Operators Training Material - Protection Basics (Part-1) PDF

Operators Training Material Protection Basics (Part-1) Power Grid Corporation of India Limited  Table of Contents Sr.No Content Pg. No 1.0 INTRODUCTION 1 2.0 PROT...

Operators Training Material Protection Basics (Part-1) Power Grid Corporation of India Limited  Table of Contents Sr.No Content Pg. No 1.0 INTRODUCTION 1 2.0 PROTECTION SYSTEM – OBJECTIVE 1 3.0 PROTECTION SYSTEM – CHARACTERISTICS 2 4.0 ZONES OF PROTECTION 3 5.0 DISTANCE PROTECTION 5 6.0 DISTANCE PROTECTION SCHEMES 10 7.0 AUTO RECLOSING SCHEME 17 8.0 OVER VOLTAGE PROTECTION 21 9.0 OVERCURRENT AND EARTH FAULT PROTECTION 22 10.0 GENERAL PROTECTION SCHEME OF TRNASMISSION LINES 25 1. INTRODUCTION The purpose of an electrical power system is to generate and supply electrical energy to consumers. The system should be designed to deliver this energy both reliably and economically. Frequent or prolonged power outages result in severe disruption to the normal routine of modern society, which is demanding ever-increasing reliability and security of supply. As the requirements of reliability and economy are largely opposed, power system design is inevitably a compromise. Many items of equipment are very expensive, and so the complete power system represents a very large capital investment. To maximise the return on this outlay, the system must be utilised as much as possible within the applicable constraints of security and reliability of supply. More fundamental, however, is that the power system should operate in a safe manner at all times. No matter how well designed, faults will always occur on a power system, and these faults may represent a risk to life and/or property. heavy fault currents can cause damage to plant if they continue for more than a few seconds. The provision of adequate protection to detect and disconnect elements of the power system in the event of fault is therefore an integral part of power system design. Only by doing this can the objectives of the power system be met and the investment protected. This shows the importance of protection systems within the electrical power system and of the responsibility vested in the Protection Engineer. In order to fulfil the requirements of protection with the optimum speed for the many different configurations, operating conditions and construction features of power systems, it has been necessary to develop many types of relay that respond to various functions of the power system quantities. 2. PROTECTION SYSTEM – OBJECTIVES The objectives of electrical system protection are to a. Limit the extent and duration of service interruption whenever equipment failure, human error, or adverse natural events occur on any portion of the system b. Minimize damage to the system components involved in the failure 1|Page  The circumstances causing system malfunction are usually unpredictable; however, sound design and preventive maintenance can reduce the likelihood of system problems. The electrical system, therefore, should be designed and maintained to protect itself automatically. 3. PROTECTION SYSTEM – CHARACTERISTICS The main characteristics of the protection system are as follows: Reliability Selectivity Speed Sensitivity Stability 3.1. Reliability The design of a protection scheme is of paramount importance. This is to ensure that the system will operate under all required conditions, and refrain from operating when so required. This includes being restrained from operating for faults external to the zone being protected, where necessary. Due consideration must be given to the nature, frequency and duration of faults likely to be experienced, all relevant parameters of the power system and the type of protection equipment used. Of course, the design of the protection equipment used in the scheme is just as important. No amount of effort at this stage can make up for the use of badly designed protection equipment. 3.2. Selectivity When a fault occurs, the protection scheme is required to trip only those circuit breakers whose operation is required to isolate the fault. This property of selective tripping is also called 'discrimination' and is achieved by two general methods. 3.3. Speed The function of protection systems is to isolate faults on the power system as fast as possible. One of the main objectives of protection system is to safeguard continuity of supply by removing each disturbance before it leads to widespread loss of synchronism and consequent collapse of the power system. 