Power Station Electrical Protection A 2 B 2 C 2 Neutral C.T E M L } a 2 b 2 c 2 M M M CT Restricted E/F Relay L L L TO TRIP CIRCUIT

Contents 1 The Need for Protection 2 1.1 Types of Faults............................ 2 1.1.1 Overcurrent.......................... 2 1.1.2 Earth Fault.......................... 2 1.2 Fault Detection............................ 2 1.3 Isolation of Faulty Equipment.................... 2 1.4 Protective Relays........................... 3 1.5 Classes of Protection......................... 4 1.6 Characteristics of a Good Protection Scheme........... 4 2 Common Terms Related to Protection 5 3 Unit protection schemes 7 3.1 Transformer protection........................ 7 3.1.1 The Buchholz relay...................... 7 3.1.2 Explosion Vent........................ 8 3.1.3 Qualitrol Pressure Relief................... 8 3.1.4 Continuous Gas Analyser.................. 8 3.1.5 Earth Fault Protection of High Voltage Delta Windings. 10 3.1.6 Differential protection.................... 12 3.1.7 Differential Protection of a Three Phase Transformer... 15 3.1.8 Differential Earth Fault Protection of Star Windings... 17 3.2 Busbar protection.......................... 19 3.2.1 Check Zones......................... 19 3.2.2 Blind Spots and Blind Spot Protection........... 22 3.2.3 AC Wiring Supervision................... 23 3.2.4 DC Supply Failure...................... 24 3.2.5 Protection Inoperative Alarm................ 24 3.2.6 Circuit Breaker failure (CB fail) Protection........ 24 3.3 Circuit Protection.......................... 25 3.3.1 Distance-time and definite distance protection...... 25 3.3.2 Auto Reclose......................... 33 3.3.3 Pilot Wire Protection.................... 33 3.3.4 220kV Oil-filled Cable Protection.............. 35 3.4 Generator Protection......................... 36 3.4.1 Generator Earth Faults................... 36 3.4.2 Stator Differential Protection................ 38 3.4.3 Generator Stator Over-Currents.............. 39 3.4.4 Negative Phase Sequence Protection............ 40 3.4.5 Reverse Power Protection.................. 44 4 Non-Unit protection 45 4.1 Overcurrent Relays.......................... 45 4.2 Earth Fault Relays.......................... 46 4.3 Earth Fault Protection of Transformers.............. 46 4.4 Earth Fault Protection on Circuits................. 47 4.5 Earth Fault on Interconnecting and Generator Transformers... 48 4.6 Time Graded (Non-Unit) Protection................ 49

4.7 Directional Relays.......................... 51 5 Backup Protection 53 6 Measuring Voltage and Current 55 6.1 Voltage Transformers......................... 55 6.2 Current Transformers........................ 55 A Pre 1985 relay codes 57 B Post 1985 relay codes 58

List of Figures 1 Photo of Transformer explosive vent................ 9 2 Photo of Transformer Qualitrol................... 9 3 Photo of Transformer Gas Analyser................. 10 4 Delta-Star transformer Protection................. 11 5 Fault is outside area covered by CT s therefore relay does not operate (i.e. current from CT A is cancelled by current from CT B)................................ 12 6 Relay operates as fault is between CT s (i.e. current from CT A is NOT cancelled by current from CT B)........... 13 7 Instantaneous relay.......................... 13 8 Biased relay.............................. 13 9 Biased type relay........................... 14 10 Protection of single phase of a Transformer............ 15 11 Transformer Differential Protection................. 16 12 Differential (Restricted) Earth Fault Protection of Transformer - Operation on Fault inside Zone................... 18 13 Differential (Restricted) Earth Fault Protection of Transformer Operation on Fault outside Zone.................. 18 14 Busbar protection scheme for a single busbar........... 20 15 Bus zone protection scheme for a single bus with bus section circuit breaker............................ 20 16 Bus zone protection for circuit breakers and a half without check zone.................................. 21 17 Busbar protection scheme for a single bus with a bus section circuit breaker............................ 22 18 measurement of distance to fault.................. 25 19 distance protection zones...................... 27 20 Acceleration of Distance measurement............... 31 21 Differential comparison Earth fault protection........... 32 22 Summation Transformer....................... 34 23 Generator stator earth fault protection............... 37 24 Location of differential protection CT s............... 38 25 Basic generator differential scheme................. 39 26 Positive phase sequence....................... 41 27 Negative sequence rotation..................... 42 28 Zero phase sequence......................... 42 29 Effects of PPS and NPS on turbo-alternator (top - Positive phase sequence; bottom - Negative phase sequence)........... 43 30..................................... 46 31 Earth fault protection on the Delta side of a transformer..... 47 32 Overcurrent and Earth Leakage Relays Connections....... 48 33..................................... 48 34..................................... 49 35 Instantaneous relays with Definite Time.............. 49 36 Inverse Time relays.......................... 50 37 Directional relay........................... 51 38 Non-Directional relays applied to parallel feeders......... 52 39 Directional relays applied to parallel feeders............ 52

