault has occurred. The tripping logic should also include unit tripping in case field circuit breaker opens when the machine is running. Requirements: (i) Shall be based on DC injection principle or low frequency AC injection principle (ii) Shall be single stage or two stages (iii) Shall have built-in time delay t o prevent unwanted operation of the relay
Alternatively A sensitive voltage function operating on bridge measuring basis with auxiliary equipment. This shall have two levels, one for alarm and one for trip. Setting r a n g e s : Alarm s t a g e 1 0 0 o h m t o 2 5 k o h m , Time delay 2 - 6 0 S e c o n d s Trip stage 100. ohm to 2 5 K ohm, Time delay 2-60 Seconds Setting Recommendations:
- alarm level - 2 5 K ohm - pick up level - 5 K ohm - timer t l - 1 seconds - timer t 2 - 5 seconds
2.2 Generator-Transformer Protection For short circuit protection, transformer-differential relay and over-current relay connected to different groups are recommended. For ground faults, earth fault o/c relays and restricted earth fault relay connected to different groups are recommended. In case a overhang protection is required, the same may be combined with REF protection o n HV side of generator transformer. 2.2.1 Generator Transformer Oifferential Protection (87 GT/87 T) Requirements: (i) Be triple pole with individual phase indication
(ii) Have unrestricted instantaneous high set over current units which shall not operate
(iii)
(iv)
(v) (vi) (vii) (viii)
during inrush Have an adjustable or multi bias setting Have second harmonic or other inrush proof features and also shall be stable under normal over fluxing conditions. Magnetising inrush proof feature shall not be achieved through any intentional time delay e.g. use of timers to block relay operation or using disc operated relays. Have one bias winding per phase and per C.T. input Have an adjustable operating current Have an operating time not greater than 30 milli seconds at 5 times of setting Shall have facility for ratio and phase angle correction either through auxiliary transformer or through in built provisions.
2.2.2 Generator Transformer Backup Overcurrent Protection (51 GT) Requirements: (i) Be triple pole type (ii) Be of definite time over current type (iii) Have an adjustable setting range of 50-200% of rated current and 0.5 - 5 seconds time
delay 2.2.3 Generator Transformer Back Up Earth Fault Protection (51 NGT) This relay monitors the current in the generator transformer neutral. It can detect faults in the transformer HV side or in the adjacent network. Requirements: (i) Be of single pole type (ii) Be of definite time characteristic (iii) Have an adjustable setting range of 1 0 to 100% of rated current
(iv) Have a timer setting range of 0.5 to 5 seconds 2.2.4 HV winding cum overhang differential protection (87 HV/87 NT) This is a unit type protection which operates for earth faults on the generator transformer HV side and also covers a large portion of the HV winding and the HV terminals upto the HV current transformers. Requirements: (i) Be triple pole type (Single pole if used as Restricted E/F Protection) (ii) Have operating time less than 30 milliseconds at 2 times setting (iii) Be high impedance or low impedance type
(iv) Operating current shall be 0.1 - 0.4 In (v) High stability against maximum through fault condition, CT saturation, harmonics and DC transients (vi) Be provided with suitable non linear resistors across the relay to limit the peak voltage to 1000 volts, in case of high impedance type (vii) Be provided with faulty phase identification
2.3 Unit Auxiliary Transformer Protections For short circuit protection, unit auxiliary transformer differential relay, overload relay for alarm
and over current relay connected to different groups are recommended. However a utility may carry out an application check and decide not to have a separate differential relay for UAT. For ground faults residual O/c relay and Restricted E/F relays connected to different groups shall be provided. The type of connection may be either current based or voltage based depending on the grounding system. 2.3.1 Unit Transformer Differential Protection (87 UAT) This is a unit type protection covering the unit transformer and the cable connection to the unit board. This protection operates for phase faults, but not for single phase to earth faults as this current is limited by the neutral earthing resistance. The unit transformer differential relay initiates a general trip and unit shutdown. Requirements: (i) Be triple pole with individual phase indication (ii) Have unrestricted instantaneous high set over current unit which shall not operate during inrush (iii) Have an adjustable or multi bias setting (iv) Have second harmonic or other inrush proof features and also should be stable under normal over fluxing conditions, magnetising inrush proof feature shall not be achieved through any intentional time delay e.g. use of timers to block relay operation or using disc operated relays. (4 Have one bias winding per phase and per C.T. input (vi) Have an adjustable operating current (vii) Have an operating time not greater than 3 0 milli seconds at 5 times of setting (viii) Shall have facility for ratio and phase angle correction either through auxiliary transformer or through in built provisions.
2.3.2 Unit Transformer back up over current protection (51UAT) Relay (i) Be triple pole type
(ii) Be of definite time over current type (iii) Have an adjustable setting range of 50-200% of rated current and 0 . 5 to 5 seconds time delay 2.3.3 Unit Transformer back-up earth fault protection (51NUAT) (i) Be single pole type (ii) Be of definite time over current type (iii) Have a setting rage of 10-100% of rated current and time setting range of 0.5-5 seconds
2.3.4 Unit transformer restricted earth fault protection (64 UAT) (i) (ii) (iii) (iv) (v)
Be single pole type Have operating time less than 3 0 milli seconds at 2 times setting Be high impedance or low impedance type Operating current shall be 0.1 - 0 . 4 In High stability against maximum through fault condition, CT saturation, harmonics and DC transients
(vi) Be provided with suitable non-linear resistors across the relay to limit the peak .voltage to 1000 volts, in case of high impedance type (vii) Be provided with fault indication
3.
ENGINEERING RECOMMENDATIONS
3.1 Redundancy The protection functions shall be subdivided into two groups each being independent and capable of providing uninterrupted protection even in the event of one of the protection groups failing. Given below is recommendation for dividing the protections in two groups: GROUP A
GROUP B
Generator Generator differential
Over-all differential
Minimum impedance (or alternatively over current/under voltage)
95% stator earth fault Loss of excitation
Negative sequence protection
Pole slip
Over load protection
Under frequency
100% stator earth-fault Rotor earth fault Reverse Power
Reverse power
Over voltage
Over fluxing
Inter-turn fault
(1 ~ e n e i a t o rTransformer
1I
Transformer differential
Over current
Earth fault over current
Restricted earth fault HV winding cum overhang differential
I I Unit Auxiliary Transformer
II
Transformer differential
1 Ground fault over current
II
1I Over current Restricted earth fault
I1
I
3.2 Tripping Principles In general, it is best if generator protection relays initiate non-sequential trip mode (Class-A)for unit isolation. However sequential tripping (Class B) provides a better means of tripping a steam turbine generator on some abnormal operating conditions where delayed tripping of the generator will not result in increased damage to the turbine, generator or other electrical equipment. The reason for sequentially tripping a steam turbine generator is to avoid the overspeed condition that results when the generator main breaker is tripped while steam is applied to the turbine.
Proper control logic is critical to the design of a sequential tripping scheme and requires some sort of mechanical "Turbine Tripped" indication (i.e. steam stop valve limit switches, trip oil system pressure switches etc.) which is supervised by an electrical reverse power relay. This relay is normally set to detect very low power levels and incorporates a brief time delay of the order of several seconds for added security. It has been recommended that generator protective relays, initiate non-sequential trip mode for isolation of the unit due t o electrical faults. Only devices protecting unit from 'an abnormal mechanical operating condition or an abnormal (not faulted) electrical condition or normal shut down should initiate a sequential trip.
