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NE9270 Manual

1. 23 23 A Internal Earth Fault B External Earth Fault Q Relay Figure 121 Zero Sequence Current Filtering For an internal earth fault on the star winding side of the transformer equal co phasal 11 15 lo components of current flow into the fault circulates through the earthed star point of the transformer but and 1 are supplied on the primary side from the Grid supply As no currents flow through the secondary CTs of the transformer it is 1 and 15 components of current on the primary side that cause the relay to trip For an external fault on the secondary side of the transformer the lo component circulates as before through the star point of the transformer but the secondary CTs see all three components of current 11 and lg However the primary CTs of the transformer only see the 1 and components There is therefore imbalance in the currents circulating between the primary CTs and the secondary CTs and the relay trips Hence the need for zero sequence filtering on the secondary side of the transformer On a low voltage delta side the zero sequence line current is automatically filtered out based on the mathematical phasor operations This is not always necessary and also not always desirable but is always the result of any subtraction of two phase current phasors Tripping Characteristic After the currents of the individual ends of the transformer have been ma
2. 290 8750 Figure 83 Circuit Diagram Analysis ofa Line to Ground Fault on an Elementary Power System Load Current Neglected The analysis for each type of fault may be represented by a specific interconnection of the sequence networks for the system from which fault currents may be determined Figures 82 and 83 illustrate the analysis of a line to ground fault on an elementary power system Note that the load current is neglected i e system and the load impedance beyond the fault point are not shown Page 115 NE9270 Power System Simulator For the transformer and line the rated current is 6 x 35v 32 10 0 1 x 132000 _ 262 x J3 01 puZ 290 Total impedances referred to 132 kV 60 MVA 21 1220 7 110 50 Zo 116 5 0 132000 x 1 10 zu EC Kc CX cC J3 122 110 5 116 5 51 1 1 1 218 218 218 654 Page 116 NE9270 Power System Simulator Experiment 9 Unsymmetrical Faults Experimental and analytic studies of varying degrees of complexity can be carried out on the Power System Simulator for a variety of faults for example line to ground line to line line to line to ground and open circuit The following are a few examples of experiments that can be carried out The connection diagrams for Parts A B C and D are given in Appendix 3 Outline descriptions are given below In all cases the values measured are to be comp
3. 0 1 000 0 9 e TIMED FAULT MANUAL FAULT CB CB 1 0 1 TP7 b TP19 a b a 1V 40V b b a b PROTECTION RELAYS e wo RESET LAMP TEST BLOCKING ACTIVE CURRENT RANGE HIGH 1V 10 LOW 1V 2 MM TRANSDUCERS Figure 30 Central Test and Control Facilities on the Power System Simulator Page 50 NE9270 Power System Simulator 4 1 Connections and Links Four core cables three phase and earth connect the components on the Simulator panel The cables are of large diameter and have a gold plated four pin plug at each end to keep the resistance low At every point of termination of a line the cable plugs are inserted into four pin sockets black square base in the panel of the Simulator The sockets are shown in the various component diagrams in Section 2 There is only one way to insert the cable plugs into the sockets insert the plug into the socket and rotate the plug clockwise until its locking catch clicks into place To remove the plug slide the locking catch backwards and turn the plug anticlockwise until you can remove it The cables are supplied in several lengths to connect the lines and components together However to avoid long lengths of cable trailing across the front of the Simulator four links have been included on the Simulator panel running parallel to the transmission lines The links are simply c
4. Jamod peeds Figure 154 Control Circuit for the Vector Drive Page 227 NE9270 Power System Simulator Relay Override and Enable Buttons Grid Transformer Relay P632 e Grid Overcurrent O C Override O R Grid Diff O R Grid Standby Earth Fault E F O R Grid Restricted E F O R Gen 1 Relay P343 Stator E F O R e System Backup O R Neg Phase Sequence O R e Gen Diff O R Overvolts O R e Under Over Frequency Hz O R e O C I O R O C gt gt O R Rev Power O R Distance Relay P442 e Distance Override Busbar Protection P142 2 e Bus A O R e Bus B O R Distribution Bus P142 4 e RDIA D1A IDMT O R DIA Inst O R RDIB IDMT O R Inst O R D1B Bk Trip Enable RD2A D2A IDMT O R D2A Inst O R RD2B IDMT O R D2B Inst O R D2B Bk Trip Enable and Auto Reclose Grid Bus P122 e Overcurrent Override Generator Bus P122 e Generator Overcurrent Override Page 228 NE9270 Power System Simulator Micom Relays Programmable LED Assignments P632 Grid Transformer FT RC ld gt Triggered LED 1 Zone 1 P442 Distance Protection FT RC IR gt STriggered LED 2 Zone 2 IDMT 1 lref gt Starting A LED 3 Zone 3 IDMT 1 lref gt Starting B LED 4 Zone 4 IDMT 1 lref gt Starting C LED 5 Distance Trip A IDMT 2 Starting LED 6 Distance Trip B Ref 2 Trip LED 7 Distance Trip C Diff Trip LED 8 Any Sta
5. node or busbar to system impedances and voltages At each node there are four variables P V 6 To solve the equations two of these variables must be specified at each node At a generator node the P and V are specified and Q and 8 are unknown at a load node P and Q are specified V and 6 being unknown At the slack node or reference node V and are specified The slack or swing bus takes up the slack in the system due to unknown line loses Since the equations are non linear numerical methods of solution are required the two most commonly used being the Gauss Seidel GS method and the Newton Raphson NR method To solve the equations the following data must be available a The impedances between nodes and admittances to ground b The active power generated and or consumed at all buses but one C reactive power consumed at all load buses d The voltage magnitude at all voltage control buses e The magnitude and angle of the voltage at one node of the network the reference bus Page 96 NE9270 Power System Simulator Experiment 7 Load Flow Study It is possible to set up on the Simulator a system as shown in Figure 67 Gen 1 Bus Switched Load l Figure 67 Three Bus System It is suggested that the experiment is carried out first so that computation can be based on measured values of V4 V2 and V3 Knowledge of the magnitude and angle of the three bus voltages defines uniq
6. or iva kWh ABY Fia componant 2 En Mecaurements Thermal state Auxiliary volta 5 ei gt 4 B e 12 00 01 01 99 Sei nole 4 itp ABC ON 0 12 01 a R5232 la 51 nz 20 25485 XM Courier Pisce nos EDs 2 Uu moble Fault ABT l m 2 m 1000 B 16 1000 A le 1000 A HI RLI stort i I abort Programmabla schame logic Hz T ie General alarm User No trips _ 100 progrommobla Breaker SUM I2 00 kA RLS vam tie CB fail timer 1 monitoring apt ime 100 ms HIF us Control CB dote H13 6j HI Setting grove Sating group GEF 06 Block 1015384 p Y Beck D384 eei 012 Extra tip cu EH Any sort 52 x RLF AJR 528 He gt EDG aute mode Select ouio mode 5 kz re za ble Gio Select mode 4 rz 4611 peot lockout Ste 092 wr F i 512 Select live line mode vm ad AJR in sore healthy EF nm P ez es Zu Live lina mode Bock ME 22 12 Reset lockout CEF Use imde 2 programmable Fis See noie 2 as ANS Numbers 67 50P Instantaneous phase overcurrent 79 Autoreclose 810 Overtraquency 67 51P delayed phase overcurrent Wottmatric 47
7. 10 1 CT secondary current 25 10 2 5 A At point B the fault current is also 25 A For relay B the secondary current threshold is 1 0 A i e a primary current of 7 A and the setting multiplier on the x axis of the relay characteristics Figure 103 is calculated as 25 A 7 3 57 Thus the time of operation of relay B for a fault at B may be obtained from the relay characteristics for a TMS of 0 05 as approximately 0 28 s For relay A also with a secondary current threshold of 1 0 A a setting multiplier of 2 5 and a TMS of 1 0 the operating time is seen form Figure 103 to be about 8 s Hence allowing once again 0 30 s time grading between relays the actual operating time of relay A should be 0 28 0 3 s which is 0 58 s The TMS setting required for the relay at point A is therefore 0 58 10 0 058 The nearest TMS is 0 05 This value of TMS can be entered into the P122 relay Summary CT ratio 10 1 Current threshold for CT secondary 1 0 A Setting multiplier 25 TMS 0 05 Operating time 0 40 5 Note that the operating time of relay A for a fault at A would be much smaller than 0 40 s Page 140 NE9270 Power System Simulator Part B Earth Faults These tests are to be carried out with relays D2A and D2B For correct relay operation in the case of an earth fault on any phase at test point 22 new values of 5 have to be calculated and entered together with other information as above into the
8. 1 MB X CB4 525 s 0554 526 553 S28 S62 E L3 e Te 4 O OS11 S27 EP 54 20 X CB22 CB23 R2 L2 Figure 140 Connection Diagram for Experiment 8b Page 212 NE9270 Power System Simulator Experiment 8 Part C Symmetrical Faults Induction Motor Contribution al GTX IPIS SZ 1 O Q GTXB X CB21 X E O 510 O S25 CB22 X X CB24 Oscilloscope C X DD 5 Timed fault switch DAE TP23a CB26 X CB27 UTB O X lt cB34 X A N Transducer IM Figure 141 Connection Diagram for Experiment 8c Page 213 NE9270 Power System Simulator Symmetrical Faults Four Bus System Experiment 8 Part D G MB S GTX NZ R lt 1 CB3 ES CB4 54 C9 C11 S1Q s2 O gt TP16 cB18 X cB19 X 52 e S57 O Link 1 S27 13 S28 O O 539 7 53 338 4 7 s25 O cB20 53 493 O RD S33 1A 7 5 X 17 O O G1 55 56 Fault CB8 point RG1 B Figure 142 Connection Diagram for Experiment 8d Page 214 NE9270 Power System Simulator Experiment 9a and 9b Unsymmetrical Faults 12 Measurement and Transmission Line Faults MB mee GTX MB CB1 CB3 X CB2 S1 Q R S31 S62 O Q SX 20 R DIA 61546 17 DTB 2 DTX1 c R A 2825 CB27 NZ TP23 X R3
9. 2 Figure 74 Curves of Voltage and Current A D C component at fo K Short circuit R Resistance Reactance i t Current t Curve of balanced components of the current ipe t Curve of d c component v t Applied voltage to Moment of short circuit Phase angle 6 Closing angle related to i t 0 Page 103 NE9270 Power System Simulator In Figure 74 waveforms v and i represent steady state short circuit conditions the phase angle being dependent on the X R ratio However if the short circuit occurred at tg the current could not instantaneously have the value A so it must in fact be zero So a direct current A equal but opposite to A must be superimposed at tg Since this d c current is not supported by a voltage it will decay with a time constant T L R The highest value of A is obtained when the fault occurs at or near a voltage zero so is a maximum at tg For this condition the maximum peak current occurs 10 ms after tg and if T 45 ms is obtained from 15 201 exp 10 45 1 2 1 8 1 2 55 where is the rms value of the balanced short circuit current This is the maximum current that should flow between the contacts if the circuit breaker closed onto a three phase short circuit it is called the making peak Some four cycles 80 ms after to the short circuit current ceases at a current zero At this point the d c current is much less than A but it effect