2|Page  As the loading on a power system increases, the phase shift between voltages at different busbars on the system also increases, and therefore so does the probability that synchronism will be lost when the system is disturbed by a fault. The shorter the time a fault is allowed to remain in the system, the greater can be the loading of the system. It will be noted that phase faults have a more marked effect on the stability of the system than a simple earth fault and therefore require faster clearance. System stability is not, however, the only consideration. Rapid operation of protection ensures minimisation of the equipment damage caused by the fault. The damaging energy liberated during a fault is proportional to the time that the fault is present, thus it is important that the protection operate as quickly as possible. 3.4. Sensitivity Sensitivity is a term frequently used when referring to the minimum operating level (current, voltage, power etc.) of relays or complete protection schemes. Relays or protection schemes are said to be sensitive if their primary operating parameters are low. 3.5. Stability The term ‘stability’ is usually associated with unit protection schemes and refers to the ability of the protection system to remain unaffected by conditions external to the protected zone, for example through-load current and faults external to the protected zone. 4. ZONES OF PROTECTION To limit the extent of the power system that is disconnected when a fault occurs, protection is arranged in zones. The principle is shown in Figure 4.1. Ideally, the zones of protection should overlap, so that no part of the power system is left unprotected. This is shown in Figure 4.2 (a), the circuit breaker being included in both zones. 3|Page  Fig 4.1 - Division of power systems into protection zones For practical physical and economic reasons, this ideal is not always achieved, accommodation for current transformers being in some cases available only on one side of the circuit breakers, as shown in Figure 4.2(b). In this example, the section between the current transformers and the circuit breaker A is not completely protected against faults. A fault at F would cause the busbar protection to operate and open the circuit breaker but the fault may continue to be fed through the feeder. If the feeder protection is of the type that responds only to faults within its own zone, it would not operate, since the fault is outside its zone. This problem is dealt with by inter-tripping or some form of zone extension, to ensure that the remote end of the feeder is also tripped. Fig 4.2 - CT locations 4|Page  The point of connection of the protection with the power system usually defines the zone and corresponds to the location of the current transformers. Unit type protection results in the boundary being a clearly defined closed loop. Figure 4.3 shows a typical arrangement of overlapping zones Fig 4.3 - Overlapping zones of protection systems Alternatively, the zone may be unrestricted; the start will be defined but the extent (or ‘reach’) will depend on measurement of the system quantities and will therefore be subject to variation, owing to changes in system conditions and measurement errors. 5. DISTANCE PROTECTION 5.1. Introduction Distance protection, in its basic form, is a non-unit system of protection offering considerable economic and technical advantages. Unlike phase and neutral overcurrent protection, the key advantage of distance protection is that its fault coverage of the protected circuit is virtually independent of source impedance variations. This is illustrated in Figure 5.1, where it can be seen that overcurrent protection cannot be applied satisfactorily. 5|Page  Fig 5.1 (a): Advantages of distance over overcurrent protection Fig 5.1 (b): Advantages of distance over overcurrent protection Therefore, for relay operation for line faults, Relay current settings 7380A. this is impractical, Overcurrent relay not suitable. Must use distance or Unit Protection. Distance protection is comparatively simple to apply and it can be fast in operation for faults located along most of a protected circuit. It can also provide both primary and remote back-up functions in a single scheme. It can easily be adapted to create a unit protection scheme when applied with a signalling channel. In this form it is eminently suitable for application with high-speed auto- reclosing, for the protection of critical transmission lines. 5.2. Principles of Distance Relays Since the impedance of a transmission line is proportional to its length, for distance measurement it is appropriate to use a relay capable of measuring the impedance of a line up to a predetermined point (the reach point). Such a relay is described as a distance relay and is designed to operate only for faults occurring between the relay location and the selected reach point, thus giving discrimination for faults that may occur in different line sections. 