Section 2
LINE PROTECTION 1.0
GENERAL
The line protection relays are required to protect the line and clear all type of faults on it within shortest possible time with reliability, selectivity and sensitivity. The line protection relays shall be suitable for use with capacitive voltage transformers having passive damping and transient . response as per IEC 186. Recommendation for provisions of line protection at different voltage levels are as follows:
There should be two independent high speed main protection schemes called Main-I and MainI1 with at least one of them being carrier aided non-switched three zone distance protection. The other protection may be a phase segregated current differential (this may require digital communication) phase comparison, directional comparison type or a carrier aided non-switched distance protection. Further, if Main-I and Main-I1 are both distance protection schemes, then they should be preferably of different types. However, they need not necessarily be of different make. Both the protections should be suitable for single and three phase tripping. In addition to above following shall also be provided: (i) Two stage over-voltage protection. However in such cases where system has grown
sufficiently or in case of short lines, utilities on their discretion may decide not to provide this protection. (ii) Auto reclose relay suitable for 1 ph/3 ph (with deadline charging and synchro check facility) reclosure. (iii) Sensitive IDMT directional E/F relay
220 kV Lines There should be atleast one carrier aided non-switched three zone distance protection scheme. In addition to this another non-switched/switched distance scheme or directional over current and earth fault relays should be provided as back up. Main protection should be suitable for single and three phase tripping. Additionally, auto-reclose relay suitable for 1 ph/3 ph (with dead line charging and synchro-check facility) reclosure shall be provided. In case of both'line protections being Distance Protections, IDMT type E/F relay shall also be provided additionally.
1.2
2.0
REQUIREMENTS
2.1 Distance Protection Distance Protection scheme shall have the following attributes: (i) Three independent zones (ii) Non-switched type with separate measurements for a!l phase to phase and phase to
ground faults. (iii) Capable of single and three phase tripping (iv) Directional (mho or quadrilateral or other suitably shaped) characteristics for zone 1, zone 2 and zone 3
(v) Capable of operation for close-up three phase faults and switch on to faults (vi) Adjustable characteristic angle to match line angle wherever applicable (vii) Accuracy of better than or equal to 5% of set value for reach measurement in zone 1 and better than or equal to 10% of set value for zone 2 and zone 3 (viii) Accuracy of better than or equal to 5% of set value for time measurement of zone 2 and zone 3 (ix) Variable residual compensation (x) Shall include power swing detection feature for selectively blocking, as required. (xi) Shall include suitable fuse-failure protection to monitor all types of fuse failure and block the protection. (xii) Maximum operating time under given set of condition shall be as follows: 4
15
1 0 Ohms
2 Ohms
60%
60%
4
4
Zero Ohms
Zero Ohms
45 ms
4 5 ms for 3 phase faults
for all faults
6 0 ms for other faults
SIR Relay setting Fault location (as % of relay setting) Trip duty Contacts per phase* Fault resistance Max. Operating Times Including trip relays (if any) and with CVT *
2.2
These trip duty contacts can be provided either in-built in the distance relay or through additional relay. Making capacity of trip contracts shall be 3 0 A for 0.25 S with an inductive load of L/R > 1 0 ms Directional Comparison Protection
Shall be a unit system of protection Shall be directional comparison type suitable for operation with one signalling channel, e.g., PLCC (iii) Shall have high speed fault detection based on principles like detection of post fault travelling wave, superimposed components, etc. Shall have high sensitivity for all types of faults Shall be suitable for 1 and 3 phase tripping Shall not be affected by heavy load transfer, power swings, CT saturation, CVT transients, VT fuse failure, line charging currents, distorted primary currents and voltages, external switching activities, sudden power reversal, zero sequence, mutual coupling, shunt reactor "in-zone" switching etc. and lightning strokes (vii) Shall have features like switch on to fault, weak end infeed, echo system (viii) Shall have feature to cover nearby fault at high speed in the event of channel fail
2.3
Phase Segregated Line Differential Protection
(i) The relay shall be all digital multi microprocessor based, designed for use with modern
digital telecommunication system multiplexer conforming to ITU-T (CCITT)specifications and Fibre Optic medium.
(ii) Each phase current shall be separately evaluated at both ends for both amplitude and phase. (iii) Shall be suitable for single phase tripping and autoreclosing.
(iv) The message transmitted by the relay to other end shall include information on currents, supervision information, CT saturation detection, synchronisation of terminals etc. The measurement shall be stabilised phase by phase for CT saturation. The communication delay shall be continuously measured and automatically compensated for in the differential measurement. (vii) Communication telegram shall have error detection and correction feature. (viii) Suitable programmable evaluation algorithm will be provided to ensure proper security and dependability of the message. The connection equipment from the relay to the communication shall be a 64 kbps Channel. An optional electrical or optical port shall be provided to directly connect the signal to auxiliary channel of OLTE (optical line terminal equipment) by passing the multiplexer or for redundancy purpose. The relay shall have communication port for remote monitoring, programmaing and control. (xii) The direct intertrip signal also shall be transmitted as part of telegram. (xiii) The sampling frequency for analog signals shall be minimum 2 kHz. Filtering and measuring techniques shall be used to ensure correct performance during all operating and transient conditions.
2.4
Phase C~mparisonProtection
(i) Shall be Current phase comparison type. (ii) Shall be suitable for operation with one signal channel. (iii) Shall have high sensitivity for all types of faults.
(iv) Shall be capable of single and three pole tripping. (4 Shall have facility for blocking/permissive trip modes (vi) Shall have facility for direct transfer tripping (vii) Shall have comprehensive alarm and test facilities (viii) Shall not be affected by heavy load transfer, power swings, CT saturation,'CT phase errors, Propagation delays, Capacitance current etc., as is typical of unit protections.
2.5
Over Voltage Protecti~n
The relay shall have following features: - Have a high drop off to pickup ratio - Have adjustable setting range for voltage and time - Have two stages - Low set stage shall monitor any one phase to phase voltage and shall have associated timer - High set stage shall monitor all three phase to phase voltage and shall have associated timer
3.0
Special Comments
(i) If found necessary, at certain locations, out of step tripping relays shall be provided for
islanding the system during disturbances
(ii) For short line application distance relays should have shaped characteristics for ground
faults and be used in permissive over reach mode with weak end infeed logic. Further, if it is a double circuit line, current reversal logic should also be available. (iii) O / V relay for 400 kV lines shall be connected to trip concerned line breaker(s), start LBB, block auto reclosure and send direct trip command. (iv) The directional earth fault relay recommended along with the distance relay should be seen as a supplement to it and not as a back up. It helps to detect very high resistance fault which distance relay cannot. (v) HVDC Systems connected to AC networks with low short circuit levels can influence AC line protections in it vicinity. This aspect needs to be looked into on case to case basis.
4.0
SETTING CRITERIA
4.1
Reach Settings of Distance Protection (i) Zone-I: to be set to cover 80-85% of protected line length (ii) Zone-11: to be set to cover minimum 120% of length of principle line section. However, in case of D/C lines 150% coverage must be provided to take care of, under reaching due to mutual coupling effect but, care is to be taken that it does not reach into next lower voltage level. (iii) Zone-111: For 400 kV lines Zone-111 to be set to cover 120% of principle section plus , adjacent longest section subject to a reach restriction so that it does not reach into next lower voltage level. For 220 kV lines, Zone-111 reach may be provided to cover adjacent longest section if there is no provision of LBB or all protection are connected to single DC source at remote and substation. (iv) Resistive reach: Resistive reach should be set to give maximum coverage subject to check of possibility against load point encroachment considering minimum expected voltage and maximum load. Also attention has to be given to any limitations indicated by manufacturer in respect of resistive setting vis-a-vis reactance setting.
, ,
'
Time Setting of Distance Protection
I
1 1
I
I
I ]
'
, / I
,
4.2
I
I
I
A Zone-I1 timing of 0.3 second is recommended. However, if a long line is followed by a short line, then a higher setting (say 0.5 sec) may be adopted on long line to avoid indiscriminate tripping through Zone-I1 operation on both lines. Zone-I11 timer should be set so as to provide discrimination with the operating time of relays provided in subsequent sections with which Zone-111 reach of relay being set overlaps.