10. 3phase at 1800 rev min 60 Hz Excitation 17 V 1 08 A without the rotor damping cage Each phase of the stator winding is split into two halves with 4 ends for series or parallel connection The rating of the generator is therefore Series connection 230 400 V Star Delta 16 3 9 3 A at 50 Hz Or 276 480 V Star Delta 16 3 9 3 A at 60 Hz Parallel Connection 115 200 V Star Delta 32 6 18 8 A at 50 Hz Or 138 240 V Star Delta 32 6 18 8 A at 60 Hz Main reactances for both parallel and series connection are Xd 18896 Xq 66 The specification of the Induction Motor is 415V 7 5kW 50 60Hz supplied with a 690 PWM Drive The motor has an automatic start stop control initiated by push buttons on the front of the Console Page 11 NE9270 Power System Simulator 2 3 Modelling and Control of the Prime Mover The 690 Vector Drive The 690 PWM Drive Controller is a sophisticated speed control unit for an induction motor It possesses several modes of control constant V f control and field oriented or vector control The basic building block of the 690 unit is a PWM voltage source inverter It uses advanced microprocessor technology for exciting the motor with controllable sinusoidal voltage source of variable voltage and variable frequency The ratio V f is kept constant up to the base speed of the motor For low speed operation voltage boost is provided to counteract the effect of stator impedance voltage drop since this be
11. Disable 2 3 and 4 Power Swing Enable Setting Values Primary CT and VT Ratios Main VT Primary Main VT Secondary Phase CT Primary Phase CT Secondary C S Input Main VT location Group 1 Distance Group 1 Line Setting Line Length 100 0 km Line Impedance 4 800 Ohm Line Angle 80 00 deg Group 1 Zone Setting Zone Status 01010 kZ1 Res Comp 0 5 kZ1 Angle 80 deg 21 3 840 R1G 1 0 Ohm R1Ph 3 0 Ohm 121 0 060 5 kZ2 Res Comp 0 5 kZ2 Angle 80 deg 72 7 200 Ohm R2G 2 0 Ohm R2Ph 5 0 Ohm 72 0 20 kZ3 4 Res Comp 1 000 Page 162 NE9270 Power System Simulator kZ3 4 Angle 0 deg Z3 10 56 Ohm R3G R4G 3 0 Ohm R3Ph R4Ph 7 0 Ohm tZ3 0 4 s Note Zone status indicates that Zones 2and 3 are enabled others are blocked See Chapter 2 of the Areva Technical Manual Procedure 1 Enter into the menu Settings of the relay the values determined above 2 Apply a three phase fault at TP6 between the first two 0 10 pu sections of the Line 6 3 relay should operate and the distance to the fault given in the Fault Records section of the Menu should be approximately 50 km 4 Apply three phase faults similarly at TP7 and TP8 The relay should operate for a fault on TP7 zone 2 at TP8 zone 2 zone 3 and at TP9 zone 3 but not at S35 as it is outside the zone 3 reach Both the fault distance and fault zone can be found in
12. Figure 143 Connection Diagram for Experiments 9a and 9b Page 215 NE9270 Power System Simulator Ine ted Li Ina rical Faults Transformer Term Unsymmet Experiment 9c Power supply MB s HAYY CB1 GTX X S25 S26 XI cB11 X cB12 O OX 12 gt 52 552 CB10 AX Open Test point opened All phases shorted together at TP16a CB15 TP16 xX MG Mr MK cB 14 S lt cB19 O 53 S54 S55 5566 S570 527 O 58 59 L3 Figure 144 Connection Diagram for Experiment 9c Page 216 NE9270 Power System Simulator Experiment 9d Unsymmetrical Faults Double End Feed GTX CB1 x R N GTB 96 2 2 GTXB Timed 2 CB3 c S58 S30 S31 S39 S37 1 O O JO om S38 S26 S25 53 O O O CB5 Fault application G1 G1TX X L L G G1 BUS O s5 Mon S10 Cm R1 L1 Figure 145 Connection Diagram for Experiment 9d Page 217 NE9270 Power System Simulator Experiment 10 Transient Over voltages GSB TX G A C CB1 Oscilloscope R GTB MB S2 V V Transducers WA 530 025 531 O 2 0 O 536 Line Capacitor 2 Q 44 In Position 2 Line Capacitor 1 In Position 1 S23 0 1 pu S24 2 0 512 522 559 X Figure 146 Connection Diagram for Experiment 10 Page 21
13. OVERVOLTAGE TRIPS CBB CBF CB8a GENERATOR 1 BUS TP4 OVERCURRENT TRIPS CB8 SYSTEM BACK UP 1 O OVERCURRENT TRIPS CB8 CBF TRIPS CB8 CBF 100 STATOR P EARTH FAULT O PHASE SEQUENCE ER T PRIME MOVER TRIPS 8 CBF 50 T 7 5 7 5 PRIME MOVER Sa 100 12 5 SECONDARY 2 CHANGE SWITCH GENERATOR 1 BUS AIMED GENERATOR 1 BUS PROTECTION VOLTAGE V CURRENT A POWER W GENERATOR OUTPUT METER C Page 10 Figure 5 Generator Unit G1 and Transformer G1TX NE9270 Power System Simulator The Generator Set Actual generator units consist of a prime mover usually a steam turbine in large power stations driving an a c synchronous generator In the Power System Simulator the prime mover is modeled by an induction motor drive with field oriented control a vector drive The Generator Set is illustrated in Figure 6 It consists of an induction motor driving a salient four pole generator through a flexible coupling A shaft encoder producing 2048 pulses rev is attached to the free end of the generator shaft for steady state and transient load angle measurement Terminal Drive motor Coupling Shaft block guard A C generator encoder Coupling Figure 6 The Motor Generator Set The full specification of the brushless AC generator is Manufactured by Mecc Alte Spa Type ECO 3 15 4 6 5 kVA 0 8 pf 3phase at 1500 rev min 50 Hz or 7 8 kVA 0 8 pf
14. The rated output of measuring transformers expressed in VA is always at rated current or voltage and it is important in assessing the burden imposed by a relay to ensure that the value of burden at rated current is used Characteristic curve The curve showing the operating value of the characteristic quantity corresponding to various values or combinations of the energising quantities Discrimination The ability of a protective system to distinguish between power system conditions for which it is intended to operate and those for which it is not intended to operate Drop out A relay drops out when it moves from the energised position to the un energised position Earth fault protective system A protective system which is designed to respond only to faults to earth Earthing transformer A three phase transformer intended essentially to provide a neutral point to a power system for the purpose of earthing Electrical relay A device designed to produce sudden predetermined changes in one or more electrical circuits after the appearance of certain conditions in the electrical circuit or circuits controlling it Note The term relay includes all the ancillary equipment calibrated with the device Page 203 NE9270 Power System Simulator Electromechanical relay An electrical relay in which the designed response is developed by the relative movement of mechanical elements under the action of a current in the input cir
15. This control circuit has a single input from the speed power potentiometer The full diagram may be found in Eurotherm Drives 690 Vector Drive User Manual which also contains information on the Drive menu and operation The main difference between the power and speed control circuits is that the speed control circuit has a speed feedback loop from the drive shaft encoder and the power control circuit has a power feedback loop from the generator output The control circuit is automatically switched from speed feedback to power feedback when the synchronising switch is closed and the generator is synchronised to the Grid supply through circuit breaker CB8 Both feedback loops go to a summing junction within the control circuit Also seen in Appendix 4 is a generator inertia switch input which is connected to the input PI circuit of the speed loop This control enables variation of the angular momentum of the motor generator to be achieved The generator G1 is not fitted with an automatic voltage regulator and control of the excitation or field current of the generator is manual To the left of the generator unit is Shown the connection between the neutral of the star connected armature windings and earth through an adjustable resistor The resistor is set to limit the earth current to the rated current of the generator The generator transformer G1TX is three phase 5 kVA 220 V 220 V star delta wound with a phase connection of Dy11 The se
16. gt 2 Current Set should be set for the maximum fault rating of the generator The operating time 1 gt 2 Time Delay should be set to 340 s to give instantaneous operation The stage will therefore be stable for external faults where the fault current from the generator will be below the stage 2 current setting For faults within the machine the fault current will be supplied from the system and will be above the stage 2 current setting resulting in fast clearance of the internal fault System Backup Protection A generator will supply system faults until they are cleared by system protection Time delayed overcurrent protection can also act as back up for system faults if it is graded with other system overcurrent protection However there may be a pronounced fault current decrement for faults close to generators resulting in a lower current than the relay setting Therefore the relay may take an unacceptably long time to operate To overcome this effect voltage controlled relay characteristics are used This characteristic is illustrated in Figure 133 If the voltage at the terminals of the generator drops below V 1 set the current threshold of the relay switches automatically from gt set to a much lower setting KI set thus ensuring quicker operation Page 189 NE9270 Power System Simulator Current setting SEU lose ee gt set V lt 1 set Measured voltage Figure 133 Modification of Current Pickup Level
17. or an equivalent voltage drop of in each phase Xm is the magnetizing reactance of the stator winding per phase The voltage phasor diagram leads to a generator equivalent circuit representation per phase shown in Figure 36 The actual emf induced in the stator windings is E Further voltage drops in the winding due to resistance and leakage reactance 14X result in a final terminal voltage of V The full phasor diagram is shown Figure 37 The combination of X and X is called the synchronous reactance of the machine The load angle 5 is a space and a time angle it can be measured approximately as the angular change in the pole position from no load to load X Synchonous Reactance Field Armature Figure 36 Equivalent Circuit for the Generator Page 58 NE9270 Power System Simulator Figure 37 Phasor Diagram for the Generator Saliency Direct and Quadrature Axis Reactances In practical generators the air gap is never uniform ie of equal length all around the machine It is certainly not true of salient pole machines as shown in Figure 38 and even cylindrical rotor machines have a degree of saliency Saliency means that there are two axes of symmetry for the magnetic circuit of the machine one along the pole or direct axis and one along the inter polar or quadrature axis These axes are shown in Figure 38 together with the flux paths associated with them Note that for the same value of mmf
18. seen by the relay and needs to be taken into account when setting Zone 3 In modern digital and numerical relays such as the P442 timers are not used and each zone has 6 measuring elements three for phase phase faults and three for earth faults This gives greater flexibility and speed of operation The relay has therefore 18 measuring elements and is known as a full scheme distance relay Such relays be used EHV and lines In interconnected power systems a distance relay is rarely applied to a single long line It is more likely to be parallel lines multiple infeeds at busbars and teed feeders The challenge to protection engineers is how mathematically to apply the relay to provide accurate discriminatory protection Modern distance protection schemes are often greatly assisted by communication links between relays forming in effect unit protection schemes As an example a common problem is the shortening effect of the second zone coverage of the following feeder due to parallel infeeds Consider for example a fault occurring on the second feeder a short distance in front of the distance relay at B say point P in Figure 111 A voltage drop will occur from the breaker B to the point of fault due to any other fault current via breaker C as well as the current fed directly from A The additional voltage drop due to current from C will not be seen by the relay A but the voltage contribution itself from B t
