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6. DISTANCE RELAYS
6.1 Introduction
The operation of distance relays is not governed by the current or power in the protected circuit but by the ratio of applied voltage to current. The relays therefore effectively measure the impedance of the circuit they are protecting. Under fault conditions the voltage is depressed and the current flow greatly increases. The impedance therefore falls during the fault; this is sensed by the distance relay and a trip initiated. Such relays are used on power network overhead lines and feeder cables when the required operating times cannot be achieved by conventional current operated relays. Since the impedance of an overhead line or cable is proportional to its length such impedance measuring relays are known as distance relays or distance impedance (DI) protection.
6.2 Basic Principles
When a fault occurs on a feeder the fault current, If, is dependent upon the sum of the fault impedance, Zf, from the 'relay point' to the fault and the source impedance, Zs
...where E is the line-to-earth voltage.
The voltage at the relaying point is proportional to the ratio of the fault impedance to total source-to-fault impedance.
If the relay is designed to measure and compare both voltage and current then Vf /If =Zf and the relay measurement of fault impedance is effectively independent of the source impedance. If a fault occurs on the feeder a long way from the relaying point then there may be insufficient fault current to operate the relay and the relay will not trip. The point at which a fault occurs which just fails to cause relay operation is known as the 'balance point' or relay 'reach'. This impedance measuring type of relay is the simplest form of distance relay and the relay is set to have a 'reach' sufficient to cover the highest impedance setting likely to be required. A radial feeder arrangement is shown in Fig. 19a. Ideally the relay, R1, would be set to cover faults arising on any section of the feeder from busbar A to busbar B. In a practical situation the accuracy of such a relay setting is insufficient and the reach impedance is usually set to cover 80-85% of the overhead line or cable feeder length in order to ensure that faults outside the zone of protection do not cause an anomalous trip. To protect the rest of the feeder and to preserve discrimination a time delay is introduced into the relay electronics such that a fault on the last 15-20% of the line being protected will still initiate a trip but after a preset time. To give complete back-up protection the relay is adjusted after a further time delay to cover faults on all the following feeders between busbars B and C. This is known as a three-step characteristic covering protection zones 1, 2 and 3. The relay will trip for faults in 'zone 1' in essentially instantaneous zone 1 time.
FIG. 19a Plain impedance relay 3 zone distance protection.
FIG. 19b Modern solid state microprocessor controlled distance impedance
relay: type OPTIMHO (courtesy GEC Alsthom T&D Protection and Control).
6.3 Relay Characteristics
The simple, plain impedance measuring relay has a circular non-directional characteristic which may be plotted on a resistance-reactance (R-X) diagram with the relaying point at the centre as shown in Fig. 20. The reach of the relay is represented by the radius of the circle and the impedance of the feeder being protected is shown as a straight line passing through the origin. A trip will be initiated for any value of impedance falling within the relay trip setting radius. If this relay was used at relaying point B in Fig. 19a a trip would be initiated due to its non-directional nature for faults lying on the feeders between both busbars AB and BC, that is both 'behind' and in 'front' of the relaying point. This plain impedance relay characteristic would not therefore, be used in practice.
FIG. 20 Plain impedance relay characteristic (R-X diagram).
FIG. 21a Directional impedance relay characteristic.
FIG. 21b Mho relay characteristic.
In order to improve on this situation a directional element may be added to the relay such that both impedance and directional measurements have to operate before a trip command is given. The resulting directional characteristic, Fig. 21a, is still not ideal as there is the problem of a possible 'race' between the directional and impedance measuring elements. In addition, when applied to long lines, with relatively high reactance to resistance ratios, the circular operating area to the right of the reactance line can be so large as to cause operation from load currents or under power swing conditions.
Further improvements with directional properties are possible using the admittance or 'mho' relay characteristic as shown in Fig. 21b. The standard mho relay uses the voltage from the faulty phase to derive the directional feature. The operating value of impedance passes through the origin but with this characteristic the reach point setting varies with fault angle.
One problem faced with distance relays is that of fault resistance which may be represented on the R-X diagram as a straight line parallel to the resistance axis for a single end fed line. The arc fault resistance bears no relation to the neutral earthing resistance used in resistance-earthed systems as regards the relay setting value. The neutral earthing resistor value is used to determine the minimum reach of the relay. Arc resistance is empirically proportional to the arc length and inversely proportional to a power of the fault current and as such may well fall outside the zone 1 reach of the relay such that the majority of earth faults are only detected and cleared in zone 2 times.
A number of distance relay characteristics such as reactance, cross-polarized and quadrilateral have been developed to improve the amount of fault resistance coverage.
The reactance relay characteristic is represented by parallel straight lines above and below the resistance axis on the R-X diagram. A combined mho and reactance relay characteristic is shown in Fig. 21c. The mho element of the relay introduces a directional feature and limits the reach of the relay such that tripping on load current is avoided. A practical mho setting would be approximately twice the line length as indicated.
FIG. 21c Combined mho-reactance relay characteristic.
FIG. 22 Cross-polarized mho relay characteristics under different conditions: (i) standard mho characteristic; (ii) cross-polarized mho characteristic, solidly earthed system; (iii) cross-polarized mho characteristic, resistance-earthed system. Zs 5source impedance.