4.3
O/V Protection
4.3.1 Low set stage may be set at 110% with a typical time delay of 5 seconds. However, a time grading of 1 second may be provided between relays of different lines at a station. Longest time delay should be checked with expected operating time of overfluxing relay of the transformer to ensure disconnection of fine before tripping of transformer. 4.3.2 High set stage may be set at 150% with a time delay of 100 m.second. 4.4
Power Swing Blocking Function Associated with Distance Relays
Decisions pertaining to allowing which Zone to trip and which to block should be taken based on system studies oil case to case basis.
Section 3
AUTO-RECLOSING 1.0
GENERAL
The auto-reclosing of power lines has become a generally accepted practice. Reports from different parts of the world show that in certain networks in regions subject to a high lightning intensity only about 5 per cent of the faults are permanent. Auto-reclosing therefore provides significant advantages. Outage times will be short compared to where station personnel have to re-energise the lines after a fault. Additionally, in interconnected networks auto-reclosing helps in maintaining system stability. Following different arrangements of auto-reclosing are possible: High speed single pole reclosing (HSAR) High speed three pole reclosing (HTAR) Delayed three pole reclosing (DAR) DAR with dead line (DL) and synchronism check(SC) HTAR with DL and S C HTAR with parallel line check (PC) In case of HSAR and HTAR without check, the two ends can be reclosed at about the same instant. In case of DAR and HTAR with DL and SC the C.B. at one end recloses first after the set dead time and with a check of dead line condition. After a successful line re-energization from one end the voltage, phase angle and possibly frequency on the line and station side are compared. At acceptable synchronous in-phase conditions the C.B. at the second end is reclosed.
1.1
Recommendations for provisions of auto-reclosing.
Presently 1 phase high speed auto-reclosure (HSAR) at 400 kV and 220 kV level is widely practised including on lines emanating from Generating Stations and the same is recommended for adoption. If 3-phase auto-reclosure is adopted in future the application of the same on lines emanating from generating stations should be studied and decision taken on case to case basis.
2.0
REQUIREMENTS
It shall have the following attributes: (i) Have single phase and/or three phase reclosing facilities. (ii) Have a continuously variable single phase dead time. (iii) Have continuously variable three phase dead time.
(iv) Have continuously variable reclaim time. (4 Incorporate a facility of selecting single phase/three phase/single and three phase autoreclose and non-auto reclosure modes. (vi) Have facilities for selecting check synchronising or dead line charging features. (vii) Be of high speed single shot type (viii) Suitable relays for S C and DLC should be included in the overall auto-reclose scheme. (ix) Should allow sequential reclosing of breakers in one and half breaker or double breaker arrangement.
3.0
SPECIAL COMMENTS
3.1
Fast simultaneous tripping of the breakers at both ends of a faulty line is essential for successful auto-reclosing. Therefore, availability of protection signalling equipment is a pre-requisite.
3.2
Starting and Blocking of Auto-reclose Relays:
Some protections start auto-reclosing and others block. Protections which start A/R are MainI and Main-11 line protections. Protections which block A/R are: - Breaker Fail Relay - Line Reactor Protections - O/V Protection
- Received Direct Transfer trip signals - Busbar Protection - Zone 2/3 of Distance Protection
- Carrier Fail Conditions - Circuit Breaker Problems.
When a reclosing relay receives start and block A/R impulse simultaneously, block signal dominates. Similarly, if it receives 'start' for 1-phase fault immediately followed by multi-phase fault the later one dominates over the previous one. .3.3
Following comn~entsare for multi-breaker arrangements of one and half breaker or double breaker arrangement
3.3.1 In a mu.lti-C.B. arrangement one C.B. can be taken out of operation and the line still be kept in service. After a line fault only those C.Bs which were closed before the fault. shall be reclosed. 3.3.2 In multi-C.B. arrangement it is desirable to have a priority arrangement so as to avoici closing of both the breakers in case of a permanent fault. This will help in avoiding unnecessary wear and tear. A natural priority is that the C.B. near the busbar is reclosed first. In case of faults on two lines on both sides of a tie C.B. the tie C.B. is reclosed after the outer C.Bs. The outer C.Bs. do not need a prioritin3 with respect to each other. 3.3.3 In multi-breaker arrangement it is necessary to trip two C.Bs. to clear a line fault and also auto reclose these two. Basically two types of arrangement for C.B. associated relays are possible i.e. - C.B. Oriented
- Line Oriented With C.B. oriented arrangement co-operation between C.Bs, Synchrocheck relay etc. is straight forward and autoreclose mode can be selected separately for each breaker. With line oriented arrangement interconnections between line relays and reclosure relay is simpler, but cooperation with circuit breakers schemes becomes complicated. For the above reasons C.B. oriented arrangement is recommended.
3.4
In case of bus bar configuration arrangement having a transfer breaker, a separate autoreclosure relay for transfer breaker is recommended.
4.0
SETTING CRITERIA
4.1
Dead Time Auto-reclosing requires a dead time which exceeds the de-ionising time. The time required for the de-ionising of the fault path depends on several factors including the arcing time, fault duration, wind conditions, circuit voltage, capacitive coupling to adjacent conductors, etc. The circuit voltage is the factor having the predominating influence on the de-ionising time. Single phase dead time of 1.0 sec. is recommended for both 4 0 0 kV and 220 kV system.
4.2
Reclaim Time
The reclaim time is the time during which a new start of the auto-reclosing equipment is blocked. If reclosing shot has been carried out and the line is energised and a new fault occurs before the reclaim time has elapsed, the auto-reclosing equipment is blocked and a signal for definite tripping of the breaker is obtained. After the reclaim time has elapsed, the auto-reclosing equipment returns to the starting position and a new reclosing sequence can occur. The reclaim time must not be set to such a low value that the intended operating cycle of the breaker is exceeded, when two fault incidents occur close together. If the breaker is closed manually, the auto-reclosing equipment is blocked and cannot start again until the reclaim time has elapsed. For the breaker to be used for auto-reclosing, it is essential that it has the operating mechanism and breaking capacity necessary for it to be able to perform the auto-reclosing sequences required.
4.3 Circuit Breaker Requirement According to IEC Publication 56.2, a breaker must be capable of withstanding the following operating cycle with full rated breaking current: The recommended operating cycle at 400 kV and 220 kV is as per the IEC standard. Therefore, reclaim time of 2 5 Sec. is recommended.
Section 4
TRANSFORMER PROTECTION 1.0
GENERAL
A Power Transformer is a very valuable and vital link in a Power Transmission system. Reliable, secure and fast protection system for the transformer is essential to minimise the damage in case of an internal fault with suitable back up protection scheme to take care of uncleared system faults. Faults occur in Transformer due to insulation breakdown, ageing of insulation, overheating due to over excitation, oil contamination and leakage or reduced cooling. To give an early warning and to minimise the damage in case of a fault it is necessary to equip it with monitors and Protective relays. Recommendations for provision of protective and monitoring equipment for transformers of 400 kV and 220 kV class are as follows:
1.1
Following are the various protections recommended for the transformer protection: Transformer differential protection Overfluxing protection Restricted earth-fault protection Back up directional O/C + E/F protection on HV side Back up directional O/C + E/F protection on LV side Protection and monitors built in to Transformer (Buchholz relay, Winding and Oil Temperature Indicators, Oil Level Indicator and Pressure Relief Device) Protection for Tertiary winding Overload Alarm
2.0
REQUIREMENTS
(i) (ii)
(4 (vi) (vii) (viji)
2.2
Differential Protection Triple pole with individual phase indication Have unrestrained instantaneous high set over-current units which should not operate during inrush. Have an adjustable or multi bias setting Have second harmonic or other inrush proof features and also should be stable under normal overfluxing conditions, Magnetising inrush proof feature shall not be achieved through any intentional time delay e.g. use of timers to block relay operation or using disc operated relays. Have one bias winding per phase and per C.T. input Have an adjustable operating current Have an operating time not greater than 30 milli seconds at 5 times of setting The scheme shall have facility for ratio and phase angle correction either through auxiliary transformer or through in-built provisions. Overfluxing Protection
(i) Overfluxing protection shall be phase to phase connected.