19. the flux produced on the quadrature axis would be much smaller than that on the direct axis because its magnetic circuit contains much more air For any axis in between the direct and quadrature axis an mmf would produce a flux somewhere between the maximum d axis flux and the minimum q axis flux In the previous section it was seen that the position with respect to the pole axis of the resultant mmf F is dependent on the power factor of the load Figure 35 Thus the magnitude of the flux produced by F and the flux pattern in the machine will vary with load power factor As a means of analysing this situation the armature reaction mmf Fa is divided into two components at right angles Faq along the d axis and Fa along the q axis These mmfs are shown in Figure 38 Figure 39 shows the mmf and corresponding emf diagrams for a uniform air gap generator with lagging power factor load In this case the flux produced by an mmf would be the same on both axes so the stator winding reactances on both axes Xma and Xmg are equal However for a salient pole machine is much less than X g and the voltage phasor diagram changes as shown in Figure 40 For comparison the voltage ON is the voltage Er for a uniform air gap generator for which Xsq The direct axis synchronous reactance Xma Xj and the quadrature axis synchronous reactance Xmq Note that for a given power saliency reduces the load angle 6 at whi
20. to the neutral point current The P632 generates in its software the phasor sum of the phase currents Amplitude matching is required as before of the currents from the two ends of the differential system But vector group matching is not required The two amplitude factors are calculated as before by the expressions Kam N b b Iref N b The matching factors must always be lt 5 In addition the following conditions apply e The ratio of the matching factors must be lt 3 e The value of the smaller matching factor must be 2 0 5 The tripping characteristic is shown in Figure 125 The threshold current 4 is equal to the magnitude of the phasor sum of the amplitude matched resultant currents lam Nb and The restraining current p np is equal to the magnitude of the calculated current lam Nb Page 174 NE9270 Power System Simulator t 8 00 lan ler 6 00 4 00 2 00 ii cin lan let 0 2 LE 0 00 2 00 4 00 6 00 8 00 IRN ler Figure 125 Tripping Characteristics of Ground Differential Protection Page 175 NE9270 Power System Simulator 7 6 Setting the P632 Transformer Differential Protection The P632 has the most complicated Setting Menu of all the relays in the Simulator Care is needed in completing the several sections of the Menu and particularly in finding enables required for the relay to function Four application ar
21. 2 kVA the base susceptance B is 0 0413 S For 125 km of 132 kV line on a base of 100 MVA the line susceptance is typically 0 06 pu For a line of 220 V 2 kVA a susceptance of 0 06 pu is equivalent to a capacitance of approximately 8 uF at 50 Hz Cables The cable has four equal sections The cable per unit reactance per section is 0 01 pu which is equivalent to 10 km of 132 kV 100 MVA cable At 220 V 2 kVA 0 01 pu is equal to 0 24 0 The per unit susceptance of the cable is 0 25 pu which is equal to 31 2 uF Capacitors of 15 uF are connected at the end of each cable section See technical drawing 79962 Page 15 NE9270 Power System Simulator 2 5 The Distribution Busbar and Utilisation Busbar The distribution system and load centre is shown on the right of the of the Simulator panel The system consists of two transformers that can be supplied individually or in parallel by means of two switched busbar interconnectors Switched and variable loads and a dynamic load are connected to a Utilisation Bus which are fed via two parallel distribution transformers from a Distribution Bus The schematic diagram of the distribution system as it appears on the NE9270 front panel is reproduced in Figure 9 together with its associated protection system Figures 10 and 11 show the enlarged left and right halves for easier viewing The Technical Drawing for this section of the Simulator is number 79964 Each distribution transformer is 2 kVA th
22. 8 NE9270 Power System Simulator vs es 035070 e 035070 882 Sal IN3MHMH OHJAO snd HOJIVSH3N35 cs snd HOIVH3N39 5 30885 40 110 sna NOI LO3 LOHd 3ONVLSIG snd NOILOALOYd SNE 282 Sali IN3HMH OH3AO 30885 JO 10 NOILOALOYd H3IHOJSNVH L HOLSIS3H ONIHLYVA 82 82 53181 82 189 53141 tinya ASGNVLS HIsv3 191415384 YAWYOASNVYL dio 82 180 Sal NOILOALOYd TVILN3Y34410 Gasvid 199 JIN3MHMH ODOH3AO V AlddNS ONINOONI 88010 AlddNs Diagram of Grid Supply Busbar and Grid Transformer tic Figure 4 Schema Page 9 NE9270 Power System Simulator SUPPLY ON GENERATOR 1 PROTECTION 53 OUT OF SERVICE MAINS SUPPLY HEALTHY e e e e e e e e e BIASED DIFFERENTIAL PROTECTION TRIPS CB8 CBF EXCITATION PRIME MOVER GENERATOR GENERATOR FIELD 55 GENERATOR 1 BUS e le CURRENT A VOLTAGE V SPEED REV MIN LOAD ANGLE DEGREE TPS UNDER OVER 4 i FREQUENCY 9 EARTHING RESISTOR GENERATOR 1 TRIPS CB8 GENERATOR 1 TRANSFORMER EZE Dy11 d
23. Application and Timer The Manual Fault and Timed Fault circuit breakers are at the bottom centre of the Test Point and Alarms section of the Simulator panel see Figure 30 Either of the Fault circuit breakers can be used to apply faults three phase line to line or line s to earth at a selected point in a system For example to apply a line to earth fault at the end of line 1 take a three phase cable connector from the terminal socket of line 1 to test point 559 The red socket output from 559 is then connected to the primary side of the Fault circuit breaker and the secondary side of the Fault circuit breaker is connected to the earth socket to the right of the circuit breaker After the fault is applied by closing the fault breaker a protective relay should trip its associated circuit breaker after a set time If impedance is to be inserted in the earth connection then either the XL and R components in the panel above the fault circuit breaker or an external impedance could be used The Timed Fault circuit breaker can be used to clear a fault should a relay fail to trip This function is a useful back up when experimenting with relay operating or trip times The timer is first set to a time greater than the expected operating time of the relay Closing the Timed Fault breaker will apply the fault and start the timer If the relay fails to trip within its set operating time the timer will open the Timed Fault circuit breaker and re
24. Banks in the Simulator are designated R1 L1 R2 L2 R3 L3 and R4 L4 All Load Banks are connected in delta Each Load Bank has an isolating circuit breaker Resistive and Inductive Loads R1 L1 and R4 14 are independent loads fed from dummy transformers i e the star delta transformers shown on the panel do not exist They are rated at 220 V line R1 and L1 are situated near Generator 1 R4 and L4 are situated near the Generator 2 Bus on the right hand side of the Simulator panel The Simulator schematic for these loads are shown in Figure 13 VARIABLE VARIABLE L1 L2 L3 OPEN cLoseo amp A a 1 ww wu P P 1 50 100 VARIABLE VARIABLE RESISTIVE LOAD 1 INDUCTIVE LOAD 1 Figure 13 Resistive and Inductive Loads 1 and 4 220V R2 L2 and R3 13 are major loads for the Distribution Systems at the right hand end of the Simulator 12 and R2 are shown in Figure 10 R3 and L3 are shown in Figure 11 They are rated at 110 V line Each of these loads has an additional bank of switched capacitors See Figure 14 12 5 _ 12 5 12 5 12 5 i 12 5 4 125 1 2 50 E 4 50 12 5 12 5 125 LS 50 Figure 14 Delta Connected Switched Capacitive Loads In each set of resistive and inductive loads are three potentiometers or designated L1 12 and 13 All
25. Cables For loads greater than Py the line absorbs reactive power for loads less then the line generates reactive power Table 7 gives values of MVAr km absorbed and generated by lines and cables for no load and full load conditions Lines generally absorb reactive power except when very lightly loaded Cables however generate reactive power even when fully loaded The Py for cables is of the order of ten times that for lines and is always greater than the corresponding thermal rating It must be noted therefore that in a power system with an extensive transmission and distribution system considerable reactive power can be absorbed or generated by the transmission system itself with a consequent drop or rise of system voltage Page 84 NE9270 Power System Simulator Voltage Regulation at Constant Load Power Factor At the receiving end of a transmission system there may be connected loads of varying power factor If the sending end voltage of a transmission line V is considered constant it is of interest to determine the variation of V for varying load at fixed power factors These calculations can be carried out from the line equations V V S 1 0 0 8 0 6 0 9 Lagging 0 4 p f 0 9 Leading 0 2 p att Figure 61 Voltage Regulation at Constant Load Power Factor Figure 61 shows the result of such calculations As might be expected from earlier discussion leading power factor loads cause an inc
26. Centres 33 Communicating Measurement Centres M230 35 Individual Protection Schemes and Relays 39 Essential Operating Procedures 45 4 General Operation of the Power System Simulator 49 Connections and Links 51 Earth Connections 51 Switches and Circuit Breakers CBs 52 Simulator Control Systems and Relay Overrides 53 Fault Application and Timer 53 Test Points Transducers and Instrumentation o4 Remote Access to the Relays and Measurement Centres o4 oimulator Start Up Procedure 56 Generator 1 Start Up Procedure Use Generator 1 Control Panel 56 Generator Shut Down 56 5 Theory and Experiments Steady State Operation 57 Commissioning Experiments of Generator steady state operation of Experiment 1 Synchronisation 67 Experiment 2 Variation of Armature Current with Excitation Vee Curves 73 Experiment 3 The Generator Performance Chart 77 General Theory of Transmission of Power Reactive Power 80 Experiment 4 Voltage Variation and Control 86 Experiment 5 Voltage Regulation for Constant Power Factor Load 89 Distribution System Three Phase Transformers 91 Experiment 6 Three Phase Transformer Operation 95 Load Flow Studies Experiment 7 Load Flow Study 6 Experiments Fault Currents Transient Over Voltages and Transient Stability Symmetrical Faults Experiment 8 Symmetrical Faults Unbalanced Fault Currents Experiment 9 Unsymmetrical Faults Transient Over voltages A C Circuit Interruption Experiment 10 Demonstration of T
27. Fault Records 5 For earth faults connect TP7 between one line and earth the fault CB and apply a fault to earth The relay should operate and the fault location should be 100 km of Line 6 Page 163 NE9270 Power System Simulator 7 5 Differential Protection Differential protection systems are the most widely used type of unit protection where instantaneous relay operation is required due to the magnitude of fault current There are two possible sub divisions 1 Circulating current schemes for short zones which includes most power systems plant 2 Balanced voltage systems used for physically long zones such as feeders and transmission lines These notes refer only to circulating current schemes Biased Differential Protection Schemes a External Fault 400 5 A 400 5 A P1 P2 4 A P1 P2 ee Short Circuit b Internal Fault 3000A P1 2 P1 P2 2000 A 37 5 A Figure 115 Differential Protection Note the CT polarity designation 1 2 51 52 and associated current directions The principles of operation of biased differential protection schemes are common to most unit type protection systems Stated briefly the current entering a protected zone e g feeder transformer generator busbar etc is compared with the current leaving the same zone This basic principle is indicated in Figure 115 where it is seen that during a through fault condition the corresponding current transformer secon