40 Illustration of gross errors in distance measurement with feed in between relay and fault....................... 53

19481 Demonstrate knowledge of electricity supply protection equipment Protection 19481 Author - Richard J Smith Creation date - 7 November 2006 Last Updated - 3 May 2007 Description This course provides the student with an understanding of electricity supply protection equipment with emphasis on the equipment provided at Huntly Power Station. Successful completion of this course will enable the student to achieve NZQA unit standard 19481 Demonstrate knowledge of electrical supply protection equipment. Pre-Requisites The student have achieved EnChem level 2 and completed his/her electrical component of their plant training at Huntly or equivalent work experience. Completing and Passing the Course The following modules need to be successfully completed to pass the course: 1. the 19481 Protection workbook to a satisfactory level 2. the course evaluation survey Who should do this Course Genesis staff wishing to complete NZQA National Cert Electricity Supply (Level 4) will be required to undertake this course. Student Objectives On completing this course, the student will be able to; 1. Define common terms and abbreviations used in discussing electrical protection. 2. Describe the purpose and classes of protection (range: purpose of protection, typical causes of faults) 3. Identify the methods of discrimination used to find faults (range: time, current, direction of power flow, distance measurement, differential relays) 4. State the purpose of voltage and current transformers 5. Identify and describe the types of transformer protection (range: buchholz, overcurrent, earth fault, differential) 6. Describe the principles of circuit and busbar protection (range: distance measurement, earth faults, bus zone, CB fail, and backup protection) 7. Describe relay numbering systems, both pre 1985 and ANSI C37.2 1

1 The Need for Protection If a fault or other abnormal condition occurs in a power system, the faulty apparatus must be isolated from the rest of the system as quickly as possible to reduce damage both to the faulty equipment and to those parts of the system carrying the fault current. Protective devices are therefore installed in the system to detect the presence of a fault and initiate the required action. Isolation of the affected equipment will then allow continued operation of the remainder of the system as normal. 1.1 Types of Faults 1.1.1 Overcurrent When a circuit or piece of equipment is carrying a greater current than it was designed for, it is said to be overloaded. Most equipment can tolerate some degree of overloading for a limited time, but protection needs to be provided to limit the overloading to a value that doesn t damage the equipment. Overcurrent can be caused by lighting strikes on overhead lines or just attempting to supply more load than the circuit design load. 1.1.2 Earth Fault A common cause of faults on buried cables and overhead lines is an earth fault. This can be caused by breakdown of insulation or digging up of buried cables, or by operating cranes, etc near overhead lines. When a live circuit is connected to earth a large current will flow (which can cause overloading on the circuit), the earth voltage near the point of the earth fault can increase to a dangerous level, and supply to the intended recipient can be interrupted. 1.2 Fault Detection Faults and other abnormal conditions may cause changes in the magnitude, direction, phase angle and frequency of circuit currents and voltages. The nature of these changes depends upon the fault and the position of the fault relative to the point in the system from which the fault is being observed. A protective system uses current transformers and voltage transformers (to measure magnitudes of current and voltage and transform them to values which can be handled by the relays), relays (to monitor these values and detect an abnormal condition) and a tripping circuit to the circuit breaker. A fault detection system must provide protection of the system. 1.3 Isolation of Faulty Equipment Protection of the system is the ability of a fault on equipment to be isolated from the system quickly and with as little interruption to other supplies as possible. By the operation of many types of relays which measure the electricity in the system, an appropriate operation of a particular relay will trip circuit breakers to isolate the fault. 2

The protective equipment should be simple as possible, but it should also process discrimination in order that it should isolate only the faulty circuit or apparatus and not operate for other faults outside its zone. 1.4 Protective Relays A relay used for automatic protection may be defined as a mechanical or electrical apparatus triggered by current, voltage, or power which opens or closes a local circuit when the current has a specified magnitude, or bears a specified relation to the voltage of the main circuit with which the relay is associated. The function the relay provides may be classified as follows: UNDER VOLTAGE, and UNDER CURRENT in which operation takes place when the voltage or current falls below a specified value. OVER VOLTAGE, and OVER CURRENT, in which operation takes place when the voltage or current rises above a specified value. DIRECTIONAL, in which operation takes place when the component of the current in phase with the voltage, assumes a specified magnitude and a specified direction in relation to the voltage. DISTANCE, in which the operation is governed by the ratio of the voltage to the current, i.e. impedance, or to the component of the current having some specified phase relation to the voltage. Relays can be classified, with regard to their timing characteristics, under the following headings; INSTANTANEOUS, in which complete operation takes place with no intentional time delay from the incidence of the operating current reaching the minimum pick up value. DEFINITE TIME, in which the time delay between incidence of the operating current and the completion of the relay operation is independent of the magnitude of the current. That is a definite time must elapse after the minimum pick up value of current is reached, before tripping is initiated. INVERSE TIME, in which the time lag decreases as the value of the operating current or power increases. The function of a protective relay is to remove the faulty line or equipment from service with as little disturbance and as little damage to the equipment as possible. Both these considerations require that the time of operation must be as fast as possible but the first also requires that only the faulty section must be removed. Protective relays must therefore be speedy and selective and this is achieved by the use of both time and current graded relays and special relays for special types of fault. Remember 3