26
(ii) Operate on the principle of measurement of voltage to frequency ratio. (iii) Have inverse time characteristics compatible with transformer overfluxing.
(iv) Provide an independent alarm with a definite time delay at value of v/f between 100% t o 130% of rated value. (v) Have a high resetting ratio of 98% or better.
2.3
REF Protection
(i) Shall be single pole (ii) Have an operating current sensitivity of at least 10% of nominal current
(iii) Be tuned to the system frequency (iv) Have a suitable non-linear resistor t o limit the peak voltage during in-zone faults in case of high impedance type (v) Shall be high or low impedance principle type. 2.4
Back-up overcurrent protection relay (on HV side and MV side)
(i) Be 3 pole type (ii) Have IDMT characteristic (directional on MV side) (iii) Have a variable setting range of 50-200% of rated cilrrent
(iv) Have a characteristic angle, 30(/45( degrees lead (v) Shall include high unit having low transient over-reach and variable setting range typically 500-2000% of rated current (vi) Include hand reset indicators per phase 2.5
Back up earth-fault protection relay
(i) Shall be single pole type (ii) Have IDMT characteristic (directional on MV side) (iii) Have a variable setting range of typically 20-80% of rated current
(iv) Shall have a characteristic angle of 45/60 degree lag (v) Shall include high set instantaneous unit having low transient over-reach and variable setting range of typically 200-800% of rated current (vi) Shall include hand reset indicators
2.6
0;erload Alarm relay
(i) Shall be of single pole type (ii) Shall be of definite time overcurrent type (iii) Shall have a continuously variable current range of 50-200% of rated current and
continuously variable timer setting range of 1-10 sec. (iv) Shall have a drop off t o pick up ratio of 95% or better.
2.7
Tertiary Winding Protection
There are variations in the practices adopted for bringing out the tertiary terminals of ICTs. Therefore, depending upon the type of connections, adequate protection scheme may be adopted in consultation with the manufacturer of the transformer.
3.0
Special Comments
3.1
Duplication of transformer protection is not considered necessary but the protection
and monitors shall be divided in two groups viz. Gr A and Gr B at 400 kV. At 2 2 0 k ~ level this is recommended depending on the importance of the substation and where it is decided to go for two groups of protection with two station batteries. Given below is one possible way of grouping these protections: Group A
Group B
Transformer biased
R.E.F. Protection
differential relay
Buchholz Protection
Back up Protection (HV)
Back up Protectior, (MV)
Overfluxing Protection (HV)
Overfluxing Protection (MV)
Oil temperature high tripping
Overload protection (Alarm only) winding temperature high tripping
Pressurn relief tripping
OLTC Buchholz tripping
Delta winding protection
Oil level high/low tripping
Group A and B protections shall be connected to separate DC source/separately fused supplies. DC sources shall be supervised. Both Gr A and Gr B protections shall give out tripping impulses to liV, MV and LV (if applicable), circuit breakers. 3.2
The transformer overfluxing protection has been recommended on both sides for interconnecting transformers. This is to cover all possible operating conditions, e.g. the transformer may remain energised from either side. For other transformers overfluxing relay shall be provided on the untapped winding of the ~ransformer.
3.3
In case of breaker and half switching schemes, the differential protection C.Ts. associated with Main and Tie breakers should be connected to separate bias windings and these should not be paralleled in order to avoid false operation due to dissimilar C.T. transient response.
3.4
Whenever separate phase-wise C.Ts are available on neutral side of transformer, triple pole high impedance relay may be provided instead of single pole R.E.F. relay.
4.0
SETTING CRITERIA
4.1
The current setting of the back up O/C relay shall be set above the expected maximum load current so as to allow possible overload on account of loss of one of the parallel transformers.
4.2
Overload relay shall be set at 110% of rated current with delay of 5 seconds. This shall be connected to give only alarm and not for tripping.
Section 5
REACTOR PROTECTION 1.0
GENERAL
Shunt Reactors are used in EHV systems to limit the overvoltages due to capacitive VAR Generation in Long Transmission Lines. The shunt reactors are normally connected (a) Through isolators to a line (b) Through circuit breakers to a busbar (c) Through circuit breakers to the tertiary of a Interconnecting transformer. Faults occur in shunt reactors due to insulation breakdown, ageing of insulation, overheating due to overexcitation, oil contamination and leakage. To give an early warning and to minimize the damage in case of a fault it is necessary to equip it with monitors and protective relays. Recommendations for provision of protection and monitoring equipment for Reactors are as follows: (a) (b) (c) (d)
2.0
Reactor differentialProtection Reactor REF Protection Reactor-backup protection (Impedance type or definite time o/c & E/F) Protections and monitors built into reactor (buchholz, winding temperature, oil temperature,. pressure relief, oil level, Fire protection) REQUIREMENTS
2.1. Differentia1 Protection (i) Shall be triple pole type (ii) Have an operating current sensitivity of atleast 10% of nominal current. (iii) Be tuned to system frequency (iv) Have operating time not greater than 30 ms at 5 times of setting (v) Have suitable non-linear resistors to limit peak voltage during in-zone faults in case of high impedance type (vi) Shall be high or low impedance type. 2.2
Restricted earthfauIt protection
(i) Shall be 'single pole (ii) Have an operating current sensitively of atleast 10% of nominal current (iii) Be tuned to system frequency
(iv) Have suitabhnon-linear resistors to limit peak voltage during in-zone faults (v) Shall be high or low impedance type
2.3 Backup protection ReIay Either (i) Shall be triple pole type (ii) Shall be single step polarised 'mho' or impedance distance relay suitable for measuring
phase to ground and phase to phase faults.
(iii) Shall grounds a characteristic angle between 60-80 degrees
(iv) Shall have an adjustable definite time delay relay with setting range of 0.2. to 2.0 Sec. (v) Shall have a suitable range for covering 60% of reactor impedance (i) Shall be a single stage definite time 3 pole, overcurrent relay with adjustable current and
time. (ii) Shall be connected for 2 O/C and 1 E/F connection and shall be non-directional with high reset ratio and low transient overreach.
3.0
SPECIAL COMMENTS
3.1
No duplication of reactor protections needs to be done but the protections and monitors shall be divided in two group viz. Gr. A and Group B.
Given below is one possible way of grouping these protections
Group A Reactor differential relay Reactor back up relay Oil temperature trip Pressure relief trip
Group B Buchholz trip Reactor R. E/F relay Winding temperature trip Oil level high/low trip Fire protection trip
Gr. A and Gr. B. protection shall be connected to separate DC Source/separately fused supplies and DC sources shall be supervised. Both Gr, A and Gr. B protections shall give out trip impulses to main breaker and also block auto reclosing where they are directly connected to the line they should also trip remote end CB.
3.2
It may be noted that the connection of Restricted Earth Fault protection on the neutral side shall be from residually connected bushing CTs (in case of bus reactor) or from the ground side CT in the neutral grounding reactor (for line shunt reactor). The latter is to ensure that the protection covers the neutral earthing reactor as well in the protected zone.
3.3
The impedance or overcurrent backup protection may not be able to detect inter-turn fault in the reactor, for which the buchholz may be the only answer, unless the number of turns involved is very high. Manufacturers of reactor and relays may be consulted in this regard.
4.0
SETTING CRITERIA
The magnitude and nature of the switching-in currents should be considered when determining settings of reactor protections. 4.1
Typical settings for o/c relays are:
Current Setting - 1.3 x Rated current 4.2
Time setting - 1 sec.
Typical setting for impedance type of relays are
Reach - 60% of Reactor Impedance
-
Time setting - 1 sec.