28. Figure 46 Note the additional area gained due to saliency Theoretical Stability Limit roundrotor Theoretical oid lt Practical Limit salient Salient LF 5 Excitation Figure 46 Theoretical Stability Limit Note that if the reference voltage for the construction of the Power Chart is taken from the secondary side of the Generator Transformer then the reactance of the transformer should be added to 4 Typical Values of Generator Parameters Typical values of synchronous reactance are given in Table 6 For a more complete explanation of generator reactances refer to the textbooks shown in the References section of this manual Page 65 NE9270 Power System Simulator Large T G 2 pole Gas T G 2 pole Slow speed salient pole Medium speed salient pole Salient pole 4 pole Table 6 Typical Range of Values Synchronous Generators Page 66 NE9270 Power System Simulator Experiment 1 Synchronisation Theory The process of connecting a generator in parallel with another generator or with busbars to which a number of generators are already connected is known as synchronising The process is necessary because of the possible difference in frequency of the two machines or of the incoming machine and the system Connection can only be made if the frequencies are nearly the same and must be made at or near an instant when the two sets of voltages
29. Grid Bus Although 10096 Zone 1 is equal to 0 20 pu in the above example it is recommended that a 0 30 pu length of line is used for stability tests A general description of the blocking process and relay requirements is given in Chapter 2 of the Areva Technical Manual Power swings follow a much slower impedance locus than that measured for a fault Thus the relay measures the time taken for the impedance seen by the relay the impedance locus to swing through the AR or AX bands to the Zone 3 threshold See Figure 114 A power swing is detected if the time in the AR band is more than 5ms and Power Swing Blocking is executed Typically the AR and DX band settings are both set between 10 3096 of R3Ph Refer to Section 3 of the Areva Technical Manual Copyright permission from Areva Figure 114 Power Swing Detection Characteristics Three additional settings are required for power swing blocking see Chapter 2 of the Areva Technical Manual 1 A biased residual current threshold is exceeded 2 A biased negative sequence current threshold is exceeded 3 phase current threshold is exceeded Page 161 NE9270 Power System Simulator Relay Menu Settings The following configuration data and settings should be entered into the relay Menu as they are given below Refer to Sections 2 and 4 of the Areva P442 Technical Manual for further data and explanation Configuration Active Setting Group 1 Setting Group 1 Enable
30. Negative sequence overvollage 37P Phase undercurreni 51v Voltage controlled overcurrent 5O0BF Breaker failure and backtrip 67 50IN Instantaneous neutral overcurrent 67 Directional 25 Chack synchronising 67 51N Time delayed neutral overcurrent 59 Overvoltage 67 46 Negative sequence overcurrent 37N Neutral undercurrent 59 Residual overveltage BC Broken conductor detection 64 Restricted earth fault 27 Undervoltage VTS transformer supervision 49 Thermal overtoad Blu Underfrequency CTS Current transformer supervision 1 All CT connectors have integral shorting These contacts ore made before the internal CT circuits are disconnected Note 2 Additional hardware for P143 only Note 3 SA CT connections shown CT connections available on the terminal blocks Note 4 The bridge rectifier is not present on 24 ABY dc version Copyright permission from Areva Figure 19 P143 System Overview Page 28 NE9270 Power System Simulator Relay Front Panel The front panels of all relays are very similar with common features although the relay boxes may differ in size Figure 20 shows the front panel of the P142 with hinged covers at the top and bottom shown open Hold both ends of the covers when opening them as they break easily Seria ond V Ratings Top cover M f LCD Fixed function LEDs User programable function LEDs Keypad Bottom cova Battery compart
31. Protective relays t is difficult to simulate in hardware form the performance and operation of the many combinations of components in an integrated power system Software models provide a means for analysis of integrated system performance but cannot provide hands on operational experience The Power System Simulator NE9270 is a hardware scale model of a power system designed to mimic real systems and modern practice It is flexible and has an extensive range of components to allow a wide range of experiments to be carried out These experiments allow the study of essential aspects of both component and system operation and performance at undergraduate and postgraduate level They also offer a means for operational training for industrial suppliers and utilities The Simulator is in effect a small scale integrated power engineering laboratory suitable for group experiments in class demonstrations tutorials and training To maximise the capability and flexibility of the Power System Simulator the design specification includes a At least two generation or supply sources switching and interconnecting systems multiple lines and cables and a distribution system and loads b An integrated protection system whose operation and settings are dependent on system configuration and operation Page 1 NE9270 Power System Simulator centralized control panel for the application of faults the measurement and record of fau
32. The synchroscope also has an on off switch that should be normally in the off position except when synchronising 3 synchronise Generator 1 the main or GRID supply the Grid red and yellow terminals next to the GRID instruments above the GEN 1 controls should be connected to the REF bus terminals of the synchroscope Similarly the red and yellow terminals of GEN 1 should be connected across to the INCOMING bus terminals of the synchroscope 4 Link sockets 1 to 53 5 Switch on the Mains Supply MCB on the left of the Simulator panel 6 Close circuit breakers CB2 and 5 7 Press the green START button for the motor 8 Quickly bring up the speed to 1500 rev min for 50 Hz or 1800 rev min for 60 Hz if you are too slow the under over frequency system will trip 9 Close the circuit breaker CBFb in the Generator 1 Control panel Increase the excitation to give a voltage equal to that of the Grid supply 10 Switch on the synchroscope Watching the synchroscope gently alter the speed so that the red LEDs of the synchroscope are indicating slow clockwise rotation Just before top dead centre of the synchroscope at 11 o clock positional indication changes to the green LEDs Close the duplicate circuit breaker control switch CB8b in the Generator 1 Control panel when the green LED illumination approaches top dead centre Circuit breaker CB8 closes to connect the Generator 1 to the GEN 1 BUS 11 Generator 1 is
33. VARIABLE L1 L2 L3 L1 L2 L3 230V AC 230V AC OSCILLOSCOPE 6A MAX 6A MAX RESISTIVE LOAD 2 INDUCTIVE LOAD 2 CAPACITIVE LOAD 1 Figure 10 The Distribution and Utilisation Bus Left Side Page 17 NE9270 Power System Simulator S63 CB21 D2 A OVERCURRENT EARTH FAULT TRIPS CB21 DISTRIBUTION BUS e T DISTRIBUTION e TRANSFORMER 2 PRIMARY Aut METER N CB24 DISTRIBUTION TRANSFORMER 2 DISTRIBUTION TRANSFORMER 2 PROTECTION PRIMARY TAP CHANGE SWITCH 2 596 0 2 5 DISTRIBUTION 5 0 TRANSFORMER 2 5 0 7 5 7 5 10 0 10 0 1 TRANSFORMER 2 AMKA DISTRIBUTION TRANSFORMER 2 SECONDARY OPEN METER P i D2 B OVERCURRENT AUTO RECLOSE 4 FARTI TAJET RECLOSES CB26 e CLOSED CB26 TP22 UTILISATION BUS CLOSED CLOSED CB34 12 5 12 5 25 50 GHGS e RUNNING DYNAMIC VARIABLE LOAD L1 L2 L3 L1 L2 L3 RESISTIVE LOAD 3 Figure 11 The Distribution and Utilisation Bus Right Side VARIABLE 20 GSS CAPACITIVE LOAD 2 DYNAMIC LOAD INDUCTIVE LOAD 3 CONTROL Earthing Transformer Figure 12 Earthing Transformer Connections Page 18 D2 A D2 B NE9270 Power System Simulator 2 6 Resistive and Inductive Loads The Resistive and Inductive three phase Load
34. When the fault is cleared the capability of the generator to supply electrical power may be such that P gt The generator unit would then decelerate towards its original steady state operating point as energy is taken out of the rotating mass to supply the electrical power However the generator unit will not suddenly stop decelerating at the operating point its momentum will take it past this point Eventually deceleration will cease and the generator will then be accelerated again back towards the operating point The generator unit will therefore oscillate or swing about the steady state point until the oscillation is damped out and the generator unit returns to stable running If however the fault causes the initial swing to be so large that even after the fault is cleared P is still smaller than there is no way the generator unit can decelerate back to its original operating point The speed of the generator will continue to increase so that the rotor poles slip past the stator poles When pole slipping occurs the generator unit has become unstable and has lost synchronism with the other generators in the power system Reference to the load angle 5 is made when discussing the swing of a generator unit Figure 42 shows the increase of P with 6 for a generator discussed previously in Section 5 and known as the Power Angle Curves This is a very important characteristic in stability studies The ideal curve shown gives P si
35. are accessed by the front pori and their settings changed on the PC with S1 software the P122 Menu is simple enough to be accessed by the front key pad The Menu contents description is presented in the Areva Technical Manual The important sub menus are Configuration Protection and Broken Conductor To get the Configuration and the Protection press 4 to Output Parameter which requires the normal AAAA Password for entry then for Configuration and by further to Protection Broken Conductor is found under the Automatic Ctrl Menu Go U from this Menu and then until Broken Conductor is found Go to enter settings See Chapter 3 2 of the Areva Technical Manual P122 Settings See Section 3 for an introduction to this relay Configuration Settings Group Select Group1 CT Ratio Line CT primary Line CT Sec Check phase rotation is ABC gt Yes 1 015 Page 143 NE9270 Power System Simulator Earth Fault 1 Function le gt Ie Delay Type Idmt TMS Broken Conductor Broken Conductor Broken Conductor Time Ratio 12 11 Now set one of the 4 selectable LEDs 5 to 8 to Broken Conductor Find Led Broken Conductor under Configuration Say Yes and enter See page 21 22 of Chapter 3 1 of the P122 Technical Manual Procedure Phase Faults Use Distribution Transformer 1 circuit 1 Setup the three relays in accordance with the settings calculated above
36. are in phase Synchronising Switch Figure 47 Synchronising of Two Generators Consider the synchronising of two three phase generators as illustrated in Figure 47 This can be done with the aid of a voltmeter and a three way switch The phase sequence of the generators must be the same otherwise short circuits will result First with the speed of each machine adjusted approximately to the required values different only if the machines have different numbers of poles the field current of each is adjusted until the voltages of the machines are nearly equal Positions 1 and 3 of the voltmeter selector switch may be used for observation of the voltages of the two machines By changing now to position 2 the voltage variations between the two red phases can be observed Since the difference in frequency 11 fz will be small the frequency of the voltage variation will be small and if necessary can be made still smaller by a slight adjustment of the speed of one machine The synchronising switch may be closed as the voltmeter reading is passing through zero If the two voltages are not exactly in phase but the difference is small the generators will normally pull into synchronism If the two voltages are not in phase or the difference in their frequencies is too great the two machines will pull out of synchronism Page 67 NE9270 Power System Simulator Synchronising Instruments To synchronize generators the following ins