The 'cross-polarized mho' relay uses a voltage for the directional or polarizing feature derived from phases other than those involved in the fault. For example phases R and Y will be used for a B phase fault condition. Therefore the relay has different characteristics for different types of fault condition as shown in Fig. 22. For a three phase fault all phases are affected in the same manner and the relay follows the standard mho relay characteristic. Unlike the plain impedance relay the characteristic is a function of the source impedance as well as the relay setting. The larger the source impedance the larger the operating R-X diagram circle becomes and the greater the fault resistance capacity. For a single phase to earth fault the relay source impedance has positive, negative and zero phase sequence components. For a resistance-earthed system the zero sequence impedance will include a value of earthing resistance equal to three times its nominal value. This will swamp the other sequence impedance components with the effect of moving the centre of the operating circle away from the 2X reactance axis to the 2R resistance axis compared to the solidly earthed system case. The relay may in fact be directional even though the characteristic shown envelopes the R-X diagram origin. For a fault 'behind' the relay the characteristic is different. The cross polarized mho relay has the essential stability of the standard mho relay with regard to power swing and load impedance performance for symmetrical faults. It also provides an improved fault resistance coverage.
Solid state relays have the advantage of being able to produce quadrilateral characteristics with independently adjustable R and X settings and some modern relays have complex polygonal characteristics or even multiple characteristics for differing faults such as mho for multiphase faults and polygonal-shaped ones for single phase to earth faults. Typical resistance settings may be 4-8 times reactance settings allowing for improved arc resistance characteristics and therefore better short-line protection. It is, however, necessary to be careful to avoid anomalous over-reach tripping. On a double end fed system the fault resistance measured by the relay at one end is also affected by the current infeed from the remote end. These two fault current infeeds will make the fault resistance appear to the measuring relay to be larger than it really is. In addition, the fault currents are likely to be out of phase. This makes the measured resistance have a reactive component which can appear either positive or negative on the R-X diagram. If negative a fault beyond the reach of the relay can appear within the relay tripping zone and cause anomalous operation. To help overcome this problem solid state electronic relay manufacturers produce quadrilateral impedance characteristics with an inclined reactance line as shown in Fig. 23.
6.4 Zones of Protection
The settings normally applied to a three-stage distance impedance relay must take into account:
- the accuracy and performance of the associated CTs and VTs;
- the accuracy of the relay calibration;
- the accuracy of the transmission line or cable feeder impedance data.
Consider the radial feeder arrangement shown in Fig. 19a.
Zone 1 setting is based on actual line impedance. Relay R1 at relaying point A is set to 85% of the protected line:
FIG. 23 Quadrilateral impedance relay characteristics.
...
...where ZAB is the line impedance from busbar A to busbar B. The setting should be reduced to suit the accuracy of the relay being used. For a reactance relay line reactance X would be used instead of impedance Z. For a teed feeder 85% of the appropriate distance between the relay and the nearest adjacent relay should be chosen.
The zone 1 time is essentially instantaneous; in most cases it is not actually set but is provided as a basic operating time for zone one at approximately 20-40 ms; older relays may require to be set at 50-100 msec.
Zone 2 settings are arranged to cover the remaining 10-20% of the line AB and should not normally reach further than 75% of the next section of line BC. The minimum setting should be 120% of the protected line and on teed feeders not less than 1.2 times the distance of the further of the remote ends. As explained in sub-Section 6.3 if there is an infeed from both ends of a line or at an intermediate busbar zone 2 reach will be ....
6.5 Switched Relays
As noted above, some relays have more than three zones. The different zone settings may be achieved by using individual relays for each zone or by having one relay and extending its reach after each time interval has elapsed.
Six sets of electronics may be built into the overall distance relay: three for phase faults and three for earth faults. The directional elements detect the direction of the fault such that the relay is only 'started' for faults in the required direction. The use of separate relays is known as a full or non switched scheme and has traditionally been used at the highest transmission voltage levels above 300 kV. However, advances in technology and reduction of costs mean that only such full schemes are available these days, whatever the voltage level.
Projects incorporating existing networks will come across 'switched' systems. In a switched system, one measuring relay is used to cover all types of faults. Starting elements are used to detect the type of fault, which phases are involved and to apply the appropriate voltage and current to the measuring relay and to initiate the appropriate zone time delay. The starting elements may be undervoltage, under-frequency or under-impedance types. When setting starting elements it is necessary to take into account the load impedance and the current in the sound phases during single phase to earth faults.
With modern solid state relays the reliability differences between full and switched schemes have become blurred. The time differences for starter switching operations have also been reduced and selective fault detection using quadrilateral characteristics is easier. Considerable flexibility is avail able and basic distance protection schemes have become cheaper such that their use is justified at distribution voltage levels as well as the more traditional use at transmission voltages.
6.6 Typical Overhead Transmission Line Protection Schemes
6.6.1 Permissive Under-Reach
For a zone 1 fault the relay operates and trips its associated circuit breaker.
At the same time the relay sends a signal via pilot wires or using power line carrier to the remote end of the line. This signal, in conjunction with the already initiated starting elements or some other form of double checking security which avoids false tripping, initiates tripping at the remote end thus completely isolating the faulted section of line. Typical time delays due to transmission and operation of auxiliary relays are of the order of 40 msec.
This is a tenfold improvement over the normal zone 2 operating time (typically 400 msec) of the remote end relay (see Fig. 24).