Section 6
BUS BAR PROTECTION 1.0
GENERAL
Bus bar protection is required to be provided for high speed sensitive clearance of bus bar faults by tripping all the circuit breakers connected to faulty bus. Recommendations for providing bus bar protection at different voltage levels are as follows:(i) Bus bar protection must be provided in all new 400 kV and 220 kV substations as well
as generating station switchyards. (ii) For existing substations, provision of bus bar protection is considered a must at 400 KV
level and at 220 KV level it is essential at substations having multiple feed. In case of radially fed 220 KV substations, having more than one bus it is desirable to have bus bar protection but is not a must.
2.0
REQUIREMENTS
Bus bar protection shall have following features. (i) It shall be of 3 phase type and operate selectively for each bus bar section. (ii) It shall operate on differential principle and provide independent zones of protection for
each bus. (iii) It shall provide zone indication.
(iv) It shall be stable for through faulf conditions upto maximum 40 kA fault level. (4 For applications where bus differential protection sensitivity has to be set below load current, as may be a case with use of concrete structures, it is recommended that a separate check zone is provided otherwise provision of separate check zone is not essential. Check zone, if provided, shall be of high impedance type. It shall incorporate continuous supervision for C,T. secondaries against any possible open circuits. In case of detection of any open circuiting of C.T. secondaries, after a time delay, the affected zone of protection shall be rendered inoperative and an alarm will be initiated. (vii) It shall include D.C. supply supervision (viii) Include adequate number of high speed tripping relays. (ix) Whenever C.T. switching is involved the scheme shall include necessary C.T. switching relays and have provision for C.T. switching incomplete alarm. It shall include IN/OUT switching facility for each zone.
3.0
SPECIAL COMMENTS
3.1
The D.C. supply for bus bar protection shall be from an independent feeder.
3.2
Faults lying between C.B and C.T. shall be cleared from one side by opening of C.B on busbar protection operation. However clearing of fault from other side shall be through breaker failure protectionhack up protection.
3.3
3 Phase trip relays shall be provided for each circuit breaker which shall also initiate B.F.P. of concerned breaker.
3.4
Length of secondary leads should be kept as minimum as possible. Where lead runs ar excessive, an increase in wire size or use of parallel conductors are means to reduc lead resistance.
3.5
In case of existing substations where current transformers are of different ratios, biase type differential protection is recommended for use.
4.0
SETTING CRITERIA
4.1
C.T wire supervision relays should be set with a sensitivity such that they can detect C.? secondary open circuit even in case of least loaded feeder.
4.2
Bus bar differential protection should have overall sensitivity above heaviest loaded feede current unless a separate check zone has been provided. In cases where fault current are expected to be low as brought out in 2 (v) above, the protection should be sensitivi enough to take care of such expected low fault current.
4.3
In case of voltage operated high impedance type protection, the voltage setting shoulc be above expected voltage developed across the relay during maximum through faul current condition. In case of current operated relays for stability under through faul condition, external resistance is to be set such that voltage developed across relay an( resistance combination is below the voltage required for forcing required relay operating current.
Section 7
LOCAL BREAKER BACK-UP PROTECTION (BREAKER FAILURE PROTECTION) 1.0
GENERAL
In the event of any circuit breaker failing to trip on receipt of trip command from protection relays, all circuit breakers connected to the bus section to which the faulty circuit breaker is connected are required to be tripped with minimum possible delay through LBB protection. This protection also provides coverage for faults between C.B and C.T. which are not cleared by other protections. Recommendations for providing LBB protection at different voltage levels are as follows: (i) In all new 400 kV and 220 kV substations as well as generating stations switchyards, it
must be provided for each circuit breaker. (ii) For existing switchyards, it is considered a must at 400 kV level and also at 220 kV switchyards having multiple feed. In case of radjally fed 220 kV substations, provision of LBB protection is desirable but not essential.
2.0
REQUIREMENTS
LBB protection shall have following features: (i) Have short operation and drop off times. (ii) Have three phase current elements with facility for phase wise initiation. (iii) Have current setting range such that these can be set at minimum 200 mA for line and
5 0 mA for generators (for 1A C.T. Secondary). (iv) Have one common associated timer with adjustable setting.
3.0
SPECIAL COMMENTS
(i) The relay is separate for each breaker and is to be connected in the secondary circuit of
(ii)
(iii)
(iv) (v)
the CTs associated with that particular breaker. This CT secondary may be a separate core, if available. Otherwise it shall be clubbed with Main-I or Main-I1 protection core. For line breakers, direct tripping of remote end breaker(s)should be arranged on operation of LBB protection. For transformer breakers, direct tripping of breaker(s) on the other side of the transformer should be arranged on operation of LBB protection. For lines employing single phase auto-reclosing, the LBB relays should be started on a single phase basis from the trip relays. This is to avoid load currents in the healthy phases, after single phase tripping, leading to unwanted operation of the breaker failure protection, since the current setting is normally lower than the load current. It is considered a good practice to have DC circuits of Gr.A and Gr.B protections and LBB relay independent. A separately fused supply should be taken for LBB relay in this case. LBB cannot operate without proper initiation. It is good practice to provide redundant trip output and breaker fail input where other forms of redundancy does not exist. One way of doing this is by providing separate aux. relay in parallel with trip unit and using contacts of these for LBB initiation.
(vi) Separation should be maintained between protective relay and CB trip coil DC circuit so that short circuit or blown fuse in the CB circuit will not prevent the protective relay from energising the LBB scheme. (vii) In addition to other fault sensing relays the LBB relay should be initiated by Busbar protection, since failure of CB to clear a bus fault would result in the loss of entire station if LBB relay is not initiated. (viii) Whenever used in combination with busbar protection scheme, tripping logic of the same shall be used for LBB protection also. (ix) For breaker-fail relaying for low energy faults like buchholz operation, special considerations may have to be given to ensure proper scheme operation by using C.B. contact logic in addition to current detectors.
4.0
SETTING CRITERIA
(i) Current level detectors should be set as sensitive as the main protections. A general
setting of 0.2 A is commonly practiced for lines and transformers. However, in case of existing schemes associated with lines having single phase autoreclosure and where phase wise initiation is not available, it is recommended that 2ph + 1E/F element may be used with phase element set above maximum expected load current while E/F element may be set sensitively. (ii) Current level detector for generators may be set at 50 mA (for 1A C.T. secondaries). (iii) Timer setting should be set considering breaker interrupting time, current detector reset time and a margin. Generally a timer setting of 200 ms has been found to be adequate.
Section 8
DISTURBANCE RECORDING AND FAULT LOCATION EQUIPMENT 1.0
GENERAL
1.1
Disturbance Recorder - Provides better understanding of the behaviour of Power network after a disturbance - Gives useful information to improve existing equipment and in planning/designing new installations
Disturbance recorder shall be microprocessor based and shall be used to record the graphic form of instantaneous values of voltage and current in all three phases, open delta voltage and neutral current, open or closed positions of relay contacts and breaker during the system disturbances. Disturbance recorders are recommended for all the 400 kV lines. At 220 kv level also they are recommended for all interconnecting lines. In other cases utilities may decide depending on their need. It is also recommended that all the disturbance recorders in the station are synchronised with GPS
1.2
Fault Locator
Distance to fault locator is recommended to be provided as a standard for all 400 kV and 220 kV lines on both ends. However for short lines of length upto 2.0 kms, fault locator can be provided at one end only.
1.3
Event Logger
The Event logger is used to record the state of switchyard equipment and relays and occurrences of alarms. The equipment also records events recorded by disturbance recorder, as also changes in digital inputs, i.e operation and resetting of relay contact and switching of primary plant within the substation. In case all required events can be accommodated in disturbance recorder no separate event logging equipment is recommended.
2.0
.
REQUIREMENTS
2 . 1 Disturbance Recorder Recording capacity - Record minimum eight analogue inputs (8)and minimum 16 binary signals per bay or circuit. Memory capacity - Minimum 5 sec of total recording time Recording times - Minimum prefault recording time of 100 ms
-
Minimum Post fault recording time of 1 0 0 0 ms
Trigger -
Any of digital signals can be programmed to act as trigger Analogue channels should have programmable threshold levels for triggers. Selectior of over or under levels should be possible.