37. are the inputs to the relay from CTS and 5 connected into the power system These inputs go to the software protection elements shown by their ANSI numbers In APPENDIX 1 is the ANSI IEC numbering and symbol systems for identifying relay functions The outputs from the two blocks of protection elements are taken to the Programmable Scheme Logic PSL The PSL allows the user to customise protection and control functions and to programme the operation of optically isolated inputs shown on the bottom left of the diagram relay outputs to CBs etc and LED indicators shown on the right hand side of the diagram The PSL is configured using the support software MiCOM S1 which is PC based Settings can also be changed using the S1 software The PC may be plugged into the front serial port of the relay to download to the relay new PSL arrangements and relay settings Many of the input and output relays in all protection relays on the Simulator have been used for additional control functions e g relay blocking and Accept and Reset buttons This functionality must be included if the user needs to create their own PSL Also shown on the right hand side of the front panel is an RS485 connection for remote control Communication via Courier or Modbus Page 27 NE9270 Power System Simulator belle es P143 SR yet Matia IL Field valage TE ici rm m
38. breakers helps to maintain continuity of supply in the event of transient faults 80 90 of faults on any overhead transmission line are transient Only a single reclosure single shot is used in EHV transmission systems due to considerations of system stability but in distribution systems multi shot reclosures are used as 8096 of all faults are transient In an auto reclose cycle the circuit breaker may open and reclose a specified number of times before locking out staying open reclosure prevented Figure 104 shows the time sequence and events in a single shot auto reclosure scheme Refer to Chapter 14 of Reference 16 for a fuller discussion of auto reclosing The initial trip by the circuit breaker is usually instantaneous to minimise damage at the fault location After a set time delay a dead time the circuit breaker recloses automatically the instantaneous protection is inhibited and IDMT protection is made operative to try and burn off the cause of the fault If the fault is still on the IDMT relay operates and the breaker opens again A second reclosure follows after another dead time If the fault has been removed the second reclosure is successful If the fault is still on the IDMT operates once again For a two shot cycle operation of the IDMT is followed by a lock out Procedure and Setting the RD2B Relay The P142 relay in the right hand branch of the distribution system position RD2B possesse
39. close to motor starting currents and can be estimated by taking the inverse of the starting reactance Decay rates vary from motor to motor and also depend on the exact location of the fault On some large machines it may be possible to obtain accurate data of time constants particularly for motors under construction However for the majority of machines data will be unobtainable A C current decrements are usually included by using various rules of thumb and by considering the effect on the make and break duty separately To calculate the make contribution the full fault contribution of the induction motor is considered However for the break duty it is usually assumed that the induction motor current has decayed to one third of the peak a c value Induction motors have little effect on transmission system faults but may influence fault currents within distribution systems Power station auxiliary supplies contain large numbers of induction motors that have a significant effect on fault current Effect of AVRs Most synchronous machines contain automatic voltage regulators AVRs to stabilise the terminal voltage when the load fluctuates Often AVRs are fast enough to influence fault currents and the principal effect is to reduce the rate of a c current decay Since fault level calculations often ignore the a c decrement the effect of an AVR is to make the calculation more accurate Page 106 NE9270 Power System Simulator Current p
40. closed b Dark lamp method As the frequency of the incoming generator approaches that of the existing supply the flashing of the lamps becomes slower The middle of the dark period is the point of the in phase condition when the synchronising switch can be closed with safety Figure 48 Dark Lamp Method Page 68 NE9270 Power System Simulator C Bright lamp method The dark method of synchronising has a disadvantage it is very difficult for the human eye to determine the exact period of darkness In addition the lamp filament may not be hot enough to radiate in the visible spectrum but may still have a voltage across it Bright lamp synchronising will pulse bright and dim just as in the dark lamp method but the synchronising switch is closed at the brightest point of the illumination cycle With single phase circuits this method produces the maximum voltage at exactly the correct phase angle The bright lamp method has a disadvantage in a three phase circuit there could be a 60 error when the lamps are emitting full light output This is a major factor in not using bright lamp synchronising for three phase circuits A1 B1 C1 Figure 49 Bright Lamp Method d Rotating lamps or cross connected method The circuit shown in Figure 50 is known as two bright one dark synchronisation rotating lamps synchronisation or the cross connected Siemens Halske method It can be seen that two sets of lamps are cross connected betw
41. described in a variety of forms from short explanations to more prescriptive descriptions with calculations It is anticipated that academic institutions and training establishments will wish to produce their own detailed instructions for carrying out experiments Page 2 NE9270 Power System Simulator 1 2 Outline Description of the Power System Simulator The Power System Simulator is housed in a metal cabinet 5 m long x 2 2 m high x 1 4 m deep with rear access to all power components and bottom cable entry for a three phase supply of 10 kW 50 60 Hz The front panel of the cabinet contains a one line schematic representation of the components within the Simulator as well as means for their interconnection operation and control All components and connectors have a code description and address for identification within the SCADA system The main components in the front panel schematic are shown in Figure 2 Section 2 describes and illustrates the main components in greater detail and a complete diagram of the front panel is included with this manual Cable 1 Cable 2 Cable 3 Cable 4 o 0 01pu 0 01pu 00 0 01pu 00 0 01pu Fo x Grid GTX Line 1 Line 2 Line 3 ay o 0 1pu oo 0 15pu 0 15pu To G2 X Line 4 Supply x 0 0 25pu 0 0 25pu Bus GS NM Go X X Line 6 Mesh Bus X X X R L4 Bus Bar G1 L X 54 T 8 DTX2 R L2 R L3 Figure 2 Schematic Diagram of Main
42. equivalent to 24 4 and the positive sequence line impedance 41 Thus V 2 lat I 1 1 x d This analysis shows that the relay can only measure an impedance which is independent of infeed and earthing arrangements if a proportion K 1 3 of the residual current In is added to the phase current I This technique is known as residual compensation Most distance relays compensate for the earth fault conditions by inserting an additional replica impedance Z within the CT side of the measuring circuits Whereas the phase replica impedance Z4 is fed with the phase current at the relaying point Zy is fed with the full residual current This is shown in simplified form in Figure 112 It is shown in Reference 9 that if in Figure 112 is put equal to K 1 Z1 3 the sum of the voltages developed across Z4 and Zu equals the measured phase to neutral voltage in the faulted phase 247 for A N fault Relay Z comparator MEN Circuits Relay replica circuits Figure 112 Earth Fault Relay Current and Voltage Circuits Page 158 NE9270 Power System Simulator Experiment 17 Three Zone Distance Protection Scheme The MiCOM P442 distance relay is a very sophisticated numerical relay with 18 measuring elements or comparators which enables a variety of characteristics to be obtained and information on fault quant
43. fault in the protected zone Measuring relay An electrical relay intended to switch when its characteristic quantity under specified conditions and with a specified accuracy attains its operating value Operating time With a relay de energised and in its initial condition the time which elapses between the application of a characteristic quantity and the instant when the relay operates Page 204 NE9270 Power System Simulator Operating time characteristic The curve depicting the relationship between different values of the characteristic quantity applied to a relay and the corresponding values of operating time Operating value The limiting value of the characteristic quantity at which the relay actually operates Pick up A relay is said to pick up when it changes from the de energised position to the energised position Protected zone The portion of a power system protected by a given protective system or a part of that protective system Protection gear The apparatus including protective relays transformers and ancillary equipment for use in a protective system Protection relay A relay designed to initiate disconnection of a part of an electrical installation or to operate a warning signal in the case of a fault or other abnormal condition in the installation A protective relay may include more than one unit electrical relay and accessories Protection scheme The coordinated arrangements for the pro
44. faults and is very unlikely in this system even if the setting current is very low Through current means in at one feeder and out at either another feeder in the same zone or through the bus section CB CB10 Zone 1 and Zone 2 include the reserve bus or back bus provided the bus section CB CB15 in the reserve bus is open If CB15 is closed current can flow into one zone and out at the other zone so that both zone relays would trip illustrating the purpose of the bus section CTs It is suggested that a simple single line Line 42 and load system is set up to investigate the operation of the protection scheme and the effects of varying the relay settings on the operation and stability of the relays 7 8 Generator Protection The protection system for the generator and generator transformer within the Power System Simulator G1 and GTXI respectively is shown in Figure 5 and the connection diagram in Figure 25 The system contains most of the electrical protection normally associated with generators and generator transformers Prime mover protection is not included with the exception of a reverse power relay Generator Unit faults can be divided into two broad categories a Insulation failure resulting mostly in earth faults b Abnormal running conditions The main protection system is associated with category a faults A generator generator transformer unit in which the primary winding of the transformer is delta connected is isola
45. for Voltage Controlled Overcurrent Protection 4 Reverse Power Protection If the prime mover power output fails or is reduced the generator may take power from the system or a parallel generator to motor the prime mover This is a serious situation and can cause considerable damage A wattmetric relay element is used set below the motoring level to initiate tripping B Indication of Abnormal Operation The protection system includes a number of indicators or alarms for abnormal operation of the unit These are Over voltage e Under or over frequency e Negative phase sequence 1 Negative Phase Sequence Protection Negative phase sequence protection differs from all other forms of protection for the unit in that the need for protection is due to faults on the transmission system rather than in the generator unit Faults on the system can cause negative sequence current l5 to flow in the generator These 100 Hz currents can cause intense surface heating of the solid rotor of the generator that can cause severe damage Indication of excessive negative sequence current l5 is given by a negative sequence relay which can if the condition persists trip the main breaker Manufacturers give generators two ratings 1 For low values of negative sequence current The continuous l5 the machine can withstand 120 2 For high values of negative sequence current The short time thermal withstand the form 15 t The negati