Relays may require current and/or voltage supplies from CTs and/or VT s. Relays operate on current, voltage, power, or impedance. Some relays have a built in, time delay, either definite time or inverse time. 1.5 Classes of Protection Protection systems can be divided into two basic classes: Unit Protection Unit protection protects a precisely defined area of the primary system and will respond only to faults within that area. Typical examples are differential protection, differential earth fault protection, busbar protection, Buchholz relay, pilot wire, direction comparison earth fault. Non-Unit Protection will respond to a fault within an area that is not precisely defined. Typical examples are overcurrent protection, unrestricted earth fault protection. 1.6 Characteristics of a Good Protection Scheme Reliability Discrimination Stability Speed of operation 4

2 Common Terms Related to Protection Back up Protection This is a second, often slower and cheaper protective system, that supplements the primary protection should the latter fail to operate for any reason. CT Current Transformer Definite Time Relay A relay which operates in a pre-determined time, which is not affected by fault values. Usually it is operated by the closure of a contact on another relay, such as an instantaneous over-current relay, instantaneous earth fault relay, etc. Discrimination The ability of protection to select and disconnect only the faulty equipment, leaving as much other equipment as possible live. Also called selectivity Instantaneous Relay These are relays whose operation is not intentionally delayed. Typical operating times are from about 0.05 to 0.1 second. Inverse Time (e.g. Overcurrent Relay) These have a time of operation that decreases as the magnitude of the operating current (or other operating quantity) increases. Non-Unit Protection Protection that will respond to a fault over a wide area of the system. In general the area will not be precisely defined. High Speed Tripping This is a relative term but generally implies operation in less than 2 or 3 cycles (0.04 or 0.06 seconds). HV High Voltage LV Low Voltage Primary Protection This is the main protective system that is intended to operate on an internal fault. Relay Drop off Value When the current is lowered, the value at which the relay returns to the de-energised position. Relay Pick up Current The value of current at which the relay just operates and closes its contacts (or voltage for voltage operated relays). Reliability In the event of a fault in a zone, the protection of that zone must operate and trip the correct circuit breakers to isolate that zone, and only that zone, from all live supplies. If it fails to operate, or operates unnecessarily, the protection system is said to mal-operate. Achieving reliability requires correct design and installation and regular maintenance of the protective equipment. Residual Current The current that results from combining the three currents in the phases. Paralleling the three secondaries of CT s on R, Y and B phases gives an output of the vector sum of the currents in the three phases - the residual current. This is commonly connected to an earth fault relay. 5

Residual Voltage The vector sum of the voltages to earth of the three phase conductors. The secondary equivalent is obtained by connecting the three VT secondaries in series. Restraint A relay may be hindered from operating by some quantity, such as voltage. it is then said to be given (voltage) restraint. An impedance relay is restrained by voltage, operated by current. The current tending to close the contacts, the voltage to open them. Sensitivity A protective scheme is sensitive when it will respond to very small internal faults, but note that extreme sensitivity is usually accompanied by poor stability. item[selectivity or discrimination] The protection in any zone is said to discriminate or be selective, when it can distinguish between an internal fault within the zone and an external (through) fault in another zone. The protection should trip on an internal fault but ignore all external faults and normal load current. A scheme that lacks discrimination will cause unnecessary disconnection of healthy plant and circuits. Signal Link A communication link between two substations used for protection purposes, usually to close (or open) a contact at the remote station. The link may be by metallic wires (pilots), carrier over pilot wires, power line carrier, radio, etc. Speed of Operation The longer a fault is allowed to persist, the greater the damage that may be caused. In the case of a high current fault close to a generator, synchronisation to the system may be lost. Fast operation should not, however, be sought at the expense of selectivity or reliability. Stability Protection is stable if it does not respond to faults outside the protected zone, i.e. it operates only for those faults it is designed to operate for. Unit Protection Protection which protects a precisely defined area of the power system. It responds only to faults within that defined area. Typical examples are differential protection, busbar protection, Buchholz relay. VT Voltage Transformer 6

3 Unit protection schemes Unit protection responds only to faults within clearly defined boundaries and therefore no time delay is necessary for discrimination. This allows fast clearance times which are important for protection of main equipment such as generators and transformers. Usually the protective scheme consists of two CT s per phase, one set at each end of the protective zone. The relay measures the difference between the secondary currents. If the zone is healthy, there is no difference between the currents and the relay remains inoperative. If a fault occurs within the zone (i.e. between the ends), currents from the CTs no longer balance and the relay operates. Examples of unit protection: Differential protection of generators Differential protection of transformers Overall differential protection of generator transformers Differential earth fault protection of the star winding of transformers, including cables Earth fault protection of transformer delta windings Busbar protection Pilot wire protection Some directional comparison schemes (or distance carrier) Buchholz protection 3.1 Transformer protection 3.1.1 The Buchholz relay The Buchholz relay is mounted on transformers in the oil pipe between the main transformer tank and the conservator tank. Its purpose is to collect any gas from the transformer. Gas given off can be an early warning of damage to the transformer and early detection can greatly reduce the cost of repair. The Buchholz relay has two switches, alarm and trip. The alarm switch is connected to a float in the top of the relay. This will operate when a certain amount of gas has accumulated in the relay. The trip switch is connected to a flap in line with the oil pipe, and may have a float in addition. In the event of major trouble the switch will be activated by a sudden rush of gas or oil. Some transformer tap changers have a Buchholz relay with trip contacts only. Early Buchholz relays used mercury switches; these caused spurious alarms or trippings in times of earth tremors due to slopping of the mercury. These alarms or trippings can be prevented by the use of a seismic blocking relay which 7