6.6.2 Zone Extension
In a zone extension scheme the remote end receives a signal which extends the reach of the remote end relay to zone 2 without waiting for the zone 2 timer delay. The zone 2 element confirms a fault and initiates tripping of the remote end breaker. The scheme is slower than permissive under-reach but considered to be slightly more secure (see Fig. 25).
FIG. 24 Permissive under-reaching scheme.
FIG. 25 Zone extension scheme.
FIG. 26 Permissive over-reach scheme.
FIG. 27 Blocking scheme.
6.6.3 Permissive Over-reach
The zone 1 coverage is set to beyond the length of the feeder being protected at, say, 120% line length. For an in-zone fault on the protected feeder both local and remote end relays detect the fault and send a signal to a receiver at the opposite end of the line. The relay tripping contacts are in series with receiver recognition contacts and tripping is allowed (see Fig. 26). For an out-of-zone fault lying beyond substation B but within the 20% over-reach, the relay at substation A detects the fault but not the relay at substation B.
Relay B will receive a signal from relay A but will not operate. Relay B will not therefore send a signal to relay A which in turn will be inhibited. Neither relay will therefore cause circuit breaker tripping to occur. Should the transmission path fail the scheme will still operate in zone 2 time with an over ride of the receiver contact.
6.6.4 Blocking
Forward and reverse 'looking' distance measuring relays are required at each end of the line and set to approximately 120% line length coverage. For an in-zone fault both relays 'see' the fault, no signal transmission is required to take place, and the circuit breakers at each end of the line operate (see Fig. 27). For an out-of-zone fault lying beyond substation B but within the 20% over-reach, the relay at substation A will detect the fault. Its tripping operation will be inhibited by receipt of a signal from the reverse looking relay at substation B. The scheme introduces a slight time delay due to transmission times and auxiliary relay operating times. The advantage of the scheme is that when power line carrier signaling is used the 'blocking' is achieved by trans mission of the inhibit signal over a healthy rather than a faulty line.
FIG. 28 Phase comparison principles.
6.6.5 Phase Comparison
High frequency signals are transmitted between substations A and B as shown in Fig. 28. These signals are arranged to be sent in bursts only during the positive half cycles of the power frequency current. The continuity of the combined signals generated is monitored. Under fault conditions attenuation of signals over the associated faulted lines or those lines carrying fault current is likely. This scheme does not rely upon magnitude of received signal but its continuity.
Consider the case of an internal fault on line AB between substations A and B. The power frequency fault currents entering the zone of protection at A and B will only be slightly out of phase. Upon detection of the fault both ends will therefore transmit an intermittent signal simultaneously which, when combined, will still consist of bursts. The relays at substations A and B are arranged to initiate tripping under these conditions.
Under external out-of-zone through fault conditions the current is entering at one end of the line and leaving at the other. The power frequency fault currents at substations A and B will therefore be displaced by approximately 180-. The high frequency signals generated at each end of the line will now, when combined, form a continuous signal. The detection circuits are arranged such that under reception of such a continuous signal tripping is inhibited.
6.6.6 Auto-Reclosing
Records indicate that 80-90% of overhead line faults are developed from transient causes such as lightning strikes or objects coming into contact with the lines. Service may be preserved and system stability maintained by rapid fault clearance and re-energization of the line. The theoretical minimum dead time between reclosing attempts are only of the order of a few cycles.
To this must be added:
- The actual circuit breaker operating time. When 'multi-shot' schemes (repetitive reclosing usually followed by a 'lock-out' command to inhibit further attempts) are designed the dead time is increased above the single shot requirement in order to take into account circuit breaker recovery times and ratings.
- A de-ionization period to allow for the dispersal of ionized air around the fault path is of the order of 10-20 cycles depending upon voltage level.
- When electromagnetic IDMTL protection relays are used in conjunction with auto-reclose schemes it is essential to allow full resetting during the dead time before the next circuit breaker closure attempt. This is of the order of 10 s or more and sets a limitation for auto-reclose dead times on distribution systems with simple current operated protection relays.
- The reclaim time must be sufficient to allow the protection to operate correctly on a persistent fault. Again for IDMTL relays this could be up to 30s under low fault level conditions. For definite-time protection 3s reclaim times or less are common practice.
- The auto-reclosing timer and trip relay must provide a circuit breaker trip signal sufficiently long enough to allow the circuit breaker motor wound spring charge, hydraulic or pneumatic mechanism and solenoid closing to be correctly initiated. This is of the order of 0.1-1 s. Once initiated a practical spring charge mechanism may take 30-60 s to complete spring charging.
FIG. 29 Basic circuit breaker trip initiation schemes.
7. AUXILIARY RELAYS
7.1 Tripping and Auxiliary
In order to trip circuit breakers and operate alarms more than one relay con tact is usually required. In addition, the relay contacts may have to be rated to carry heavy and highly inductive currents. This requires large contacts and high contact pressures. Tripping relays are therefore used to multiply the number of contacts available, provide isolation between the source and sys tem operating element and to meet the required duty. Examples of basic circuit breaker tripping schemes are given in Fig. 29. The disadvantage of intermediate tripping relays is that they increase the overall fault clearance time by adding another stage in the fault clearance sequence. Therefore alternatives such as opto-isolators, reed relays and solid state switches may be considered to provide good isolation and faster responses.