46. having an impedance of 0 37 per km The impedance from the relay location to the distant line extremity would be Z 20 0 37 7 4 Q error of even 1 would correspond therefore to a physical distance of 1 100 x 20 km 200 metres This shows that an overreaching error could cause incorrect operation for faults in the first 200 metres of those feeders connected to the remote end busbar This risk is unacceptable and indeed the actual accuracy of a typical distance relay system approaches 10 1596 when the accuracy of the associated current and voltage transformers is also taken into account It is thus customary to set the distance relay to operate for faults up to only 8096 of the protected line length This is referred to as the 1st zone It is apparent however that the amplitude type comparator described has no directional properties Figure 107 Whether the current flows from busbar to line or from line to busbar the relay will operate To make the relay directional an additional directional relay may be added However a better solution exists The type relay combines distance measuring and a directional feature one unit This is achieved in the Mho relay by comparing not simply with Zp as before but by comparing V I Zp or Zr Zp with Zp Zp is the replica or relay impedance which is fixed Zr is the fault impedance The threshold of the relay occurs when Zf Zp Zp and the locus of the threshold is
47. in a graded sequence such as Relays A B and in Figure 102 One such application takes advantage of the change in fault level between the LV and HV sides of a transformer For example the through fault current for a phase phase phase fault on the utilisation bus is about 29 A This is the maximum current that will be obtained for a through fault on the LV side The equivalent current on the HV side is 15 A Therefore if a fault occurred on the HV winding of the transformer the relay can be set for instantaneous operation at a fault current higher than 16 A normally about 1 3 x 16 A 20 8 A The shorter time setting can limit fault damage to the transformer This operational situation can be investigated on the Simulator by setting a Definite Time element of relay RD1A on the primary side of the distribution transformer DTX1 to about 20 A or a CT secondary current of 20 A 7 2 86 A The operating time of the relay element should be set at zero Relay A at position RGTB could now be graded with the instantaneous element of Relay B thus considerably reducing the operating time If a fault is applied at TP20 with relay RD1B inhibited relay RD1A will operate after a delay i e time graded However if a fault is applied at TP17 relay RD1A should operate instantaneously Setting the RD1A Relay for High Set Operation Group 1 Overcurrent I gt 2 Function DT Definite Time 1 gt 2 Current Set 20A Group 1 Earth Fault 2 IN2 gt
48. indicates when the induction motor is running The DC shunt connected Generator supplies a resistive load The field current of the DC Generator is varied by means of a thyristor whose firing angle is controlled by a 10 turn potentiometer positioned on the panel below the Dynamic Load schematic The potentiometer is motorized for remote control A relay operated by the supply to the Induction motor prevents the field of the DC Generator being supplied when the motor is not running See drawing 79964 for detail Page 16 NE9270 Power System Simulator DOUBLE BUS PROTECTION BUSB o 1 o 1 m 01 OVERCURRENT EARTH FAULT LT TRIPS CB20 DISTRIBUTION BUS i o 5 DISTRIBUTION TRANSFORMER 2 PRIMARY METER DISTRIBUTION TRANSFORMER 1 PRIMARY METER CB23 DISTRIBUTION TRANSFORMER 2 PROTECTION DISTRIBUTION TRANSFORMER 1 PROTECTION DISTRIBUTION TRANSFORMER 2 PRIMARY TAP CHANGE SWITCH am P DISTRIBUTION 6 0 50 15 47 5 Hc DISTRIBUTION TRANSFORMER 1 PRIMARY TAP CHANGE SWITCH 25 50 50 DISTRIBUTION TRANSFORMER 1 ETT 15 100 E iii i 9 gt 2 L3 gt AMER
49. is referred to as neutral displacement voltage It may be shown that Vye is equal to 3 Vp Hence a residual voltage measuring relay can be used for earth fault protection If the system is impedance or distribution transformer earthed the neutral displacement voltage can be measured directly in the earth path via a single phase VT This type of protection can be used to provide earth fault protection irrespective of whether the generator is earthed or not and irrespective of the form of earthing and earth fault current Page 188 NE9270 Power System Simulator level For faults close to the generator neutral the resulting residual voltage will be small Therefore only 95 of the stator winding can be reliably protected For the Generator 1 in the Simulator the current is limited to 1 A for full phase voltage by inserting a 128 resistor between star point and earth A voltage operated relay element is used in the Simulator the 128 O resistor being tapped to provide a maximum input of 50 V 100 Stator Earth Fault Protection Full or 100 stator winding protection can be obtained in the MiCOM P343 relay by measuring tne amplitude of the third harmonic component in the voltage between star point and earth Most generators produce third harmonic voltage due to non linearities in the magnetic circuits of the generator Under normal operating conditions the distribution of the third harmonic voltage along the stator windings varie
50. known Note that a load absorbs reactive power if it is inductive and generates reactive power if it is capacitive Power Transmission and Voltage Regulation for Lines where Capacitance is Neglected jk Inductive Load S P jQ Lagging power factor Figure 58 Equivalent Circuit Series Impedance Only Consider the line represented by the equivalent circuit in Figure 58 only the series impedance is included For this line it may be shown that Buda COS COS Z 9 6 gt is the angle between V and Now let e 90 sin 7 sine Page 81 NE9270 Power System Simulator This is a more convenient form in which to write the equation because when gt R 0 i e the ratio is large In gt sin5 Similarly it may be shown that 1 xU V y Large Power Shortline System V Constant Tran Line pp XT Transfer Reactance Figure 59 Generator Feeding a Large Power System The equation for P is similar to that for the power delivered to a system by a generator a generator feeds a large power system through a transformer and a short line as shown in Figure 59 then P sin T where Xr is the total or transfer reactance of the system and is the overall load angle between the rotor axis and the system bus reference axis Thus for a generator feeding a large system or for a ge
51. load condition set the excitation of Generator G1 to produce 220 V at the Distribution Bus Note the voltage at the Generator Bus Connect a load of 25 resistance and 25 inductive reactances to the system Keep the generated voltage Vs constant for this increase in load and note the value of the Distribution Bus voltage Vr Measure the load current and power factor Repeat this procedure for equal resistive and inductive loads of 50 75 and 100 Plot the variation of distribution voltage against power kW delivered and compare the curve obtained with the curves in Figure 61 Repeat for a resistive load only power factor 1 25 to 100 as a reference for comparison Page 89 NE9270 Power System Simulator Page 90 NE9270 Power System Simulator 5 4 Distribution System Three Phase Transformers Two or three winding transformers that are used in power systems are voltage transformers as their applied primary voltage is nominally constant Three single phase transformers can be used but since the sum of symmetrical three phase currents and flux is zero there is no need for a common return limb in the magnetic circuit and a 3 limb core type transformer is normally used The primary and secondary windings for each phase are wound with the HV winding around the low voltage winding as shown in Figure 64 Low voltage winding High voltage winding Laminated Core Figure 64 Three limb Core Type Tr
52. magnetic optical or other components without mechanical motion It should be noted though that few static relays have a fully static output stage to trip directly from thyristors for example By far the majority of static relays have attracted armature output elements to provide metal to metal contacts which remain the preferred output medium in general System impedance ratio S I R The ratio of the power system source impedance to the impedance of the protected zone Time delay A delay intentionally introduced into the operation of a relay system Transducer A device that provides a d c output quantity that has a definite relationship to the a c input quantity being measured Unit protection A protection system which is designed to operate only for abnormal conditions within a clearly defined zone of the power system Unrestricted protection A protection system which has no clearly defined zone of operation and which achieves selective operation only by time grading Page 206 APPENDIX 3 Connection Diagrams Experiments 2 and 3 Generator Control GSB GTX CB1 0 2 GTXB C 51 53 5 G1B G1TX X CB8 G1 Figure 135 Connection Diagram for Experiments 2 and 3 Page 207 NE9270 Power System Simulator Experiments 4 and 5 System Voltage Regulation S25 S26 S62 CB20 a gt 2 CB23 DTX1 d us G1 G1TX X cB25 cB28 X cB2
53. now synchronised to the Grid supply The speed power pot now controls the power output of the generator Generator excitation controls reactive power When switching off reduce the power output and the reactive power to as near zero as possible before opening the circuit breaker CB8 Procedure with Rotating Lamps Connection should be made initially between the GRID supply and the GEN 1 Bus by connecting the GRID TRANSFORMER Bus to the GEN 1 bus by using either the left or right hand routes between the busbars This procedure is for connecting Generator 1 to the main or GRID supply at the GEN 1 Busbar The synchronising switch is therefore CB8 that is duplicated in the central control panel 1 Before switching the supply on check that the Generator Inertia switch is in position 1 the excitation and speed power pots are wound down to minimum 2 Above the synchroscope there are three lamps R Y B in triangular formation Each lamp has two connecting sockets Page 70 3 4 5 6 7 8 9 NE9270 Power System Simulator To synchronise Generator 1 to the main or Grid supply connect the lamps between the GRID TX BUS and GEN 1 BUS R Y B sockets as shown in Figure 50 This circuit is for the rotating lamp method of synchronizing As an additional visual aid connect the synchroscope as in the last experiment Switch on the Mains Supply MCB on the left of the panel Close CBs2 3 and 5 Switch on the synchroscope Wind down t