6|Page  The basic principle of distance protection involves the division of the voltage at the relaying point by the measured current. The apparent impedance so calculated is compared with the reach point impedance. If the measured impedance is less than the reach point impedance, it is assumed that a fault exists on the line between the relay and the reach point. UM M IL B UN=0 ZS A Distance ZL ZM Relay ZML=UM/ IL ZML=ZL + ZM >> ZL Fig 5.2 - Operating Principle of Distance Relays 5.3. Distance Zones of Protection Careful selection of the reach settings and tripping times for the various zones of measurement enables correct coordination between distance relays on a power system. Basic distance protection will comprise instantaneous directional Zone 1 protection and one or more time-delayed zones. Typical reach and time settings for a 3-zone distance protection are shown in Figure 5.3 Digital and numerical distance relays may have up to five or six zones, some set to measure in the reverse direction. Typical settings for three forward-looking zones of basic distance protection are given in the following sub-sections. To determine the settings for a particular relay design or for a particular distance tele-protection scheme, involving end-to-end signalling, the relay manufacturer’s instructions should be referred to. Zone 1 Setting 7|Page Electromechanical/static relays usually have a reach setting of up to 80% of the protected line impedance for instantaneous Zone 1 protection. For digital/numerical distance relays, settings of up to 85% may be safe. The resulting 15-20% safety margin ensures that there is no risk of the Zone 1 protection over-reaching the protected line due to errors in the current and voltage transformers, inaccuracies in line impedance data provided for setting purposes and errors of relay setting and measurement. Otherwise, there would be a loss of discrimination with fast operating protection on the following line section. Zone 2 of the distance protection must cover the remaining 15-20% of the line. Zone 2 Setting To ensure full coverage of the line with allowance for the sources of error already listed in the previous section, the reach setting of the Zone 2 protection should be at least 120% of the protected line impedance. In many applications it is common practice to set the Zone 2 reach to be equal to the protected line section +50% of the shortest adjacent line. Where possible, this ensures that the resulting maximum effective Zone 2 reach does not extend beyond the minimum effective Zone 1 reach of the adjacent line protection. This avoids the need to grade the Zone-2 time settings between upstream and downstream relays. In electromechanical and static relays, Zone 2 protection is provided either by separate elements or by extending the reach of the Zone 1 elements after a time delay that is initiated by a fault detector. In most digital and numerical relays, the Zone 2 elements are implemented in software. Zone 2 tripping must be time-delayed to ensure grading with the primary relaying applied to adjacent circuits that fall within the Zone 2 reach. Thus complete coverage of a line section is obtained, with fast clearance of faults in the first 80-85% of the line and somewhat slower clearance of faults in the remaining section of the line. Zone 3 Setting Remote back-up protection for all faults on adjacent lines can be provided by a third zone of protection that is time delayed to discriminate with Zone 2 protection plus circuit breaker trip time for the adjacent line. Zone 3 reach should be set to at least 1.2 times the impedance presented to the relay for a fault at 8|Page  the remote end of the second line section. On interconnected power systems, the effect of fault current infeed at the remote busbars will cause the impedance presented to the relay to be much greater than the actual impedance to the fault and this needs to be taken into account when setting Zone 3. In some systems, variations in the remote busbar infeed can prevent the application of remote back-up Zone 3 protection but on radial distribution systems with single end infeed, no difficulties should arise. Zone-4 Settings Zone 4 (Reverse) is used to provide back-up protection for the local busbar, by applying a reverse reach setting of the order of 25% of the Zone 1 reach. In Powergrid the settings calculations will be done through standard protection settings templates which are available in Intranet. The typical settings of Zones are as follows: Z4A Z4C Time Z3A Z3C T3 Z2A Z2C T2 Z1A Z1C A Z1B B D Z2B T2 Z3B T3 Z4B Z1A = 8 0 % of Z AB (inst.) Z2A = 1 2 0 % of Z AB (~3 0 0 m s – 50 0m s) Z3A (FORWARD) = 120% of {Z AB + Z CD} (~800ms – 1500ms) Z4A (REVERSE) = 10-25% of Z AB (~500ms) Fig 5.3 – Typical Settings of Distance Zones 9|Page 6. DISTANCE PROTECTION SCHEMES 6.1. Introduction One of the main disadvantages of this scheme is that the instantaneous Zone 1 protection at each end of the protected line cannot be set to cover the whole of the feeder length and is usually set to about 80%. This leaves