Changeover 'all or nothing' relays may be divided into auxiliary and trip ping classes. Tripping relays must have the following characteristics:
- Fast, with less than 10 msec operating times.
- High operating contact ratings to operate circuit breaker trip coils.
- Mechanically stable and shock resistant.
- Must not be prone to maloperation.
- Have provision for a visual 'flag' or operation indicator in the relay case.
Relay contacts are referred to as being 'normally open' (n.o.) or 'normally closed' ( n.c.) in the normal unenergized state. In order to understand schematic diagrams it must be emphasized that this n.o. or n.c. state has nothing to do with the usual state of the relay when included in its particular circuit.
For throwover or bistable relay contacts the convention is for illustration in the state which will apply when the initiating device is in the normally open state. For circuit breakers the auxiliary switches are shown with the circuit breaker main contacts in the open position. Standard symbols for these contacts and different types of relays are illustrated in Section 2.
IEC 60255 'Electrical Relays' give the following nominal DC relay coil voltages: 6 V, 12 V, 24 V, 48 V, 60 V, 110 V, 125 V, 220 V, 250 V and 440 V.
The IEC preferred working voltage for all or nothing relays is 110-80% of nominal. The systems designer should be careful when matching battery sys tem and relay coil voltages. A 110 V nominal DC system when using Plante ´ lead acid cells will have a float charge of some 124 V DC. Therefore 125 V relay coils should be used and not 110 V coils. In addition, the substation battery voltage at the end of the discharge period could well be below the 80% minimum. British Electricity Supply Standards have recognized this and an assured trip operation at ,53% of rated voltage is specified. This is a difficult or at least unusual requirement for many manufacturers to meet and is probably over stringent. For general application it is prudent to stick to the IEC duty range of 70-110% to avoid the risk of excessive tender prices. Additional assurance can be achieved by slightly oversizing the substation battery.
It is essential that the trip circuits do not mal-operate owing to earth fault currents.
In the circuit shown in Fig. 30 an earth fault on the wire between the protection relay contact and the trip relay could cause current to flow through the relay as the wiring capacitance on the negative side of the battery discharges. In a transmission voltage substation there is a large amount of secondary wiring permanently connected to the substation auxiliary supply battery. Therefore a standard test for a tripping relay is that it should not operate when a 10 µF capacitor charged to 150 V is connected across the relay coil. If the substation battery centre point is resistance-earthed then there is also another path for current to circulate. It is usual to size this resistor to limit the maximum earth fault current to about 10 mA. As very light duty auxiliary relays will certainly operate at this current level they should not be used in protection trip schemes if spurious signals are to be avoided.
A typical trip relay is illustrated in Fig. 31. The attracted armature relay is used for high speed operation (20-40 ms) at high current levels. In order to avoid damage to the protection relay contact if it has to break the trip relay current or sustain it for a long length of time a self-cut-off contact is incorporated which breaks the coil current when operation is complete.
For self-reset relays an 'economy' resistor is placed in series with the coil to limit the current once the relay has operated.
FIG. 30 Effect of earth faults on trip relay operation: (a) typical shunt
reinforcing contactor system; (a) Typical shunt reinforcing contactor circuit;
(b) earth leakage path. (b) Earth leakage paths
Trip relays may be divided into two classes:
1. Lock-out trip relays. Used to ensure that once a circuit breaker has been tripped by the protection scheme it cannot be reclosed either manually or automatically until the trip relay has been reset. The reset function may be either manual or electrical.
2. Self-reset trip relays. Useful for auto-reclose schemes.
Some typical relay characteristics are detailed in Table 2.
FIG. 31 Attracted armature relay type MVAA (courtesy GEC Alsthom T & D
Protection & Controls).
7.2 AC Auxiliary Relays
Since small and reliable silicon diodes are available it is nowadays common practice to rectify the AC and use ordinary highly reliable DC relays. If AC relays are used the design must take into account the fact that the holding flux in the armature will fall to zero every half cycle. Small copper shading rings are sometimes employed to cause a phase shift sufficient to damp any flux reversal vibrations or relay chatter.
7.3 Timers
Highly accurate solid state timers are available by using digital electronics to divide down and count pulses from a known standard. The time delay may be derived from 50 Hz or 60 Hz mains, a simple free running RC oscillator, an internal piezo electric quartz crystal oscillator, reception of a calibrated radio beacon or satellite transmission. Setting ranges of 0.02 to many hours may be obtained with an accuracy down to less than 0.3% of the set value.
TABLE 2 Performance of Some Trip and Auxiliary Relays
Clockwork, wound spring mechanisms and synchronous motors have also been used in the past with 10 to 1 timer ranges and 5-10% accuracy levels.
The delayed reset relay is arranged to change the state of the output contacts immediately upon energization. It will also allow a preset delay period of time to elapse before change of state on loss of supply. The delayed operate timer relay allows change of state of its output contacts after some adjustable preset period following energization of the coil.
Simple diodes or RC networks may be applied in order to relays to slow down operation. Some circuits are shown in Fig. 32. The application of these delays helps prevent 'races' between circuits operating at slightly different speeds. A mechanical dash pot damper device is also used on some 400 V distribution air circuit breaker operating mechanisms.
FIG. 32 Diode and RC circuits used to provide short-time delays (200
ms).