54. operating time choose the lowest TMS of 0 025 Thus the actual operating time of the relay is 9 5 s x 0 025 which is 0 24 s Summary CT ratio 14 1 Current threshold for CT secondary 1 00A Setting multiplier 2 09 Time multiplier setting 0 025 Calculated operating time 0 24 s Relay Point B Relay B acts as a back up to relay C for a fault at C The fault current at B due to a fault at C is 29 20 2 which is 14 60 A The CT ratio at B is 7 0 1 CT secondary current 14 60 7 0 2 09 A which is also the setting multiplier if the threshold current is 1 A Time read from the relay characteristics for a setting multiplier of 2 09 and a TMS of 1 0 is 9 5 s Allowing 0 3 s time grading between relay point C and relay point B to allow for relay and CT errors and circuit breaker operation see page 132 of N PAC ref 16 the calculated operating time for the relay at B is 0 24 0 30 s which is 0 54 s Page 139 NE9270 Power System Simulator The TMS setting required for relay at point B is 0 54 9 5 0 057 The nearest TMS setting is 0 050 giving and actual operating time of 0 48 seconds Summary for Relay B CT ratio 7 1 Current threshold for CT secondary 1 0 A Setting multiplier 2 09 TMS 0 05 Operating time 0 48 5 Relay point A Fault Point TP2 Relay A acts as a back up to relay B for a fault at B TP17 The fault current at A due to a fault at B is 127 V 5 08 which is 25 At point A the CT ratio
55. overcurrent menu of relay RD1A and relay RD2A select settings of direction reverse Apply a phase phase phase fault at line 3 via the timed fault CB The Timed Fault CB acts as an upstream relay and CB in removing the faulted transformer or feeder Set the Timer to 1 0 s The Relay RD2A should operate but not RD1A It may be interesting to try forward and non directional settings in one or both relays for comparison Alternative Experiment This experiment can also be carried out on the Distribution Transformers by applying a phase phase phase fault at TP21 see Figure 106 The Grid supply transformer is connected to both Distribution Transfomers by means of Line 2 TP21 is located between the relay RD2B and the transformer DTX2 Relay RD2B trips the circuit breaker CB26 located downstream of relay RD2B If therefore relays RD1B and RD2B were set for non directional overcurrent both CB25 and CB26 would open for a fault at TP21 Both transformer branches would then be open circuit But if both relays were set for reverse direction overcurrent only relay RD2B would trip preventing further fault current flowing through transformer DTX1 Relay RD2A should then trip opening CB24 and removing transformer DTX2 from the system The Utilisation Bus could still be supplied through transformer DTX1 Page 152 NE9270 Power System Simulator 7 4 Distance Protection Distance protection of transmission lines and feeders may be cl
56. power transformer should have a delta connected set of CTs and the delta side of the power transformer should have a star connected set of CTs This form of CT connection also prevents unbalanced CT secondary currents due to zero sequence currents on the occurrence of an earth fault external to the protected zone However the ratio of the delta connected CTs must be divided by V3 to obtain a balance of secondary circulating currents under through fault conditions as shown in Figure 116 Transformer differential protection schemes have higher settings both for pick up and restraint or bias than for example generator differential protection Expressed as a percentage of rated current the setting are typically a pick up setting of 40 and bias of 20 compared with corresponding settings of say 20 and 10 for a generator The reasons for this are several a When the transformer is on no load the no load current is seen as an internal fault current The relay setting current must therefore be greater than the no load current expressed as a percentage of primary current The energising current is also dependent on the type of fault b The two sets of CTs differ in current and voltage ratings and it is therefore difficult to match them Large out of balance current may flow during heavy through fault conditions C The transformer may be fitted with on load tap changers It is not practical to alter CT ratios to match the varying ratio o
57. relays contained microprocessors but these were rapidly overtaken by numerical relays which use a specialised Digital Signal Processor DSP as the computational hardware together with associated software tools DSP technology has advanced so that relays such as the Areva range now include several relay functions or elements overcurrent differential protection etc in one box plus measurement and control functions It is also possible for single relay functions to have up to four independent setting groups in one relay although only one group is activated at a time Because the functional requirements of relay elements are set by software relays for different applications can have similar operational features terminal arrangements and internal organization They differ only in the nature and number of the relay elements inside them Table 4 summarizes the features and capabilities of the numerical relays within the power system Simulator Relay Classification All Areva Protection and Control relays have a P or protection number that defines their function and capability e g P142 The first number defines their overall function these are Plxx Overcurrent protection P2xx Motor protection P3xx Generator protection P4xx Distance protection P5xx Current Differential protection P6xx Transformer Differential protection P7xx Busbar Differential protection The second number defines the relay platform from the simples
58. should be included in the fault circuit as back The fault currents should be recorded in relay RD1A Look in the Disturbance Records of this relay for traces of the fault currents and in Measurement 1 Menu for the magnitude of phase currents Symmetrical component analysis should be used to calculate the fault current for each type of fault Compare the calculated values with measured values Part C Faults on a Transmission Line Terminated in a Transformer If Line 2 is connected to Line 3 and then terminated in one of the distribution transformers any line to ground fault at the junction of the two Lines would result in ground current flowing to the star points of both the grid supply transformer and the distribution transformer The disposition of sequence currents for a line to ground fault on such a system is shown in Figure 84 Additionally Figure 85 shows the interconnection of the sequence networks and the analysis for determining the currents in such a system Carry out the following experiment Set up a system on the Simulator as described above and shown in the Experiment 9c Connection Diagram in Appendix 3 Connect the reactance of 9 6 on the Simulator panel between the fault point and the earth of the grid supply to distribution transformer system not the actual earth connection Measure using the M230 meters the steady state fault currents flowing throughout the system and compare measured and calculated va
59. situated on the far right of the Simulator panel provides connection between the Simulator and external equipment in particular Generator 2 Unit NE9272 The schematic for this Section of the Simulator shown in Figure 17 consists of a single main Bus with connection sockets 564 567 560 and 561 The last three of these sockets are positioned for easy connection to the Links 2 and 4 or to the Distribution Bus GENERATOR 2 BUS GENERATOR 2 INFEED METER Ra Figure 17 Generator 2 Bus At the out board end of the Generator 2 Bus are situated circuit breaker CB36 control switch CB36a and M230 meter Ra Meters Ra and Rb have CTs at this point of the circuit and are duplicate meters Meter Rb is situated in the Generator 2 Control and Synchronising Panel within the central Test Area of the Simulator This Panel is shown in Figure 18 GENERATOR 2 GENERATOR 2 BUS NFEED SPEED POWER EXCITATION GENERATOR 2 52 J CONTROL GENERATOR 2 INFEED 0 1 9 GENERATOR 2 BUS CB36b Figure 18 Generator 2 Control Panel The symbols Y on either side of CB36 and in the Control Panel indicate the position of the line voltages to which Generator 2 Bus and Generator 2 Infeed in the Control Panel refer CB36 is the synchronizing breaker and can be closed either by switch CB36a or switch CB36b Socket S68 is connected in parallel with S67 of the Generator 2 Bus and is provided to make connections easier Having
60. the trip LED can be configured to be self resetting The trip LED is initiated from output relay 3 the protection trip contact Alarm Yellow flashes to indicate that the relay has registered an alarm This may be triggered by a fault event or maintenance record The LED will flash until the alarms have been accepted read after which the LED will change to constant illumination and will extinguish when the alarms have been cleared Out of service Yellow indicates that the relay s protection is unavailable Healthy Green indicates that the relay is in correct working order and should be on at all times It will be extinguished if the relay s self test facilities indicate that there is an error with the relay s hardware or software The state of the healthy LED is reflected by the watchdog contact at the back of the relay Relay Serial Numbers and Addresses Each relay has a unique number printed beneath the top flap i e P142 This indicates that the software version B1 is used for the PSL User Interface The relay has three user interfaces e front panel via LCD and keypad front port for local Courier communication to a PC with S1 software e rear port for remote communication to a PC equipped with 10 SCADA software This port can support either Courier or Modbus protocol chosen on order and not user selectable Courier is the communication language developed by ALSTOM T amp D Prote
61. they are entered For either protection settings or disturbance recorder settings the relay stores the new setting values in a temporary scratchpad It activates all the new settings together but only after it has been confirmed that the new settings are to be adopted This technique is employed to Page 30 NE9270 Power System Simulator provide extra security and so that several setting changes that are made within a group of protection settings will all take effect at the same time e Protection settings scheme logic settings and fault locator settings where appropriate Control and support settings including relay configuration CT VT settings passwords e Disturbance recorder settings Navigation of the Menu and Settings The lt ff and keys which are used for menu navigation and setting value changes include an auto repeat function that comes into operation if any of these keys are held continually pressed This can be used to speed up both setting value changes and menu navigation the longer the key is held depressed the faster the rate of change or movement becomes The front panel menu has a selectable default display The relay will time out and return to the default display and turn the LCD backlight off after 15 minutes of keypad inactivity If this happens any setting changes which have not been confirmed will be lost and the original setting values maintained Whenever there is an uncleared alarm pres
62. winding 220 V TP1 q 4 x BEEN ig 216 2i Figure 24 Relay P632 Grid Transformer GTX CT Arrangements Page 40 NE9270 Power System Simulator Generator Unit G1 and Generator Transformer GITX The P342 Generator Protection Relay provides protection of the Generator The main protection for the generator is a biased circulating current differential protection It does not cover the generator transformer as well because the relay does not possess circuits to eliminate the effects of transformer transients such a current inrush Figure 25 shows the connection of the relay into the system 220 110 V 2 a 10 1 lA 99 VN Figure 25 Relay P343 Generator 61 and Terminal Arrangements Earth fault protection for the generator stator winding is provided in addition to the differential protection by inserting a resistor between earth and the star point of the stator winding Normally this resistor would Page 41 NE9270 Power System Simulator be on the secondary side of a VT The value of the resistor limits the earth current to 1 A for a fault at the generator terminal The resistor is tapped to give a maximum of 50 V input to the relay neutral voltage input An overcurrent element is connected at the terminal end of the stator winding It has a Definite Time High Set setting for instantaneous operation on the occurrence of a sta