two ‘end zones’, each being about 20% of the protected feeder length. Faults in these zones are cleared in Zone 1 time by the protection at one end of the feeder and in Zone 2 time (typically 0.25 to 0.4 seconds) by the protection at the other end of the feeder. Fig 6.1 – Conventional distance scheme This situation cannot be tolerated in some applications, for two main reasons: A. faults remaining on the feeder for Zone 2 time may cause the system to become unstable B. where high-speed auto-reclosing is used, the non-simultaneous opening of the circuit breakers at both ends of the faulted section results in no 'dead 10 | P a g e  time' during the auto-reclose cycle for the fault to be extinguished and for ionised gases to clear. This results in the possibility that a transient fault will cause permanent lockout of the circuit breakers at each end of the line section Even where instability does not occur, the increased duration of the disturbance may give rise to power quality problems, and may result in increased plant damage. Unit schemes of protection that compare the conditions at the two ends of the feeder simultaneously positively identify whether the fault is internal or external to the protected section and provide high-speed protection for the whole feeder length. This advantage is balanced by the fact that the unit scheme does not provide the back up protection for adjacent feeders given by a distance scheme. The most desirable scheme is obviously a combination of the best features of both arrangements, that is, instantaneous tripping over the whole feeder length plus back-up protection to adjacent feeders. This can be achieved by interconnecting the distance protection relays at each end of the protected feeder by a communications channel. The purpose of the communications channel is to transmit information about the system conditions from one end of the protected line to the other, including requests to initiate or prevent tripping of the remote circuit breaker. The former arrangement is generally known as a 'transfer tripping scheme' while the latter is generally known as a 'blocking scheme'. 6.2. Types of Distance Protection Schemes A number of these schemes are available, as described below. Selection of an appropriate scheme depends on the requirements of the system being protected. Carrier Communication Schemes A. Permissive Schemes I. Permissive Underreach Protection (PUP) Schemes Direct Underreach Protection Scheme PUP Scheme with Z2 (PUP Z2) PUP Scheme with Forward Start (PUP Fwd) 11 | P a g e  II. Permissive Overreach Protection (POP) Schemes POP Scheme with Zone 2 (POP Z2) POP Scheme with Zone 1 (POP Z1) B. Blocking Schemes BOP Scheme with Zone 2 (BOP Z2) BOP scheme with Zone 1 (BOP Z1) In Powergrid, PUP Z2 and POP Z2 schemes are being used. 6.3. Direct Underreach Protection Scheme The simplest way of reducing the fault clearance time at the terminal that clears an end zone fault in Zone 2 time is to adopt a direct transfer trip or intertrip technique, the logic of which is shown in Figure 6.2. A contact operated by the Zone 1 relay element is arranged to send a signal to the remote relay requesting a trip. The scheme may be called a 'direct under-reach transfer tripping scheme’, ‘transfer trip under-reaching scheme', or ‘intertripping underreach distance protection scheme’, as the Zone 1 relay elements do not cover the whole of the line. Carrier Send Carrier Send Z1 T1 T1 Z1 Z2 T2 T2 Z2 TRIP TRIP ≥1 ≥1 Z3 T3 T3 Z3 Z4 T4 T4 Z4 Carrier Receipt Carrier Receipt Fig 6.2 - Logic for direct underreach transfer tripping scheme A fault F in the end zone at end B in Figure 6.3 results in operation of the Zone 1 relay and tripping of the circuit breaker at end B. A request to trip is also sent to the relay at end A. The receipt of a signal at A initiates tripping immediately because the receive relay contact is connected directly to the trip relay. The disadvantage of this scheme is the possibility of undesired tripping by accidental operation or maloperation of signalling equipment, or interference on the communications channel. As a result, it is not commonly used. 12 | P a g e  Fig 6.3 - Logic for direct underreach transfer tripping scheme 6.4. PUP Scheme with Z2 (PUP Z2) The direct under-reach transfer tripping scheme described above is made more secure by supervising the received signal with the operation of the Zone 2 relay element before allowing an instantaneous trip, as shown in Figure 6.4. The scheme is then known as a 'permissive under-reach transfer tripping scheme' (sometimes abbreviated as a PUTT, PUR or PUP Z2 scheme) or ‘permissive underreach distance protection’, as both relays must detect a fault before the remote end relay is permitted to trip in Zone 1 time. Carrier Send Carrier Send Z1 T T Z1 1 1 Z2 T T Z2 ≥ TRIP TRIP ≥ 2 2 Z3 T 1 1 Z3 T 3 3 Z4 T T