switches the Buchholz relay out of service when earth tremors are detected. A seismic blocking relay uses the pendulum principle. When the pendulum moves, contacts close and the Buchholz trip circuit is temporarily made inoperable. This relay must he firmly mounted so that movement caused by vehicles etc is not detected. The disadvantage is that at the time of earth tremors this protection is out of service. An improved method is the use of a Buchholz relay using reed switches. These are not affected by movement, as reed switches are closed magnetically. To prevent the possibility of reed switches closing due to the magnetic field caused by inrush currents special biased reed switches are used. These have a small magnet holding the contacts open. This prevents the switch from being closed by stray magnetic fields. When the switch is moved to its operating magnet, the switch closes as usual. The Buchholz alarm which is float operated can be activated by low oil level allowing air into the relay or by air from the oil in the transformer after filtering has been carried out. The Buchholz relays primary purpose is to provide early warning of conditions inside the transformer that indicate the probability of a developing fault. If a large internal fault in the transformer does develop, the fault would be cleared by a differential relay. 3.1.2 Explosion Vent Explosion vents are fitted to all large transformers. This vent is a large diameter pipe welded to the top of the transformer tank with a down turned bursting disk or diaphragm. The pipe is usually higher than the conservator tank to prevent excessive loss of oil, should the disk burst. The explosion vent protects the transformer case from building up pressure in the case of an internal fault. When a serious internal fault occurs gas is produced. This quickly builds up pressure which will operate the Buchbolz trip. Should the pressure not be sufficiently relieved the bursting disk will shatter and relieve the pressure from inside the tank case. This is usually obvious by the spillage of oil down the transformer and over the ground below the vent. 3.1.3 Qualitrol Pressure Relief A more modern form of explosive vents for transformer is called a Qualitrol. When a fault or short circuit occurs in a transformer, the arc instantaneously vaporises the liquid causing extremely rapid build-up of gaseous pressure. If this pressure is not relieved adequately within several thousandths of a second, the transformer tank will rupture spraying flaming oil over a wide area. The Qualitrol pressure relief valve opens fully under such pressure within 2 milliseconds. 3.1.4 Continuous Gas Analyser Most modern large transformers are fitted with a dissolved gas analyser which can provide continuous on-line reading of dissolved gas in oil and also moisture 8

Figure 1: Photo of Transformer explosive vent Figure 2: Photo of Transformer Qualitrol 9

level in oil. The gas detection component is based on combustible gases dissolved in oil passing through a selectively gas-permeable membrane into an electrochemical gas detector. Within the gas detector, the gases combine with oxygen from the ambient air to produce an electrical signal that is measured by an electronic circuit and converted to ppm. The gas detector is sensitive to the gases that are the primary indicators of incipient faults in oil-filled transformers (i.e. Hydrogen, Carbon monoxide, Ethylene, and Acetylene). Moisture detection is performed by a thin-film capacitive moisture sensor. The capacitive value of this sensor varies according to the moisture level and this value is converted to an electrical signal. Both the gas detection and moisture level reading are configured to generate alarms but are not usually connected to transformer trip circuits. Figure 3: Photo of Transformer Gas Analyser 3.1.5 Earth Fault Protection of High Voltage Delta Windings This protection is provided by an earth fault relay operated from CT s in the leads to the transformer HV delta winding. See Figure 4. The delta winding, being insulated from earth, cannot provide an earth return path for faults anywhere on the system between the generation source and the HV CT s. The earth fault relay can only operate for earth faults on the transformer delta 10

(primary) winding or leads from the transformer to the CT s. The protection is therefore a form of unit protection and trips without time delay. R Y B CT s Earth Fault Relay A 2 B 2 C 2 Figure 4: Delta-Star transformer Protection Consider the case of a delta star transformer as shown in Figure 4 supplied from generation source on the left hand side of RYB, and connected to load a 2 b 2 c 2. When the transformer is un-faulted, the currents in each of the leads R,Y,B at any instant of time return through the other two. The secondary currents from the CTs circulate round the CT secondaries, but do not pass through the earth fault relay. Faults to earth in the secondary side of the transformer (e.g. feeder faults) do not operate the HV earth fault relay. An earth fault on secondary terminal a 2 will be balanced on the supply side by primary current in R phase returning to the source via B phase. Even with the transformer back livened from the secondary, the earth fault relay could not pick up for a primary earth fault to the left of the CTs. Now if there is an earth fault on say the HV A 2 terminal, earth fault current will flow through Red phase CT and operate the HV earth fault relay. Thus operation of the relay only occurs for HV faults on the transformer and connections up to the CT. Advantages Unit protection given for earth faults on HV winding. Location of the fault is more easily found than for full differential protection where LV faults also actuate the relay. a 2 b 2 c 2 11