7.4 Undervoltage
DC undervoltage relays are used to provide continuous trip circuit supervision or main substation DC distribution voltages. AC undervoltage relays are used to protect large motors from damage that could occur from running at low voltage, in mains failure monitors and in VT secondary circuits. Again, solid state relays offer advantages over older electromechanical types in terms of accuracy and have typical drop-off and pick-up voltage settings within 1% of each other with out cost penalty. Specifications should cover the following points:
- Single or adjustable setting.
- Setting or setting range required.
- Instantaneous- or time-delayed operation.
- Single-or-three phase supervision.
- Resetting ratio or adjustment range required.
7.5 Underfrequency
Underfrequency relays are applied to generation plant to avoid fatigue or excess vibration when running outside synchronous speed. The relays operate in con junction with load shedding schemes in order to quickly bring the generation back into synchronism and up to speed. Digital electronic underfrequency counter relays divide down and compare the supply frequency with an internally derived stable clock reference. A delay is incorporated in order to prevent anomalous operation under transient conditions (DC offsets under fault conditions, harmonics, voltage dips on large motor starting, etc.). The advantage of the underfrequency relay is that it may be installed almost anywhere throughout the network and wired to initiate tripping of particular loads on a customer's premises. In contrast, telecontrol methods tend to operate out to primary substations rather than customer's premises and therefore are less selective in the particular loads shed. The characteristics required are explained in Section 1. A useful formula for designing a load shedding scheme is:
...where H=total system inertia, MJ L=system load, MW G=system generator output, MW ft =frequency at time t following load or generation change fo 5initial frequency t=time in seconds following disturbance
Fig. 33 shows a typical set of time-frequency curves for various degrees of system overload with underfrequency relay trip setting points at 49 Hz and 48 Hz. Several stages of load shedding are established in order to minimize outages whilst maintaining system stability. The load shed should always slightly exceed the theoretical minimum required in order to avoid further, more drastic stages of shedding. A time delay between stages is necessary such that the effect of the first load shedding (which will take several hundred milliseconds depending upon circuit breaker operating times, generator inertia and generator governor response) can be determined before the second stage is started. On a large steam generation system up to five stages of load shedding may be applicable, whereas on a single gas turbine or light diesel installation only one or two stages with 300 ms delays might be applicable.
FIG. 33 Underfrequency load shedding curves.
FIG. 34 Protection grading exercise: network single the diagram.
8. COMPUTER-ASSISTED GRADING EXERCISE
8.1 Basic Input Data
Consider the simple 11/3.3/0.415 kV distribution network shown in Fig. 34. It is necessary to derive suitable protection settings and grading margins for the network. The fundamental formulae for determining network impedance parameters on a similar base is given in Section 28, Section 28.7.2. The basic input data and protection requirements are as follows:
- 11 kV source fault level5500 MVA.
- The fault contribution from large motor loads is ignored in this example.
See Section 1, Section 1.3.6 for the effects of simplifying assumptions concerning induction motor loads and Section 14, Section 14.3.9 for a sample calculation taking induction motor fault contribution into account.
- The protection must only disconnect from the power source the minimum of faulted plant such that services to other users or loads are maintained.
8.4 Relay Settings
The characteristics of the relays and fuses are held on a data file and loaded into the computer. The chosen CT ratios are then entered into the computer.
A reference voltage is selected and all protection device characteristics are plotted on a log-log time-current scale at the reference voltage. With a simple computer assisted grading program the operator can 'move' the relay characteristics on the screen to give the required discrimination margin between successive protection devices. The required plug setting multiplier (PSM) and time setting multiplier (TSM) to give this margin can then be read off from the computer screen.
For the relay R1 located on the primary side of the 11/3.3 kV transformer a PSM of 100% (i.e. 500 amps) is chosen with a TSM of 0.1 s to discriminate with the 500 kW, 3.3 kV motor fuse.
For the relay R2 located on the primary side of the 3.3/0.415 kV trans former, a PSM of 150% (i.e. 375 amps) is chosen with a TSM of 0.1 s to discriminate with the 150 kW, 0.415 kV motor fuse.
Fig. 35 is an example of computer generated grading curves associated with this example.
FIG. 35 Computer generated grading curves.
9. PRACTICAL DISTRIBUTION NETWORK CASE STUDY
9.1 Introduction
This section shows how the principles and the different types of protection are used on an actual distribution network. The network chosen for this purpose is the Channel Tunnel power supply network which embodies a traction supply system and a reconfigurable distribution network. The traction supply system feeds a 25 kV single phase to earth 2,500 A catenary to provide the power to the electric locomotives which haul the international Eurostar trains as well as the special shuttle trains operated by Eurotunnel.
The distribution system is required to support the requirements of the passenger terminals at Folkestone and Coquelles as well as the auxiliary ser vices of the tunnels, such as ventilation and cooling.
To ensure the highest level of security for the power infeed to the tunnel system, the power demand is shared approximately equally between the French and British power systems. The connections to these power systems are at 400 kV to minimize the effects of unbalance and harmonics and then transformed to 225 kV for the French infeed and 132 kV for the UK infeed.
These grid infeeds supply main high voltage substations on each side of the Channel. It is in these substations that the segregation of traction and auxiliary systems occurs.
9.2 Main Substation Protection
The main substations on both sides of the Channel are fed from the main grid system by underground cable circuits. On the French side the cables operate at 225 kV and are approximately 2.5 km in length. These cable circuits are protected by a pilot wire scheme using one pair of pilots to transmit a signal proportional to the three phases. On the UK side the cable circuits operate at 132 kV but the feeder length is approximately 14 km. Because of the high capacitance of the charging currents these circuits are protected by three independent pilot wire protection schemes on a phase-by-phase basis.