Z4 4 4 & & Carrier Receipt Carrier Receipt Fig 6.4 - Permissive under-reach transfer tripping scheme 13 | P a g e  The PUP schemes require only a single communications channel for two-way signalling between the line ends, as the channel is keyed by the under-reaching Zone 1 elements. The related diagram shown in Fig 6.5 Fig 6.5 - PUP Signalling Arrangement 6.5. POP Scheme with Zone 2 (POP Z2) In this scheme, a distance relay element set to reach beyond the remote end of the protected line is used to send an inter-tripping signal to the remote end. However, it is essential that the receive relay contact is monitored by a directional relay contact to ensure that tripping does not take place unless the fault is within the protected section; see Figure 6.6. The instantaneous contacts of the Zone 2 unit are arranged to send the signal, and the received signal, supervised by Zone 2 operation, is used to energise the trip circuit. The scheme is then known as a 'permissive over-reach transfer tripping scheme' (POTT, POR or POP). Carrier Send Carrier Send Z1 Z1 T1 T1 Z2 Z2 T2 TRIP TRIP T2 ≥1 ≥1 Z3 Z3 T3 T3 Z4 Z4 T4 T4 & & Carrier Receipt Carrier Receipt Fig 6.6 – Permissive over-reach transfer tripping scheme 14 | P a g e Since the signalling channel is keyed by over-reaching Zone 2 elements, the scheme requires duplex communication channels - one frequency for each direction of signalling. The related diagram shown in Fig 6.7 Fig 6.7 – POP Signalling Arrangement To prevent operation under current reversal conditions in a parallel feeder circuit, it is necessary to use a current reversal guard timer to inhibit the tripping of the forward Zone 2 elements. Otherwise maloperation of the scheme may occur under current reversal conditions. It is necessary only when the Zone 2 reach is set greater than 150% of the protected line impedance. The timer is used to block the permissive trip and signal send circuits as shown in Figure 6.8. The timer is energised if a signal is received and there is no operation of Zone 2 elements. Fig 6.8 - Current reversal guard logic – permissive over-reach scheme 15 | P a g e An adjustable time delay on pick-up (tp) is usually set to allow instantaneous tripping to take place for any internal faults, taking into account a possible slower operation of Zone 2. The timer will have operated and blocked the ‘permissive trip’ and ‘signal send’ circuits by the time the current reversal takes place. The timer is de-energised if the Zone 2 elements operate or the signal received' element resets. The reset time delay (td) of the timer is set to cover any overlap in time caused by Zone 2 elements operating and the signal resetting at the remote end, when the current in the healthy feeder reverses. Using a timer in this manner means that no extra time delay is added in the permissive trip circuit for an internal fault. Weak Infeed Conditions: In the standard permissive over-reach scheme, as with the permissive under- reach scheme, instantaneous clearance cannot be achieved for end-zone faults under weak infeed or breaker open conditions. To overcome this disadvantage, two possibilities exist. Fig 6.9 - Weak Infeed Echo logic circuit The Weak Infeed Echo feature available in some protection relays allows the remote relay to echo the trip signal back to the sending relay even if the appropriate remote relay element has not operated. This caters for conditions of the remote end having a weak infeed or circuit breaker open condition, so that the relevant remote relay element does not operate. Fast clearance for these faults is now obtained at both ends of the line. The logic is shown in Figure 6.9. A time delay (T1) is required in the echo circuit to prevent tripping of the remote end breaker when the local breaker is tripped by the busbar protection or breaker 16 | P a g e  fail protection associated with other feeders connected to the busbar. The time delay ensures that the remote end Zone 2 element will reset by the time the echoed signal is received at that end. Signal transmission can take place even after the remote end breaker has tripped. This gives rise to the possibility of continuous signal transmission due to lock-up of both signals. Timer T2 is used to prevent this. After this time delay, 'signal send' is blocked. A variation on the Weak Infeed Echo feature is to allow tripping of the remote relay under the circumstances described above, providing that an undervoltage condition exists, due to the fault. This is known as the Weak Infeed Trip feature and ensures that both ends are tripped if the conditions are satisfied. 