Fast operating, and cheap. Disadvantages Only operates for HV earth faults. Does not cover HV phase to phase faults, short circuited turns, or LV faults. (However if the fault is inside the transformer, it is cleared by the buchholz relay.) Remember Differential earth fault protection of transformer LV star windings also protects the LV cables if the CT position includes them in the protected zone. Earth fault protection of the delta winding may operate for flashover of the transformer rod gaps or surge diverters. 3.1.6 Differential protection Circulating Current Differential Protection Figure 5 shows two CT s, A and B, protecting the conductor AB with differential protection. An external load or an external fault is represented at F. Secondary currents flow as shown, and if the CTs have the same ratios and maintain their accuracy, the currents cancel out to zero and no current flows in the relay. A CT - A Fault Current R CT - B B Fault to earth (F) Figure 5: Fault is outside area covered by CT s therefore relay does not operate (i.e. current from CT A is cancelled by current from CT B) If an internal fault occurs between the CT s as shown in Figure 6, secondary current flows in the relay. If current is fed to the fault from side A only, the equivalent secondary current flows into the relay. If current is also fed in from side B, the secondary current is added to that from CT A. Hence the relay operates for internal faults (i.e. faults between the two CTs). Differential relays fall into two basic types: Simple instantaneous relays. Biased relays (relays with current restraint). 12

A CT - A Fault to earth (F) Fault R CT - B Figure 6: Relay operates as fault is between CT s (i.e. current from CT A is NOT cancelled by current from CT B) Relay operating coil current Relay operating coil current Relay Operates Relay does not operate Current through CTs A and B Figure 7: Instantaneous relay Relay Operates Relay does not operate Current through CTs A and B Figure 8: Biased relay B 13

Simple Instantaneous Relays Attracted armature type relays can be very stable in differential circuits where the currents entering and leaving the equipment are identical, i.e. differential protection of busbars and generators, but not transformers. Simply by connecting a resistance in series with the relay, of a value chosen to simple established rules, it can be assured that the relay will not operate for faults external to the protected zone. The CT s must have the same turn s ratio, and reasonably similar magnetisation characteristics. Biased Differential Relays These relays are given a restraint against operating which increases with the through current. A common construction is the induction disc pattern, similar to the inverse over-current relay, with an operating coil on one electromagnet causing the disc to rotate to close the relay contacts. Another coil carrying the secondary equivalent of through current produces a torque on the disc in the opposite direction, tending to prevent (restrain) relay operation (see Figure 9). CT Restraint Operating Figure 9: Biased type relay Neglecting initial spring tension then, a 1 amp relay with 20% bias would operate at 0.2 amp with 1 amp through current, and operate at 2 amps with 10 amp through current. This assists the relay to remain inoperative when the two CTs do not match correctly in ratio. In particular this occurs with transformer differential protection, where there are taps on the main transformer. The CT ratios may be satisfactory for one transformer tap ratio, but not for other taps. Transformer Differential Protection In the differential protections described above the currents entering and leaving the equipment are identical in value if the equipment is healthy. In transformer differential protection, the input and output currents (primary and secondary) which are compared, have a known ratio to one another unless there is a short circuit in the transformer. Figure 10 shows a single phase transformer of ratio 66kV to 11kV (It will have a turns ratio of 6/1). If 600 amps flow in the 11 000 volt secondary, this must be CT 14

Transformer Voltage Source 66kV / 11kV CT 100/1 CT 600/1 100 Amps 1 Amp 1 Amp 600 Amps Load Relay Operating Winding Figure 10: Protection of single phase of a Transformer balanced by 1/6 x 600 = 100 amps in the primary winding. Ignoring magnetisation current (normally very small), the ratio secondary output current/ primary input current will always be the same as the no load voltage ratio primary volts/ secondary volts (6/1 in this case) unless some or all of the transformer turns are shorted. Now if CT s of 100/1 and 600/1 amp ratio are inserted in the primary and secondary connections as shown and the CT secondaries are connected to a relay, a current of 1 amp will circulate round the CTs, and the current through the relay operating coil will be zero (or practically so). If the transformer is partly or wholly short circuited, the balance of currents to the relay is upset, and the relay operates. Hence faults which occur between the HV and LV current transformers are detected. 3.1.7 Differential Protection of a Three Phase Transformer The three main features of a practical transformer differential scheme for a three phase transformer to provide stability are the: Choice of correct CT connections and ratios The type of connection used on the main transformer determines the relay connections to the protective CTs in order for currents on each side of the relay to cancel for all types of through fault (phase to phase or earth faults). Thus corresponding to a given star delta connected transformer a particular delta star scheme of CT interconnections is required. Also the overall CT ratios have to match the main transformer ratios (and current ratings). If the installation does not conform to the required protection scheme, unwanted tripping may occur after the load has built up above relay sensitivity. Provision for Slight CT Mismatch As mentioned above, a biased type relay is provided for stability as different tap ratios on the main transformers 15

result in different current ratios for the transformer. Provision of Stability against Magnetisation Inrush Currents When the voltage supply to a transformer is suddenly switched on to liven it, magnetisation currents are drawn from the supply of a value many times full load of the bank. These currents on one side of the bank are not matched by corresponding currents on the output winding and hence, fed only to one side of the relay appear as a transformer fault. The currents take many seconds to decay to the normal low value. These magnetisation inrush currents contain a high proportion of 100 cycle per second (100 Hz) component which is the second harmonic of the normal 50 Hz supply frequency. Internal transformer fault currents for which the relay is expected to operate do not contain this second harmonic. This characteristic is used to make the relay immune to operation from magnetisation inrush currents. A proportion of relay operating current is passed through a filter circuit, and the 100 Hz component from it is fed into a sensitive winding on the relay which hinders it from operating. A timer of approximately 20 seconds is usually employed to ensure inrush currents have stabilised. The connections for the protection of a three phase transformer are shown in schematic form in Figure 11. Note that this diagram does not show the second harmonic restraint nor taps on the relay. R Y B C.T s Power Transformer Bias Coils Neutral Point C.T s Relay Operating Coils Figure 11: Transformer Differential Protection Advantages 16