Time Tagging - Has built in real time clock and calendar to time tag recorded disturbances. Drift of thc in built clock shall not be more then 0 . 5 sec per day. Sampling Rate - 1 KHz Recording band width ,
- 5-250 Hz
Voltage Channel - Dynamic range 0.01-2 x Nominal Voltage - Resolution 0.1% Current Channel - Dynamic range with full DC offset - .01-60 x Nominal Current Printer -- Printer shall be suitable for taking print on plane paper
2.2
Fault Locator
- Be on line type - Have built in display unit - The display shall be directly in percent of line length or kilometers without requiring an\ further calculation - Be suitable for applicable breaker operating time - Have an accuracy of 3% or better - Shall take care of (a) presence of remote end infeed (b) predominant DC. component in fault current (c) high fault arc resistance (d) Severe CVT transient -
Shall have mutual zero sequence compensation if fault locator is to be used on double circuit line.
3.0
SPECIAL COMMENTS
3.1
Start function to disturbance recorder is to be provided by change in state of one or more of the events connected and/or by any external triggering s o that recording of events during a fault or system disturbance can be obtained. List of typical signals recommended to be recorded is given below:
(i) Recommended Analogue Signals From CT
From Line VT
From Aux. VT vo
(ii) Recommended Digital Signals(Typica1)
- Main 1 Carrier receive - Main 1 Trip -
-.
-
Line O N Stage I/Stage I1 Reactor Fault Trip Stub Protection Optd. Main I1 Trip Main I1 Carrier Receive ~ i r e cTrip t CH A/B CB I Status A PH CB I Status B PH CB I Status C PH CB I1 Status A PH CB I1 Status B PH CB I1 Status C PH Bus bar trip MainI'Tie CB LBB Optd.
Note : These may need modification depending upon Protections chosen and the contact availability for certain functions.
3.2
If disturbance recorder function or fault locator functions are available as integral part of any of main protection, then separate stand alone units for this functions are not required. However both DR and Fault locator function, preferably should not be in the same unit.
3.3
In case of DR being part of main protection, it should be possible to connect external binary inputs.
3.4
Stand alone DR which can cater to more than one bay/circuit can also be used. However this should have minimum 8 analogue and 16 binary inputs per bay/circuit.
Section 9
GUIDELINES FOR PROTECTION SYSTEM ENGINEERING 1.0
GENERAL
Some broad guidelines for Engineering of Protection System in addition to engineering recommendations made in various sections, are given below and could be refined if felt necessary by the Utility according to its specific needs and practices.
2.1
Gr. A and Gr. B Protection
Wherever two sets of DC sources are available, to obtain redundancy and to be able to take protection out for maintenance, while equipment is in service, the relays are electrically and physically segregated into two groups. Grouping is done to the extent possible in such a way that each group can independently carry out protective functions with near equal redundancy. Interconnection between these two groups shall not generally be attempted. However if found absolutely necessary such interconnection shall be kept to the bare minimum. Even in cases when only one set of battery source is available segeration of protections and trip circuits in two groups may be considered by giving DC supplies through separate fuses.
2.2
Trip Unit
In case of segregation being made as indicated above, scheme associated with each circuit breaker is provided with two sets of trip units, one in Gr A and one in Gr.B. Each set consists of one unit for 1/3 phase tripping and another for 3 phase tripping only. 1/3 phase tripping unit and 3 phase tripping units are initiated by functions as described below. However, in case the protection relay itself is having sufficient number of trip duty contacts, then separate trip units will not be necessary. 2.2.1 1 ph & 3 ph trip (Protections which,start auto recloser) - Main I Line Protection
- Main I1 Line Protection These units shall be applicable for line circuits only and shall be with self reset type contacts 2.2.2 3 ph trip (Protections which block auto reclosure) -
Direct trip receive Line reactor protection Bus bar protection Transformer protection Overvoltage protection Back up protections
These units shall be hand reset type 2.2.3 Direct trip of remote end breaker In line with the present 400 KV practice it is recommended that direct trip signal is sent to remote end under following conditions.
(i) When LBB relay operates (ii) Reactor protection and O/V protection
2.3
DC Distribution
Since the availability of even the best engineered protection depends upon the integrity of the DC auxiliary supply, considerable care has to be given to the design of a system which will retain the reliability of the protection system as a whole, under all conditions. Secondly from an operational point of view, it is essential that it is possible to work on any part of the protection system with full security, while not disturbing the rest of the protective system. Arising out of these considerations, following guidelines for designing a suitable DC distribution system have been set forth. 2.3.1 For 400 kV stations there shall be two separate battery systems available for protection, control and tripping/closing operations. For 220 kV stations where only one set of battery source is available segregation of protection and trip circuits in two groups may be considered by giving DC supplies through separate fuses. 2.3.2 Distribution of DC supply shall be done bay wise to feed the following (a) (b) (c) (d) (e)
Protection CB functions Isolator/earth switch functions Annunciation/Indications Monitoring functions(DisturbanceRecorder, Fault Locator, Event Logger etc.) when these are not integral part of protection
2.3.3 (a) Protection Function For each group of protection(ie Group A and Group B relays) separate DC sources are recommended. (b) CB Functions Trip coil 1&2 shall be fed from separate sources. Closing coil can be from either of these two sources. (c) Isolator/Earth switch These associated with any one circuit shall be fed from one of the two DC sources. In the case of a 1& 1/2 CB arrangement, the Isolator/Earth switch associated with the tie CB can be fed from either Source 1 or 2. (d) Annunciation & Indication For each bay, these functions can be fed from either one of the 2 sources. Each function shall be fed however through separate feeds. (e) Monitoring Functions These shall be grouped in 3 groups (i) (ii)(iii)
Disturbance Recorders Fault Locators Event Loggers All the three groups shall be fed through separate teeds from either of the two sources. This is to enable the full availability of these equipment irrespective of that of the protections.
2.3.4 General Notes: 1. A s to how the separate D.C. feeds are to be taken from the sources, there are two alternatives. (a) Through separate feeds from the board to each circuit panel (b) Through a limited no of feeds to a separate panel of the relay or control board (Exclusively meant for marshalling the DC circuits for the various relay panels). The choice between (a) or (b) is left to the utilities as per their individual practices. 2. Sub-fusing of the DC circuits shall be done with care since blowing of the fuse will have to be monitored. Also such sub-fusing shall be kept to the minimum and can be augmented with isolating links as required. 3. Selection of sources in the event of one supply to a function failing is to be done with care, because if the fault lies downstream one may lose both supplies. 4. As a rule every DC supply going through fuse should be supervised with a no-volt relay. For trip circuits where separate trip circuit supervision relays are provided it is not necessary to provide separate DC supervision relays. 5. MCBs of adequate break-up capacity can also be used instead of fuses.
2.4
Cabling It is recommended that: (i) Separate cables are used for AC & DC circuit
(ii) Separate cables are used for DC 1 & DC 2 circuits (iii) For different cores of CT & CVT separate cables shall be used.
Section 10
LOCATION OF CTS AND VTS IN SUB-STATIONS 1.0
GENERAL
Instrument transformers (CTs and VTs) are used to obtain measured quantities of current and voltage in appropriate form for use in control, protection and measuring equipment such as Energy meters, indicating instruments, protective relays, fault locators, fault recorders, synchronizers. These are installed in different bays such as line, transformer, bus coupler bays and also at the busbar.