The 225 kV busbars at the French main substation are protected by a modern electronic type of busbar protection with monitoring systems. The 225 kV system is also fitted with circuit breaker fail protection initiated by all main protections which causes back tripping of the busbars if the current has not ceased within a preset time of the tripping request.
The 132 kV busbars are protected by a high impedance circulating cur rent busbar protection scheme. This scheme utilizes two sets of current trans formers on each circuit for check and discrimination relays as described in Sub-Section 5.5.3. The UK system is also fitted with circuit breaker fail protection.
The auxiliary transformers (225/21 kV) in the French main substation are protected by Buchholz and frame leakage earth fault protection. The frame leakage protection on the transformers works on the same principle as the busbar protection system described in Sub-Section 5.5.2. The transformer tank is insulated from earth and only one connection via a frame leakage current transformer is provided. On the UK side these transformers (132/21 kV) are protected by biased differential protection as described in Sub-Section 5.1.2.
The transformers are basically the same, however; the difference in the protection used reflects the different philosophies applied in France and the UK.
The 21 kV busbars in both the French and UK substations are protected by high impedance busbar protections using check and discriminating zones as used on the 132 kV busbars.
The protection on the other circuits in the main substations is described under the traction system or 21 kV distribution system in the following sections.
FIG. 36 Traction protection characteristic.
9.3 Traction System Protection
On the French side, there are three single phase transformers, one dedicated to each phase with a fourth transformer suitable to replace any phase. These transformers are also protected by Buchholz relays and frame leakage earth fault protection with a high set overcurrent protection.
On the UK side because of the interaction with a specially designed load balancer, it is necessary to feed the traction system by three 132/43.3 kV star zigzag transformers. These transformers are protected by biased differential protection as described in Sub-Section 5.1.2 with IDMTL overcurrent and earth fault backup.
The catenaries have to be capable of delivering up to 2,500 A of load cur rent whilst the maximum fault current is limited to 12 kA. This means that the minimum fault current when feeding the full length of the tunnel from one side in downgraded conditions can be lower than the load current. The catenaries are protected by a special distance protection which develops a parallelogram-shaped characteristic with adjustable angle by the use of phase comparators (see Fig. 36). This ensures correct detection of the low fault currents compared to the high load current. The protection also incorporates an overcurrent element and a thermal overload alarm.
However, as the overcurrent relay cannot provide a full back-up for low levels of fault current, second distance elements have been added. On the French side these are fitted on the low voltage side of the traction transformers and act to trip the appropriate phase traction transformer. On the UK side, the second elements are fitted on the catenary circuits but with a breaker fail system operating from the catenary circuit breakers to back trip the traction transformer infeeds.
9.4 21-kV Distribution System and Protection Philosophy
The auxiliary distribution system operates at a nominal voltage of 21-kV.
The terminal systems being ring main on the UK side and radial with interconnection at the end of the French side. These systems are pro vided with overcurrent and earth fault protection applied as described in Sub-Section 4.5.1.
FIG. 37 Tunnel distribution system showing main and back-up protection.
For the tunnel distribution system, the security of the system has been of considerable concern. The basic system is illustrated in Fig. 37. Within the tunnel 21 kV distribution system, the system can function satisfactorily with the loss of two circuits. The distribution system consists basically of four circuits, two of which are used to feed the pumping stations (PS) and two which are used to feed the electrical substations (ES) in the tunnel. The electrical substation feeds are split at substation 7 which is approximately the centre of the tunnel, whilst the electrical substation feeds are split at Coquelles on the north feeder and Folkestone on the south feeder. The cooling plants which are considerable non-priority loads are connected at Shakespeare Cliff North and Sangatte Shaft South, and two additional feeders are connected from the main substations to these busbars. The system is normally run split as indicated but, on loss of total infeed from either France or the UK, the normally open circuit breakers are closed and the system run solid from the healthy infeed side.
On this system, it is important that faults are cleared quickly and that uncleared faults do not persist. This has led to the use of main protection typically of the unit type with separate back-up protection usually in the form of overcurrent and earth fault protection. The 21 kV busbars at all switching locations are provided with high impedance busbar protection, basically as described in Sub-Section 10.5.5.3 but without a check zone. The larger transformers are fitted with differential and restricted earth fault protection with overcurrent and earth fault backup.
The transformers used to feed the cooling plant 3.3 kV busbars, however, do not use restricted earth fault protection. This is because the 3.3 kV earth fault current is limited by an earthing resistor to 30 A, and with a transformer rated at 12.5 MVA with line CTs of 2,500/1 A it is impossible to achieve satisfactory sensitivity under these conditions. In this case frame leakage earth fault protection has been used as described for the French auxiliary and traction transformers.
The cable circuits are equipped with pilot wire protection as described in Sub-Section 10.5.4 as the main protection. On the pumping station feeders and interconnectors, these are straightforward two-ended pilot schemes. On the electrical substation feeders, the pilot wire protection covers the sections between the major bussing points (ES3, 5, 7, 11, 13) and has to make allowance for the tee-offs in between. The special aspects of the pilot wire protection are discussed in the next section. Fault clearance within 300 msec was the target for the main protection to ensure back-up fault clearance times able to provide full thermal protection of the equipment could be achieved.