High speed of operation. Protects external leads, cables, and bushings not covered by buchholz. Being unit protection - provides discrimination with time delayed non-unit protection elsewhere on the system. Disadvantages Does not detect some incipient faults. (These are detected by the buchholz) Does not protect the transformer against overheating due to overloads or external short circuits. 3.1.8 Differential Earth Fault Protection of Star Windings This protection consists of three phase CTs with secondaries connected in parallel to give the earth fault current. This residual current is balanced against the secondary current from the transformer neutral CT and the difference is applied to the differential relay (see Figure 13). Thus the scheme detects earth faults between the neutral CT and the phase CT s, i.e. in the star winding of the transformer, LV bushings, and cable up to the switchgear containing the CT s. This relay is generally used with lead sheathed cables on 11 kv installations, and phase to phase faults are practically impossible on the 11 kv side. (Faults on single core 11 kv cables will be earth faults.) Advantages Low Cost. Fast fault clearance for heavy faults on cables as well as on the transformer. In conjunction with buchholz and fast protection of the delta winding, it virtually provides unit protection of the bank, provided that short circuits between phases are unlikely on either the HV or LV side, i.e. when cables are used on the star connected side, and spacings are larger on the other. Disadvantages Does not protect against phase to phase faults or short circuited turns, nor faults in the delta winding. When connections from the star winding are by overhead conductor instead of cable, phase to phase faults are not cleared, and where two banks are installed, both banks are tripped on overcurrent. May not detect earth faults at the neutral end of the transformer winding. Remember Unit protection operates for faults within clearly defined boundaries, usually between two sets of CTs. 17

A 2 B 2 C 2 Neutral C.I E M M M C.T Restricted E/F relay L L L To Trip Circuit Figure 12: Differential (Restricted) Earth Fault Protection of Transformer - Operation on Fault inside Zone A 2 B 2 C 2 Neutral C.T E To Trip Circuit } M M M C.T Restricted E/F relay Figure 13: Differential (Restricted) Earth Fault Protection of Transformer Operation on Fault outside Zone } L L L 18

There will be practically no current in a unit protection relay for an external fault. When unit protection operates, it trips without time delay. In differential protection of transformers: CT ratios and interconnections are chosen so that the currents compared in the relay are nearly equal. Slight mismatch of currents is permitted by the relay design (bias). Transformer magnetisation inrush currents could operate the relay, but restraint is provided on modern relays by using the 100 Hz content. 3.2 Busbar protection Busbar protection is another example of unit protection. The most common relaying principle adopted in the New Zealand transmission system is the high impedance differential scheme, which is a circulating current scheme. The basic principle of busbar protection is that for an un-faulted busbar the total input current is equal to the total output. The sum of the currents is zero for each phase. The relays measuring the summation of the currents receive no current for un-faulted conditions of the busbar. However when a busbar fault occurs, the balance is upset, and the relay receives current causing it to operate. The extent of the busbar and associated equipment protected by busbar protection (i.e. the bus zone ) is dependent upon the position of the busbar protection C.T s. The C.T s may be in the circuit breaker (bulk oil circuit breakers) or adjacent to the circuit breaker. 3.2.1 Check Zones Because the consequences of an incorrect bus zone trip can be very serious a completely independent check zone supplied by separate bus zone current transformers is usually included within a bus zone protection scheme. The check zone encompasses the whole bus and therefore contains both zone A1 and zone A2 in a typical three zone scheme. For a bus zone tripping to occur both differential relays have to respond to a fault e.g. for a fault in zone A1, the zone A1 differential relay and the check zone differential relay. Detecting the fault by two separate relays greatly reduces the risk of accidental trips. For this scheme for a fault within zone A, both the zone A and the check zone differential relays have to operate before a bus trip will occur. In many cases it is not acceptable to remove the whole bus from service. A bus coupling CB can be used to sectionise the bus into two sections. A fault on the bus in zone A1 will be detected in zone A1 and the cheek zone. CBs 42, 52, 62 and 68 will be tripped via their bus zone relays. This leaves the other section of the bus in service. An example of Bus Zone Protection without a check zone is shown in Figure 16. 19

Figure 14: Busbar protection scheme for a single busbar Zone A1 42 62 68 52 82 72 92 Zone A2 Check Zone Figure 15: Bus zone protection scheme for a single bus with bus section circuit breaker 20

Zone A 112 142 172 Bus B Zone B Bus B 132 162 192 Figure 16: Bus zone protection for circuit breakers and a half without check zone 21