2.0
LOCATION OF CTS AND VTS IN DIFFERENT SUB-STATION ARRANGEMENTS
2.1
Given below are some examples of different bus configurations showing suitable location of CTs and VTs.
i
WWW
Bus Sectionolizer
Fig. 1 : Double busbar arrangement
3-Phase
T v r I www
1 www
Fig. 2 : Double Main with Transfer bus arrangement
1 -
3-Phase
Fig. 3 : Double breaker arrangement
3~1
3-Phase,
/ba<-/
7-/ o - m - . . / \
c;c--
h
-Fig. 4 : One and a half breaker arrangement
Fig. 5 : One and a half breaker arrangement (alternative arrangement with 5 CTs)
Fig. 7 : Typical Protective Relaying Scheme for one and a half breaker busbar arrangement
2.2
Current Transformers
Some explanatory notes and comments with reference to above are given below regarding location of CTs. 2.2.1 Double Bus Arrangement (Ref. Fig.4) The CTs shall be placed near the circuit breakers (CBs) and on the line side. The detection zones of line relays and busbar relays start at the CTs. It is advantageous if these two points are close to each other. In the improbable case of a fault between the CT and CB the busbar protection will detect and clear the fault. 2.2.2 Double Main and Transfer Bus Arrangement (Ref:Fig.5) It is advantageous to locate the CTs on the line side of the disconnectors for Line and Transformer bays. In this way the protective relay connected to the CT will remain connected to the line or Transformer when it is switched over to the transfer busbar.
A separate CT is required to be provided in the Transfer bus coupler bay to obtain selective tripping for faults on Transfer bus. 2.2.3 Bus Coupler and Bus Sectionalizer.Bays (Ref. Fig.4 and Fig.5) A set of CT is necessary to enable different busbar protection zones to be formed. The protection can be arranged to give complete fault clearing with a short time-delay (L.B.B. time) for faults between CB and CT. Sometimes CTs on the two sides of CB are employed by some utilities but are usually not considered necessary. Therefore, only one set of CTs is recommended. 2.2.4 Double Breaker Station (Ref: Fig. 1) It is usual to locate the CTs on the line side after the CBs. The two CTs shall be identical. To get the line current the secondary currents of the two CTs are summated. 2.2.5 One and a Half Breaker Station (Ref. Fig. 2 and Fig.3) Like the double breaker station, the CTs are located close to the CBs. At the central CB (Tie CB) two CT sets are shown. This arrangement utilizes 4 CTs however it is also possible to use a single set of C.T. with the tie CB thus reducing number of CTs to 3 per diameter. The centre CT in this case will have to be a non-standard one and therefore 3 CT arrangement is not recommended at present but can be reviewed at a later date. Fig.3 shows alternative way of locating the CTs. This arrangement requires 5 CTs. The advantages with this arrangement are: - Paralleling of two CTs to the main line protection is not required. This gives better transient response. - Separate stub protection can be connected
Presently there are many installations with 4 CT arrangement and performance has been satisfactory. Therefore, it is recommended that 4 CT arrangement is continued to be adopted.
2.3
Voltage Transformers
2.3.1 Line CVTs CVTs are used for metering, protection and synchronization. Located at the line entry they
also enable indication of voltage on a line energized from the opposite end. CVTs can also be used as coupling capacitors for power line carrier (PLC). They are then to be located at the line side of the line traps and line earthing switches, as shown in Fig. 5. For 400 kV level it is recommended that each line bay is provided with CVTs all the three phases. Even for 220 kV substations it is preferable to provide three phase CVTs in each phase for each line bay. However, depending on utility practice CVTs in one phase may also be provided in which case protections will have to be connected to Bus VTs. 2.3.2 Bus CVTs Three phase VTs/CVTs on the busbars provide input for directional relays and reference voltage for synchronization. These VTs will have to be selected by using voltage selection scheme.
2.4
CT/VT Earthing
CT/VT secondary neutrals should be earthed at one point only. VT secondary neutral earthing is done at equipment itself. However, it is preferable to earth the CT secondary neutral in the control/protection cubicle in order to provide maximum security to the operating personnel.
2.5
CT Polarity
As a practice the P1 terminal of the CT shall be towards the bus and P2 away from the bus.
3.0
EXAMPLES OF CT, VT LOCATION
Examples of a double main and Transfer bus configuration showing line, Transformer, Main Bus coupler and Transfer bus coupler bays and another of one and half bus configuration for a Line with reactor and Transformer diameter are shown in figs. 6 & 7 to illustrate location of CTs and CVTs and utilisation of various cores based on the above recommendations.
Section 1 1
COMMISSIONING TESTS AND MAINTENANCE RECOMMENDATIONS 1.0
COMMISSIONING TESTS
1.1
Commissioning tests apart from covering protection gear, control and alarm circuits, also cover much of the primary plant with which such equipment is associated. These tests are done to ensure following:
(a) to ensure that the equipment has not been damaged in transit and that it can be safely and confidently connected to the system and taken into service. (b) ensure that equipment has been installed correctly. (c) prove the characteristics of the protection which are based on calculation (d) obtain a set of test figures for future reference if and when necessary.
1.2
Planning the Programme
First of all a list should be prepared itemising all the tests that are necessary to do for e.g. insulation resistance, secondary injection, primary injection, stability, control, indications, interlocks, alarms, tripping, end-to-end tests, auto-reclose, synchronising, on-load test etc. It may be helpful to have sheets available headed, for e.g., 'Isolators' or 'Circuit Breaker' or 'Transformers', and on these sheets have a list of items that have to be inspected or tests that are to be conducted. The tests should be programmed to take place in a logical and efficient order so that nothing already tested is disturbed during subsequent tests.
1.3
Inspection Prior to Testing
The Inspection tests should be as follows: (a) Checking for tightness of all connections in relay panels, control panels, marshalling kiosks, CT and P.T. terminal boxes and earthing connections etc. (b) Cartridge-type fuses should be inspected to ensure that the correct rating is used for the circuit. (c) Ensure that all the secondary equipment in outdoor substations is weatherproof, but there is provision for ventilation and heating (if required) to prevent condensation. (d) Before energising new secondary wiring should be checked as far as reasonably practicable that there are no bare, dangling, uncompleted leads anywhere on site which will be made alive at the same time as the equipment under test.
1.4
The Tests
Before beginning testing it should be confirmed that the particular part of the circuit under test is complete and that no one is likely to interfere with it. The tests to be done should be listed in chronological order together with any special precautions to be taken. The tests come under four broad headings. .(a) Tests before making secondary equipment alive. (b) Tests before making primary equipment alive.
(c) Synchronising tests where the new equipment is alive, but not yet in parallel with existing equipment. (d) On-load tests. Schedules for recording test results should be compiled in advance, when preparations can be made at a time free from testing stress.
1.5
Listed below are some of the more usual tests, with comments:
1.5.1 Insulation Resistance Tests These tests should be done with 500 V D.C. Megger. Each circuit should be tested in turn whilst all the others are earthed to ensure that there is no connection between two supposedly separate circuits. It is difficult to qualify in general, what value of insulation resistance should be obtained. On panel and other indoor wiring one would expect a figure in excess of 100 M.ohms. On outdoor wiring in a medium-sized substation, with wiring loops into many auxiliary switches and junction boxes, 1 M.ohm would not be unreasonable. The weather can also affect the results. A warm humid day tends to lower the value where as a cold dry day gives high values. It is recommended that items like space heater and illuminating lamps are discounted during meggering. 1.5.2 Secondary Injection Tests These tests consist of AC injection into the relay to ensure that its calibration is correct. In general, high-accuracy secondary injection tests on site are not necessary. What is needed is a set of figures, reproducible later from time to time on routine tests, which bear a known relationship to accurate figure previously obtained. Guidance should be taken from the manufacturer recommendation in this regard. 1.5.3 Polarity Tests Much of the preliminary checking can be done with the aid of a 1.5 V battery and a centre zero voltmeter. All the CTs in a group should be checked in turn to prove that they are connected to the protection with correct polarity. 1.5.4 Primary Injection Tests I
Primary Injection Tests are required to prove that CTs are correctly connected to relays. These tests should include a check of the polarity of the three CTs in a group, and often the comparison of the group with another.