Back-up overcurrent and earth fault protection (refer to Sub-Section 4.5.2) are graded to minimize the amount of system lost in the event of the main protection failing to clear the fault. This requirement is complicated by the different configurations required for normal split operation, solid down graded operation fed from either France or the UK or the modified split arrangement used when operating with the much lower fault infeeds avail able from the standby generators. This aspect is discussed in detail later.
9.5 21-kV Pilot Wire Unit Protection
A number of constraints were encountered in applying pilot wire protection to some of the 21 kV feeder sections, which arose from the following system aspects:
1. High in-zone charging current (longest section is 13.6 km).
2. Limited earth fault current (resistance earthing) and low overall fault level with emergency generators.
3. In-zone, fuse-protected, transformer tee-offs on the electrical substation (ES) feeders.
Considering the way in which the pilot wire protection sums the healthy phase in-zone charging currents for an external earth fault on a resistance earthed system, the overall sensitivity of the pilot wire protection was adjusted to give a 20% stability margin with respect to the operating quantity generated for the most onerous external PH-E fault. This margin allows for system operation at above nominal voltage and for measurement errors with out imposing practical sensitivity limitations for all types of internal fault.
Multi-terminal pilot wire protection schemes were ruled out in terms of performance and complexity because of security/reliability concerns. It was decided to apply pilot wire protection with an operating time characteristic that would co-ordinate with fuse operation for a fault on any in-zone trans former. The protection also has to be stable for aggregate magnetizing inrush current in the case of multiple transformers. To meet the latter requirement, the manufacturer's recommendation that the aggregate teed transformer load current should not exceed 50% of the protection three phase fault sensitivity was adhered to.
The pilot wire relays could have been applied with external definite-time delays to co-ordinate with the transformer fuses, but the allowance for an unpredictable pilot wire relay reset time, following fuse clearance of a transformer fault, would have created unacceptably high back-up protection operating times. Interlocking the pilot wire protection with suitable IDMT overcurrent relays at each end of a feeder section was also ruled out since breaker tripping would be prevented at both ends of a faulted feeder section in the normal case of single end feedings. Double end tripping is necessary to ensure that a fault cannot be reapplied when a supply is rerouted following a fault. The best compromise was to utilize a pilot wire relay design where the measuring element itself produces an adjustable operating time characteristic. The way in which this grades with the transformer HV fuse is illustrated in Fig. 38.
Under normal operation, the earth fault level (1 kA) is high enough to give P/W relay co-ordination with the transformer fuse protection. However, it can be seen from Fig. 38 that for low level earth faults full co-ordination cannot be achieved because of the constraints on overall pilot wire sensitivity dictated by co-ordination between transformer fuse protection and back-up protection for HV and LV phase faults. For this reason earth fault relays have been fitted to the transformers to give remote indication if a transformer earth fault causes the pilot wire protection to operate, thus allowing rapid reconfiguration.
FIG. 38 Example of 21-kV protection grading.
9.6 21-kV System Back-up Protection
Sets of microprocessor-based, directional, time-delayed, overcurrent and earth fault protection were strategically located at the positions indicated in Fig. 37.
The use of modern, multi-characteristic, microprocessor-based relays pro vided great flexibility and significant advantages when the relay setting study was carried out. Project lead times were also reduced since contract work could commence before the protection study had been completed in detail. In selecting the type of back-up protection, significant service experience was an important consideration, in addition to economic and technological factors.
In setting phase fault protection, with supplies from one or both countries, three forms of dependent-time (IDMT) relay characteristic were utilized on the multi-characteristic relays. The reduction in phase fault levels away from the intake substations meant that discrimination between feeder relays in the tunnel could be maintained without infringing a 12.5 kA/1 s damage constraint at the main intake substations.
In the cases where one intake substation (S/S) feeds the whole tunnel, with the remote ends of tunnel feeders tied together, natural discrimination is exhibited by IDMT relays on contributing feeders with those on a faulted feeder, even if some have similar settings.
As the system is resistance-earthed, earth fault levels do not vary significantly with fault location, and the earth fault current is restricted to 500 A per supply transformer. This meant that it was possible to set up relays with definite-time E/F characteristics to provide discrimination without infringing a cable-screen constraint of 1 kA/1 s. IDMT characteristic grading with the limited earth fault current was not feasible since the relay currents would include a significant, variable, neutral charging current component.
The high accuracy, low overshoot time and consistency of electronic protection, coupled with high speed SF6 breakers, were factors fully exploited in determining the minimum grading margins. It was necessary to adopt:
Dependent-time relay margin=0.2t+0.135s
Definite-time relay margin=0.06t+0.135s
...where t(d) is the downstream relay time.
To ensure full discrimination of phase and earth fault back-up protection, in the case of one national supply only, it is necessary for protection settings to be modified at the remote intake substation to give a faster response. It is also necessary effectively to adjust the definite-time delay of some sets of earth fault protection within the tunnel. Fig. 37 indicates where and under what circumstances protection settings are effectively altered.
For operation with supplies from emergency generators only, additional back-up protection setting changes are required at the intake substations and also at Shakespeare Cliff and Sangatte Shaft. Under such circumstances it is more appropriate for the O/C relays at these locations to have definite-time characteristics and more sensitive settings, to ensure that the protection will respond to the limited generator fault current contribution with its decrement.