In this case a Bus A fault will trip CBs 112, 142 and 172 this will disconnect Bus A without the loss of any supplies due to the Circuit Breaker and a half configuration. The check zone is not essential, as in the case of accidental tripping, no supplies are lost. However, a check zone may be included with a circuit breaker and a half scheme, so always check. The half breakers are not included in either zone and so are not covered by the bus zone protection. 3.2.2 Blind Spots and Blind Spot Protection A fault between 68 and the CT in Figure 17 is in the blind spot of the bus zone protection. NOTE: Blind spots only exist where current transformers are separate from the circuit breakers. This fault in the blind spot will be detected by the busbar protection within the CT zone (zone of detection) and thus the busbar protection will operate the zone A1 circuit breakers 42, 52, 62 and 68 in Figure 17. However, the fault will not be cleared by these trippings (even though the fault current may he significantly reduced). Zone A1 42 62 68 52 82 Blind Spot 72 92 Zone A Check Zone Figure 17: Busbar protection scheme for a single bus with a bus section circuit breaker The fault can be cleared by: Tripping the circuit breakers at the remote ends of the circuits associated with circuit breakers 72, 82 and 92 (no blind spot or CB fall protection 22

or or fitted). This would be a zone 2 tripping and would not clear the fault for approximately 0.65 seconds. By tripping circuit breakers 72, 82 and 92 via the zone A2 trip circuitry (blind spot protection fitted). Blind spot protection in its simplest form is only a timing relay. A fault takes place in the blind spot in Figure 17. Zone A1 and the check zone relays detect this fault. Zone A1 circuit breakers are opened but the fault is still supplied from zone A2 bus. A timing relay is also activated. After a short time, approximately 0.15 seconds, zone A1 and check zone relays are still detecting a fault. As the zone A1 circuit breakers are open the fault must be in the blind spot and zone A2 is tripped by the timing relay. This requires a definite time to elapse, but is much faster than a zone 2 tripping from remote stations. The fault in the blind spot did however clear both sections of the bus. Using CB fail protection The CB fail protection would detect current flowing through the CT adjacent to CB 68, after the CB had opened. This would be taken as a CB failure and a trip signal sent to CBs 42, 52, 62, 72, 82 and 92, to isolate CB 68 which had failed. Blind spot protection is now being removed and replaced with CB failure, as it completes the same function as blind spot protection, as well as protecting against failure of a CB to operate. Blind spots also exist between all other circuit breakers and their CTs. Consider a fault between 42 and its CT. As this is seen as a bus fault zone A1 will trip. The fault will still be supplied from the remote end of the circuit which will trip in zone 2. Other supplies on that bus have been interrupted unnecessarily. Ideally we are only required to trip the circuit on 42, but as the fault was behind the CT it is seen on the bus and not on the circuit. 3.2.3 AC Wiring Supervision Wiring supervision relays are required to detect abnormal voltages on the CT wiring. One - three phase relay is required, per zone. Abnormal voltages can be caused by open circuited CTs, CT isolator switch open while primary circuit is on load, AC wiring fault, etc. If abnormal voltages are detected on the CT wiring then the protection is disabled for the duration of the fault. AC wiring supervision flags are self resetting and generally only evident for a few seconds. 23

3.2.4 DC Supply Failure In older installations a DC supply failure relay (or trip supply supervision relay) is used to detect a D.C supply failure to the bus zone protection. One relay per scheme or one per panel is generally installed. In more modern installations it is incorporated with the bus zone protection inoperative alarms. A loss of D.C supply to the protection will render the protection inoperative. 3.2.5 Protection Inoperative Alarm An alarm is fitted to each separate bus zone to indicate loss of protection. In Figure 17 these alarms are installed for zones A1 and A2. It is not necessary to install a separate alarm for the check zone as a fault in the check zone protection will alarm all zones connected to it. A loss of check zone protection in Figure 17 will alarm both A1 and A2 zones. This alarm can occur due to: Wiring supervision relay operation. The test switch being left in the test position. Failure of the D.C power supplies to the relay. 3.2.6 Circuit Breaker failure (CB fail) Protection When a circuit breaker receives a trip signal, but fails to fully disconnect its associated faulted primary plant within its normal operating time, CB fail protection will be activated. This protection will then attempt to disconnect an adjacent circuit breaker so as to complete the disconnection of the faulted primary plant. CB fail protection shall be enabled only when the protected circuit breaker has been called upon to trip by operation of its associated protection systems. It shall not operate if the circuit breaker fails to open during a routine switching operation or automatic switching sequence unless such failure coincides with or precipitates the development of a system fault, resulting in the operation of its associated protection systems. Remember Busbar protection is a special case of circulating current differential protection (as for generators). It looks more complicated because there are more than two sets of CTs for current summations. When the current entering the busbar is equal to the current leaving, the sum of the currents is zero. Hence the sum of secondary currents is also zero, and the relay is inoperative. 24