I
II 1
1.5.5 Tripping and Closing Tests Trip circuit supervision relays should be proved and it should be checked that the alarm supply is not fed from the same supply as being supervised, otherwise no alarm could be given if the supervised supply failed. Trip-healthy lamps and resistors should be proved. 1.5.6 Indications and Alarms
I
These tests should involve checking each indication and alarm function correctly. 1.5.7 Tests on Commissioning of Carrier Protection Apart from the tests recommended on the carrier equipments itself, check should be made to
ensure correct connection and implementation of logic between relay panels and carrier equipment. 1.5.8 Phasing Tests It is necessary to prove correct phasing before a new piece of equipment can be put in parallel with existing equipment. When a circuit is being paralleled for the first time, the VT associated with that circuit must be energised from a known source and outputs should be compared with outputs of already proven VTs to prove that the VT connections are correct.
1.5.9 On-load Tests (i) Standing Current in Relays
Having got the new equipment on load it is essential to do on load tests. It should be checked that there is negligible spill current in any residually connected relays and in any protection working on the differential principle. Appearance of current in differential circuit should also be chekced either by reversing or shorting and disconnecting one of the C.T. connections. Before measuring current in the CT circuits of differential relays care should be taken to remove the appropriate trip link. (ii) Directional Relays On load tests are also required to prove the polarity of the VT connection with respect to CT connection. This will ensure that the schemes/relays are looking in proper direction. The manufacturers instructions are to be followed to conduct this test. The types of relays that need to be tested this way are directional relays and distance relays/schemes.
2.0
ROUTINE MAINTENANCE TESTS
Protective gear may stand quiescent for months and yet be required to operate with precision if fault occurs on its associated primary equipment. Routine maintenance tests on protective gear are done to ensure that the equipment remains available to perform in a fully discriminative manner the duty required of it. There are two major factors while considering the maintenance activities of any equipment. They are:(i) the human element (ii) the equipment itself with its other associated paraphernalia
2.1
The following major points are to be considered in the human element i.e. the maintenance personnel.
1. It has to be recognised that handling protective relays is a specialised job. Therefore, it is-necessary to depute suitable technical personnel who will be retained in this field for long periods in order to gain maximum benefit from their experience. 2. The personnel involved should be technically sound and be aware of modern practices. Further, electronics and computers are invading protection relay field and the present day relay maintenance personnel need to be well versed in this discipline - a need that did not exist a few years ago.
They should be fully familiar with the equipments and systems they are called upon to handle. For this purpose periodic training in the manufacturers works become essential. They should be able to attend to most of the common failures of equipments without waiting for instructions from the manufacturers. 5. The personnel involved should be innovative to develop test procedures which may not be mentioned by the manufacturers. This may be necessitated by available site conditions and considerations of operational experience.
2.2
Maintenance Tests/Checks
2.2.1 Secondary injection tests should be carried out to check the relay performance and if possible the relay should be allowed to trip the circuit breakers. The necessity for proper recording of result and logging of problems cannot be over-emphasised. 2.2.2 Check for tightness and cleanliness of all fasteners and connections should be done. 2.2.3 Check for alarm and indication circuits should be done. This can be combined with secondary injection testing. 2.2.4 Check all the concerned logics and interlocks. 2.2.5 Insulation tests of relay wiring to earth and between circuits should be aimed out with a 500 Volt tester. After maintenance when the equipment is put into service, it is essential to check that the relays are extended with the proper voltages and currents. This applies also to any auxiliary voltage.
2.3
Frequency of routine Maintenance
When determining a programme, the frequency of maintenance inspections and tests will depend on the fault history and fault liability of the equipment. There is no point in overtesting an equipment, the programme should be planned so that fault in the equipment are anticipated, not precipitated. The frequency of test will, however, vary widely with the type of equipment. Certain items are continuously monitored, some are checked several times a day, whilst others may be tested weekly, monthly, yearly or even every two years. Recommended frequency of tests and types of equipment are: (i) Daily
- Relay flags inspected on every shift - Counter readings on carrier channels (ii) Yearly
- Check of tripping criteria of protection - Injection of gas actuated relays with air or oil - Secondary injection tests on all relays - Insulation resistance tests
Section 12
TEST EQUIPMENT 1.0
GENERAL
In order to ensure healthiness and maximum availability of protective relays it is necessary to carry out periodic testing. Presently, manual as well as microprocessor based automatic testing kits are available. While the manual kits have been in use by utility engineers in past, automatic test kits are relatively recent introduction. Apart from automatic testing capability, these kits are also capable of replaying the fault recordings captured by disturbance recorders as well as transient simulation done using Electro Magnetic Transient Programme (EMTP). Also, it is possible to do comprehensive end to end testing of line protections including protection signalling with use of these automatic kits in conjunction with Time synchronising equipment. Utilities may decide on requirement of manual or automatic kits depending on size of their network and testing practices. 2.0
REQUIREMENTS
2.1 Manual Test Kits (a) Portable over current relays testing equipment. The input rating shall be between 200250 V. 5 0 Hz, AC supply and the current output range shall be 0.05-200 amps. with negligible harmonic distortion of less than 1%. A time interval meter shall be fitted to read and display 0-10 seconds with an accuracy of + 10 milliseconds. (b) Portable test equipment for testing distance relays comprising supply unit, control unit and fault impedance unit. Suitable for Ac voltage from 380-440 V, three phase, 3 wire system 2 0 Ampere (short time rated) with built in safety devices. 2.2
Automatic Test Kits
It shall be suitable to test all types of distance, overcurrent, ground relays, synchronising, transformer, reactor and busbar protection relays of major manufacturers in automatic as well as manual mode. It shall include all the accessories required for making the complete test set up. It shall have three phase current output range 0-30 amps. (rms) and three phase voltage range 0- 11 0 voltage (PH-G). It shall work on single phase 240 V, 5 0 Hz
+ 10% supply
Shall include necessary software and hardware (a) To accept fault recordings available from fault data recorder/numerical relay/EMTP simulation and replay these on the relay under test. (b) To draw the relay characteristics The accuracy of relay test kit shall be as follows: 1% for voltage aid current output and resolution of time measurement of 1ms or better.
REFERENCE STANDARDS 01
IEC 255140
02
IEC 255-3
Electrical Relays - Single input energising quantity measuring relays with dependent or independent time
03
IEC 255-5
Electrical Relays - Insulation tests for electrical relays
04
IEC 255-6
Electrical Relays - Measuring relays and protection equipments
05
IEC 255-7
Electrical Relays - Test and measurement procedures for electro-mechanical all-or-nothing relays
(3
IEC 255-8
Electrical Relays - Thermal electrical relays
07
IEC 255-10
Electrical Relays - Application of the IEC quality assessment system for electronic components to all-or-nothing relays
(33
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 two input energising quantities
10
IEC 25513
Electrical Relays - Biased (%) differential relays
ll
E C 25516
Electrical Relays - Impedance measuring relays
12
IEC 255-21-1
Electrical Relays - Vibration, shock, bump and seismic tests on measuring relays and protection equipment (Vibrationtests)
13
IEC 25921-2
Electrical Relays - Vibration, Shock bump and seismic tests on measuring relays and protection equipment (Shock & Bump tests)
14
IEC 255-21-3
Electrical Relays - Vibration, Shock, bump and seismic tests on measuring relays and protection equipment (Seismictests)
15
IEC 25522-1
Electrical Relays - Electrical disturbance tests for measuring relays and protection equipment (1MHz burst disturbance tests)
16
IEC 25522-2
Electrical Relays - Electrical disturbance tests for measuring relays and protection equipment (Electrostaticdischarge tests)
17
IEC 25522-3
Electrical Relays - Electrical disturbance test for measuring relays and protection equipment (Radiated electromagnetic field disturbance tests)
18
IEC 255224
Electrical Relays - Electrical disturbance tests for measuring relays and protection equipment (Fast transient disturbance tests)
19
IEC
25523
Electrical Relays-All-or-nothingelectrical relays
Electrical relays - contract performance