Earth fault protection also needs to be made more sensitive at these locations.
Where setting modifications are required for O/C and E/F protection, mainly at the intake substations, the setting changes are brought about by switching between two or three sets of protective relays; relay selection being under the control of electrically operated/reset latching relays with contacts acting on control terminals of the protective relays. Where it is necessary only to alter the definite-time delay of earth fault protection, for example within the tunnel, this is accomplished by the selection and insertion of external time delay relays; again under the control of latching relays. The latching relays are switched by a common command from the control centre which trips circuit breakers, load sheds and sets the protection in readiness for the appropriate configuration.
9.7 Use of Earth Fault Indicators
On the electrical substation (ES) feeders, because circuit breakers are not fit ted at each substation, it is necessary to identify the location of a fault quickly so that the system can be reconfigured, by opening disconnect switches, and re-energized. This is achieved by installing strategically located earth fault passage indicators. The same technique has also been used on the 3.3 kV distribution system, which also uses ring main units.
The indicators, and their associated core balance CTs, are custom built to ensure an operating current of less than half the minimum system E/F level, but in excess of three times the normal charging current for the longest length of cable that could be fed downstream of an indicator (to prevent sympathetic operation on a healthy feeder). The indicator design operating currents are 150 A for 21 kV and 15 A for 3.3 kV. A contact and a DC reset coil have been provided on each indicator to allow remote indication and resetting, via telecontrol, in addition to the local facilities.
9.8 Summary
It can be seen how, in a complex distribution network such as that of the Channel Tunnel, each of the different protection principles described in the earlier sections of this Section has a part to play in providing high speed selective and reliable protection:
- Current operated relays with differing characteristics to provide main protection in the terminal and back-up protection in the tunnel.
- Differential protection schemes in the form of busbar protection, restricted earth fault, biased differential transformer protection and plain and biased pilot wire schemes for cable protection.
- Distance protection to protect the traction system catenary with a specially shaped parallelogram characteristic to give the discrimination between low fault current and high load current.
- Tripping and auxiliary relays used for protection switching.
10. RECENT ADVANCES IN CONTROL, PROTECTION AND MONITORING
10.1 Background
Substations contain amongst other systems, subsystems specific to control and protection. They are:
1. Control panels with:
- control switches for manual control;
- annunciators and lamps for alarms;
- selector switches and meters for metering of current, voltage, power, energy, etc.;
- recorders for trend monitoring and historical logging.
2. Relay panels with:
- protective and auxiliary relays, suitably arranged;
- fault and event recorders for fault analysis and logs.
3. Communication panels that provide interfaces to the PLC communication system.
4. RTU panels which:
- digitize binary and analogue information from the substation for transfer via the communication system to the SCADA control centre;
- execute control commands from the control centre.
5. Interface panels to provide level of interface and isolation between engineers from the SCADA communication, protection and operations department of a utility.
Conventionally all this equipment gets interconnected with miles of cabling, which results in lengthy engineering and testing processes during the substation installation stage. In modern substations new technology has been implemented to increase the reliability of the installation as well as reduce its size and cost. To this end, a large amount of integration has taken place in the above systems and products, shrinking the footprint and reducing the overall complexity.
10.2 Developments
Integration has resulted in the terms such as relays, control panels, etc. being replaced by the term Intelligent Electronic Device (IED) and Substation Automation (SA) systems (see Fig. 39).
FIG. 39 IED with a modular concept (courtesy of ABB Ltd., UK).
FIG. 40 Example of an IEC 61850 based station (courtesy of ABB Ltd.,
UK).
A substation engineered on this basis would have one or a number of such IEDs per HV bay connected to the process (CT, VT, CB, isolator, ...) on one side, galvanically and communicating via an optic digital Ethernet bus to a computerized control and monitoring (SA) system on the other side.
The control system also communicates upwards to the SCADA system at the control centre via fiber optic or other channels. In some installations, security and operational reasons dictate the segregation of control from protection.
An IED today is a compact cost effective product that could cover protection, local control, recording, monitoring and communication all in one box.
Communication standards such as IEC 61850 ensure that the communication protocol and format is standardized across various vendors paving the way towards IED inter-operability and, it is to be hoped, IED inter-changeability in the future.
All of this reduces the number of panels and the wiring. Furthermore, the IED is 'multi-function' and it is not uncommon to have a large number (20-30 or more) of protection functions in one device due to its high processing capacity. Self-supervision and watchdog functions ensure high availability for such devices (see Fig. 40).
Some of these IEDs, with special functions such as line differential, are even provided with built-in geographical positioning system (GPS) cards to achieve highly reliable microsecond accuracy time stamps of internal signals at source. This is a prerequisite for accurate and reliable line differential protection and advanced monitoring applications.
Such systems will in future include optical data communication to 'optical' CTs and VTs (see also Section 5), intelligent breakers, etc. with the ultimate result perhaps of moving towards a substation with 'copper less' controls and protection.
REFERENCES
1. Electricity Training Association. Power system protection, vols. 1-4. Electricity Association Services, London: IEE; 1995.
2. IEEE recommended practice for protection and coordination of industrial and commercial power systems. IEEE Press; 1991.
3. Protective relays, application guide. Stafford: GEC Alsthom. T&D Protection & Control; 1995.