7. AUTO RECLOSING SCHEME 7.1. Introduction Faults on overhead lines fall into one of three categories: a. Transient b. Semi-permanent c. Permanent 80-90% of faults on any overhead line network are transient in nature. The remaining 10%-20% of faults are either semi-permanent or permanent. Transient faults are commonly caused by lightning or temporary contact with foreign objects, and immediate tripping of one or more circuit breakers clears the fault. Subsequent re-energisation of the line is usually successful. A small tree branch falling on the line could cause a semi-permanent fault. The cause of the fault would not be removed by the immediate tripping of the circuit, but could be burnt away during a time-delayed trip. HV overhead lines in forest areas are prone to this type of fault. Permanent faults, such as broken conductors, and faults on underground cable sections, must be located and repaired before the supply can be restored. Use of an auto-reclose scheme to re-energise the line after a fault trip permits successful re-energisation of the line. Sufficient time must be allowed after tripping for the fault arc to de-energise before reclosing otherwise the arc will 17 | P a g e re-strike. Such schemes have been the cause of a substantial improvement in continuity of supply. A further benefit, particularly to EHV systems, is the maintenance of system stability and synchronism. Fig 7.1: Single-shot auto-reclose scheme operation for a transient fault Fig 7.2: Single-shot auto-reclose scheme operation for a permanent fault 18 | P a g e  A typical single-shot auto-reclose scheme is shown in Figure 7.1 and Figure 7.2. Figure 7.1 shows a successful reclosure in the event of a transient fault and Figure 7.2 an unsuccessful reclosure followed by lockout of the circuit breaker if the fault is permanent. 7.2. Operating Features of Auto-reclose Scheme The following are the some of the parameters if the Auto-Recloser scheme in Powergrid: Initiation: Auto-reclosing schemes are invariably initiated by the tripping command of a protection relay function for Single phase faults in Z1/ Z2+CR reach. Type of Protection: Auto-reclosing to use instantaneous Over Current (1.5A or 2A) / Impedance (Z2) Protection to give trip during Auto-recloser operation. Dead Timer: The dead time setting in auto-reclose relay should be long enough to ensure complete de-ionisation of the arc. The Dead time is typically set at 1 sec – 1.5sec. Reclaim Time: The reclaim time should take account of the time needed for the closing mechanism to reset ready for the next reclosing operation. The typical reclaim time set at 25sec. Auto Reclose Blocking: Auto-reclose scheme needs to be blocked for following typical conditions: a. 86A/B Operation b. BusBar Protection Operation c. LBB Operation (T1/T2) of Main CB d. DT Receipt e. GD / CT SF6 L/O Operation f. Main CB OPEN Condition g. Main CB PD operation h. Multi Phase Fault (for 1-Ph A/R Set) Auto Reclose Lockout: Auto-reclose scheme needs to be lockout for following typical conditions: a. Trip in Dead Time 19 | P a g e  b. No CB Status Discrepancy at end of Dead Time c. Trip in Reclaim Time d. Main CB Unhealthy e. A/R OFF (Switch / BCU / SAS / Any relay) & Any trip (Main-1/2 relay) f. CH-1 SW OFF & CH-2 Fail & Any trip (Main-1/2 relay) g. CH-1 Fail & CH-2 SW OFF & Any trip (Main-1/2 relay) h. CH-1 Fail & CH-2 Fail & Any trip (Main-1/2 relay) i. CH-1 SW OFF & CH-2 SW OFF & Any trip (Main-1/2 relay) 7.3. Examples of Auto-Reclose Applications Single / Double Busbar Substation: Each line circuit breaker is provided with an auto-reclose relay that recloses the appropriate circuit breakers in the event of a line fault. For a fault on Line, this would require opening of respective CB and the corresponding CB at the remote end of the line. Breaker and a Half Substations simplistic example of a breaker and a half substation is shown in Figure 7.3. The substation has two busbars, Bus 1 and Bus 2, with lines being energised via a 'diameter' of three circuit breakers (CB1, CB2, CB3). Two line circuits can Fig 7.3 - Breaker and a half example be energised from each diameter, shown as Line 1 and Line 2. It can therefore be seen that the ratio of circuit breakers to lines is one-and-a-half, or breaker 20 | P a g e  and a half. The advantage of such a topology is that it reduces the number of costly circuit breakers required, compared to a double-bus installation, but also it means that for any line fault, the associated protection relay(s) must trip two circuit breakers to isolate it. Any auto-reclose scheme will then need to manage the closure of two breakers (e.g. CB1 and CB2 for reclosing Line 1). Utilities usually select from one of three typical scheme philosophies in such a scenario: Auto-reclosure of an 'outer' (or 'diameter') breaker, leaving the closing of the centre breaker for manual remote control A leader-follower auto-reclosing scheme Auto-reclosure of both breakers simultaneously The first option offers re-energisation of the line, but leaves the final topology restoration task of closing CB2 to the control operator. A leader-follower scheme is one whereby just one circuit breaker is reclosed initially (CB1), and then only if this is successful, the second or 'follower' breaker (CB2) is reclosed after a set follower time delay. i.e with priority scheme. The advantage here is that for a persistent fault there is only the increased interrupting duty of a switch-on-to-fault trip for a single circuit breaker, not two. Should a trip and lockout occur for CB1, then CB2 will also bedriven to lockout. 