If a fault occurs on the busbar, the balance is upset and the relay operates. A second differential relay must also operate for tripping to occur - the busbar check differential relay. Circuit supervision relays cut out the protection after a time delay if there is a slight out of balance of current. A check zone is usually included and the check zone and the faulted zone must detect the fault before a tripping takes place. Bus zone protection is most effective when the bus is in several sections to limit the effect of the tripping. Blind spots exist between CBs and CTs. Faults in blind spots usually remove more equipment than essential from service to clear them. 3.3 Circuit Protection 3.3.1 Distance-time and definite distance protection Distance relays are used to protect transmission lines. As their name implies they measure the distance from the relaying point to the fault, and trip if the measured distance is less than the relay setting. Substation V Generating Source (s) I Figure 18: measurement of distance to fault L = Distance of fault from substation V = Voltage of line at substation I = Line current flowing in the transmission line loop Z = Impedance of the loop L Relay Measurement faulted at F. Z Fault Figure 18 shows two conductors of a transmission line Fault current flows from the substation around the transmission line loop and is supplied via current transformers to the relay. The voltage across the loop is F 25

measured by the line (or busbar VT) to the relay. Providing the resistance of the fault is negligible, the measured ratio Line Volts/ Line Current (V/I) is the impedance of the transmission line loop. Also the loop impedance z is proportional to distance L. Hence a measurement can be made of the distance to the fault. If the measured impedance is less than the set value, it means that the fault is closer to the substation than the distance for which the relay is set and therefore the trip relay will operate. Discrimination Discrimination is provided by using the stepped time distance characteristic, as shown in Figure 19. AB and BC are transmission lines fed from both ends A and C. The relay at A measures the distance to the fault when the fault current flows out from the busbar A into the line, and has the time distance characteristic shown above the reference line 00. Thus for all faults within the first 85% (approximately) of line AB, the circuit breaker at A is tripped instantaneously. For faults further away the relay waits for about 0.5 seconds (zone 2 time), then measures a longer distance zone 2 (say 120% of the line length) and if the fault is measured within this distance, breaker A trips. If the fault continues, a greater distance zone 3 is measured and tripped in still longer time (usually 1.2 seconds for zone 3 trippings). In addition a zone 4 may be fitted that will operate in 4 seconds. Relay B on the line BC has a similar characteristic with tripping time characteristics shown above the reference line 00. Relays at C on the line CB and B on the line BA, measure for faults flowing from right to left on the diagram, and have the characteristics shown below the reference line 00. Consider now a fault at F. Relay A measures the fault as beyond zone 1 but before zone 2 time elapses the fault is cleared at B. (Relay B, facing C, measures and trips in zone 1 instantaneous time.) Note that zone 1 of each relay is arranged to cover about 85% of a line. This is because the distance relays have unavoidable errors in measuring distance. A margin has to be allowed so that faults outside the line are not seen as zone 1 faults. Zone 2 distance covers about 120% (or more) of the line to ensure definite detection of all faults at the end of the line. Zone 3 provides general back up protection (some schemes include a fourth zone for back up.) Importance of Voltage Supply Distance relays measure distance from the current/voltage ratio measurements at the relaying point. Current tends to operate the relay, and voltage to restrain tripping. It is therefore important that VT supplies should always be maintained to distance relays. The absence of VT voltage results in relays seeing an apparent fault, and provided the current is sufficient, the relay trips. Loss of voltage means that the impedance seen by the relay is zero. 26

A - time to operate B - time to operate C - time to operate A A Zone 1 B Zone 2 C Zone 3 B Zone 1 A Zone 2 B C Zone 2 F B Zone 1 A Zone 3 0 0 B Zone 2 0 0 C Zone 1 0 0 Figure 19: distance protection zones C 27

i.e. voltage V = 0 therefore Z = V I = 0 I = 0 Measurement of Direction by Distance Relays For phase to earth, and phase to phase faults, a voltage in a selected un-faulted phase is used as a reference of the direction of the fault (towards the line, or reverse direction). The relay trips in the first two zones for faults out towards the line, but does not trip for reverse faults (behind the busbars). The measurement principle used extensively combines directional measurement and distance measurement in one relay element. (One tripping contact, only closed when direction is correct, and volts/amps measurements conform to settings). Starting Relays Starting relays are used to sense a fault on the system, and start the various relay measurements. If the fault is cleared elsewhere on the system the starting relays reset. (Starting flags do not necessarily mean that a fault has occurred on that particular transmission line.) Impedance relays are generally used on each phase, and are given directional phase angle characteristics for better load carrying insensitivity. The starting relays also select which phases are to be measured, and whether to measure for faults to earth or to measure phase to phase faults. Earth fault relays are used to initiate earth fault measurement. Negative sequence current relays are used in some relays to initiate phase to phase fault measurement, these detect current imbalance in the three phases. Measurement of Three Phase Faults For three phase faults close to the protection relay, all voltages fall very low, and in particular, the phase to phase reference voltage is very low. The reference voltage is the phase to phase voltage which is used to enable the relay to determine in which direction the fault current flows, whether to the line or from the line. Without sufficient reference voltage the relay is unable to trip. One commonly used scheme to overcome the difficulty is to use a memory action. This is simply a resonant circuit tuned to 50-cycles, so that the current in the reference winding persists for a few cycles after the reference voltage has collapsed. Thus with the relay in service, if a three phase fault occurs the relay can determine the direction of the fault. However when the VT s are directly connected to the line, and the line circuit breaker is open, there is no voltage for the relays to remember and the feature cannot operate. This is overcome by arranging a contact to be closed for a short time while the main breaker is being closed. If any starting relay operates, the trip circuit is completed through this contact, and the main breaker is tripped. 28