8. OVER VOLTAGE PROTECTION The Over voltages may occur in the system due to multiple reasons. The main reason is lightly loaded Long transmissions lines which generates more reactive power during light loading condition. These over voltages will increase the stress on the insulation of power system equipment’s. To protect the system from abnormal raise in the voltages, the Over voltage protection being enabled in relays. In Powergrid, the Over voltage protection is implemented in two stages and the typical settings for the same are as follows: Over Voltage Stage-1: 110% with 5 sec delay Over Voltage Stage-2: 140%-150% with 100 sec delay 21 | P a g e  If multi circuit lines the Stage-1 settings need to be graded to avoid the tripping of all the circuit simultaneously. the typical graded settings are as follows: Circuit-1: Over Voltage Stage-1: 110% with 5 sec delay Circuit-2: Over Voltage Stage-1: 112% with 5 sec delay Circuit-3: Over Voltage Stage-1: 110% with 6 sec delay Circuit-4: Over Voltage Stage-1: 112% with 6 sec delay Stage-2 settings generally not graded and the settings are same for all circuits. 9. OVERCURRENT AND EARTH FAULT PROTECTION 9.1. Introduction Protection against excess current was naturally the earliest protection system to evolve. From this basic principle, the graded overcurrent system, a discriminative fault protection, has been developed. 9.2. Principles of Time/Current Grading Among the various possible methods used to achieve correct relay co- ordination are those using either time or overcurrent, or a combination of both. The common aim of all three methods is to give correct discrimination. That is to say, each one must isolate only the faulty section of the power system network, leaving the rest of the system undisturbed. Discrimination by Time In this method, an appropriate time setting is given to each of the relays controlling the circuit breakers in a power system to ensure that the breaker nearest to the fault opens first. A simple radial distribution system is shown in Figure 9.1, to illustrate the principle. Fig 9.1 - Radial system with time discrimination 22 | P a g e If a fault occurs at F, the relay at B will operate in t seconds and the subsequent operation of the circuit breaker at B will clear the fault before the relays at C, D and E have time to operate. The time interval t1 between each relay time setting must be long enough to ensure that the upstream relays do not operate before the circuit breaker at the fault location has tripped and cleared the fault. Discrimination by Current Discrimination by current relies on the fact that the fault current varies with the position of the fault because of the difference in impedance values between the source and the fault. Hence, typically, the relays controlling the various circuit breakers are set to operate at suitably tapered values of current such that only the relay nearest to the fault trips its breaker. But implementation of this method is very difficult as the fault resistance vary fault to fault. Discrimination by both Time and Current Each of the two methods described so far has a fundamental disadvantage. In the case of discrimination by time alone, the disadvantage is due to the fact that the more severe faults are cleared in the longest operating time. On the other hand, discrimination by current can be applied only where there is appreciable impedance between the two circuit breakers concerned. It is because of the limitations imposed by the independent use of either time or current co-ordination that the inverse time overcurrent relay characteristic has evolved. With this characteristic, the time of operation is inversely proportional to the fault current level and the actual characteristic is a function of both ‘time’ and 'current' settings. Figure 9.3 shows the characteristics of two relays given different current/time settings. For a large variation in fault current between the two ends of the feeder, faster operating times can be achieved by the relays nearest to the source, where the fault level is the highest. The disadvantages of grading by time or current alone are overcome. 23 | P a g e Fig 9.2 - Relay characteristics for different settings 24 | P a g e 10. GENERAL PROTECTION SCHEME OF TRNASMISSION LINES The general protection philosophy for transmission lines in Powergrid is as follows: 25 | P a g e