63. 00 0 mA PHASE c 000 55 THD PHASE gt 000 55 THD PHASE b 000 55 THD PHASE c PRESENT MD PRESENT MD PRESENT MD PRESENT MD Pt 00 00 W It 000 0 mA Qt 000 0 var St 000 0 VA TIME INTO PERIOD MD at 05 APR 06 59 MD at 05 APR 06 59 MD at 05 APR 06 59 MD at 05 APR 06 59 5 of 6 min Pt 000 0 W It 000 0 mA Qt 000 0 var St 000 0 VA Copyright permission from Areva Figure 22 Measurements Menu of the M230 Table 5 shows the measurements obtainable from the M230 meters including energy demand records True rms measurements of voltage and current are given i e fundamental components plus harmonics However for waveforms with significant harmonics content the readings of power and reactive power and power factor are incorrect See Resistive and Inductive Loads on page 19 Page 35 NE9270 Power System Simulator Instantaneous Measurements Parameters Phase voltages Ua Up Uc Average phase voltage U Line voltages Uab Uca Average line voltage UA Current ide Neutral current In Active power Pa Pp Po Reactive power Qa Qi Apparent power Sa Sp Sc St Power factor 8 COSp 5 COSG Frequency Frequency Total Harmonic Distortion THD la THD Ib THD Ic Total Harmonic Distortion THD Ua THD Ub THD Uc Total Harm
64. 1222 Trip Enabled 1222 Current Set 1 00A 1222 k Setting 5 0 s 12 gt 2 kreset 5 00 s 12 gt 2 tMAX 400 s 12 gt 2 tMIN 1 0 Group 1 System Backup page 35 Backup Function Volt Controlled V Dep OC Char IECS1 TMS 0 025 V Dep OC I5Set 16A V Dep OC Delay 0 5 V Dep OC tRESET Os V Dep OC V lt 1 Set lt 140 00 V V Dep OC k Set 250 0e 3 Group 1 Overcurrent page 32 gt 1 Function IEC S Inverse I gt 1 Current Set 7 00A I gt 1 TMS 250 0e 3 1 gt 2 Function 1 gt 2 Current Set 1 gt 2 Time Delay Group 1 Residual O V NVD page 72 Vy Input Measured VN gt 1 Function DT VN gt 1 Voltage Set 5 00 V VN gt 1 Time Delay 1 00 5 VN gt 1 Status Disabled Page 193 NE9270 Power System Simulator Group 1 100 Stator EF page 80 100 St EF Status VN3H gt Enabled 100 St EF VN3H gt 10 00 V VN3H gt Delay 5 00 s Group 1 Volt Protection page 47 and 49 V lt 1 Function Disabled Group 1 Overvoltage V gt 1 Function V gt 1 Voltage Set V gt 1 TMS Group 1 Freq Protection page 49 and 52 F lt setting 47 00 Hz F gt 1 Setting 93 05 Hz Page 194 NE9270 Power System Simulator Experiment 20 Generator Protection There are two test points on the simulator TP3 and TP4 These points are for investigating the protection of generator G1 for phase and earth faults TP3 is close to the Generator terminals TP
65. 2 Function DT Definite Time IN2 gt 2 Current 20A Page 147 NE9270 Power System Simulator Page 148 NE9270 Power System Simulator Experiment 15 Back Tripping In the previous experiment it should be noted that if a fault occurs at TP20 with the IDMT element of relay RD1B blocked CB25 will not operate to clear the fault In this event relay RD1A should operate to clear the fault but after a longer delay due to time grading To overcome this malfunction of CB25 a back trip signal can be sent from relay RD1B to the next circuit breaker towards the source in this case CB23 Thus set relay RD1B to produce a back trip signal after a time of say 20 longer than the calculated normal operating time Note To use the back trip function press the back trip enable pushbutton on RD1B When these settings have been made CB23 will open for a fault at TP19 in a shorter time than the calculated time graded operating time of relay RD1A and CB 20 Back Trip Settings RD1B RD1A relays Back Trip RD1B to CB23 Configuration CB Fail Enable Group 1 CB Fail Configuration Enabled CB Fail 1 Timer 100 ms Page 149 NE9270 Power System Simulator Page 150 NE9270 Power System Simulator Experiment 16 Directional Control of Relay Tripping Overcurrent relays are made directional by multiplying the current by polarizing voltage The product of the two quantities has a maximum value along an axis coin
66. 4 is on the secondary side of the Generator Transformer Figure 5 shows the positioning of the protection functions discussed in the previous section There are nine individual protection functions and elements available The function not shown is the Neutral Volt Displacement protection that is combined with 100 Earth Fault Both these relay functions require the measurement of voltage VN between earth and the neutral or star point The position of the CTs and VTs for the protection functions are positioned as shown in Figure 25 The ratio of the VTs is 220 110 V line Note that test point TP3 is positioned between the Generator and the system side or downstream CTs VTs Testing of Individual Relay Functions Before testing the Generator make sure the 128Q earth resistor is connected into the earth connection and all links are inserted into TP3 and TP4 1 Under Over Frequency and Over Voltage Run the Generator without load and not synchronised CB8 open Over voltage and frequency can be tested by excitation and speed control of the Generator Over and underfrequency should trip at 5 after approximately 15 seconds Overvoltage starts at 250 V and an IDMT curve Both will trip the generator field 2 Differential and Overcurrent Protection Phase Faults First set up on the Timer Circuit Breaker a line to line fault through the 9 60 inductor on the central control panel Set the Timer for 0 1s Run the Generator unsync
67. 8 NE9270 Power System Simulator Experiments 12 14 and 15 Overcurrent Protection Relay Grading High Set and Back Trip R MB GTB GSB GTX ES For Earth faults SZ S26 S62 0 0 2 gt CB21 2 R R DIA D2A s10 525 O TP17 gt 18 CB22 X 4 23 X CB24 e DTX1 gt DTX2 Figure 147 Connection Diagram for Experiments 12 14 and 15 Page 219 NE9270 Power System Simulator Page 220 NE9270 Power System Simulator Experiment 13 Overcurrent Protection Auto Reclose R GTB GSB GTX SZ SC Doo C820 R X os TP17 510 S25 xX 24 DTX2 gt TP21 R D2B X CB26 45 22 V CB33 O TP23 Figure 148 Connection Diagram for Experiment 13 Page 221 NE9270 Power System Simulator Experiment 16 Overcurrent Protection Directional Control 09 I 09 I 0D I Q NI O ER Sc 7 4 S7 g gg 09 O UO 09 O N E 2 x N gt RO rA NU 696 950 L9S 095 X Figure 149 Connection Diagram for Experiment 16 Page 222 NE9270 Power System Simulator Experiment 17 Distance Protection O gt aX J CO EO O E O H Q 1 7 a 0 KHXFO C c O O 4 CN eo GTXB GTX 8 DS co O Figure 150 Co
68. 9 R2 L2 Figure 136 Connection Diagram for Experiments 4 and 5 Page 208 NE9270 Power System Simulator Three Phase Transformers Parts A B C and D Experiment 6 O T 1 2 7 lt 2 YOUMS ney X zego 12680 6280 A 8089 X 4 szao X LNW 29 Hed 605 uos CdVL OMS lt gt YOUMS se INA X ZN A ala NZ 7 za 925 O t 695 695 605 LS 8x19 4 cgo Lgo 859 Figure 137 Connection Diagram for Experiment 6 Page 209 NE9270 Power System Simulator Load Flow Experiment 7 Loads As before Experiment 6 DTX2 Loads Figure 138 Connection Diagram for Experiment 7 Page 210 Experiment 8 Part A Symmetrical Faults Unloaded System R GTB GSB GTX NZ 0 1 1 x ce 4 2 SA 1 Figure 139 Connection Diagram for Experiment 8a Page 211 NE9270 Power System Simulator 526 S62 2 0 R DIA lt 17 22 O 525 R DIB CD lt gt 19 SZ X DTX1 CB25 O TP20 NE9270 Power System Simulator Experiment 8 Part B Symmetrical Faults Loaded System Fault Application Point v TP13 R GTB gt GSB GTX X 0
69. COM P343 All protection functions shown are performed by this relay This detail is shown in Figure 25 The field winding of the generator circuit breaker and instrumentation for the generator and excitation is shown above the generator symbol generator speed RPM load angle delta 5 field excitation volts and current A three phase M230 meter Meter C provides generator output data Voltage current and power meters are provided for the induction motor or Prime Mover driving the generator Page 7 NE9270 Power System Simulator The control panel for Generator 1 is situated near the central Test and Control panel for the Simulator and 15 shown in Figure 3 Start and stop buttons are provided for the prime mover and control potentiometers for control of speed power and field excitation current Above the generator control panel are voltage and frequency meters for both Gen 1 Bus and Grid Bus These meters and the terminals alongside them are used when synchronising the generator to the Grid Bus to Generator 2 The symbol Y positioned below the terminals indicate the position in the circuit at which these voltage and frequency measurements are taken For the Generator 1 the Y symbol is shown after test point TP4 CBF and CB8 are linked for ease of operation GRID BUS d GEN 1 BUS SPEED POWER EXCITATION GENERATOR 1 CONTROL 0 1 0 1 STOP Figure 3 Control Panel for Generator 1 Page
70. Close field circuit breaker CBF Adjust excitation control to give 220 V Check voltages across all generator phases on MC or MD e Circuit breaker CBF and CB8 cannot be closed until the drive motor for Generator 1 has started e The motor will only start if the generator protection is operative and the inertia switch is in position 1 4 10 Generator Shut Down 1 2 Adjust the generator output to near zero and open the field circuit breaker CBF Press the stop button and allow the prime mover motor fan to continue cooling for at least one minute before you switch off the simulator Page 56 SECTION 5 0 Theory and Experiments Steady State Operation This section considers the operation of a power system under steady state conditions when symmetrical three phase voltages are applied to three phase balanced loads resulting in identical currents in each phase of the system Basic knowledge of balanced three phase systems is assumed and the experimental studies concentrate on three main areas of system operation generation transmission and distribution and utilisation In each area a review of the relevant fundamental theory is given together with some illustrative experimental studies 5 1 Commissioning Experiments Unless specifically asked for manufacturers normally supply only nominal values for equipment parameters It is desirable therfore that the actual values of parameters should be obtained by tests before system studies a
71. Earth Fault 2 menu of relays DIA and D1B at relay points C respectively The current thresholds and TMS values are obtained by calculating the fault current by the method of symmetrical components Relay Point C Calculation of the fault current should be carried out as shown in the worked example of Section 6 Figure 83 The fault current is given by NE F 2 2 2 For a fault at relay point C Z4 Z5 8 7 as before Zp is equal only to the zero sequence reactance of the earthing transformer which is negligibly small Thus Z Z1 Z gt 274 and Ip 3 221 1 5 21 Hence is equal approximately to 1 5 times the three phase fault current The three phase current from initial calculations is 29 20 A Hence p 1 5 x 29 20 43 80 A Hence the secondary fault current is 43 80 A 14 which equals 3 13 A From the relay characteristic in Figure 103 the operating time for the relay is 0 28 s for a secondary threshold current of 1 A and a fault current of 3 13 A at a TMS of 0 025 A fault current of 43 80 A is a very large current and it is recommended that a 1 resistor on the front panel of the simulator is inserted in the earth connection of the earthing transformer to reduce the fault current to about 30 0 A The relay will still operate very positively in a time of about 0 30 s Relay Point B This relay should be set as a back up to Relay C for a fault at C TP22 In this case
72. NE9270 Power System Simulator TQ Education and Training Ltd 2006 No part of this publication may be reproduced or transmitted in any form or by any means electronic or mechanical including photocopy recording or any information storage and retrieval system without the express permission of TQ Education and Training Limited All due care has been taken to ensure that the contents of this manual are accurate and up to date However if any errors are discovered please inform TQ so the problem may be rectified A Packing Contents List is supplied with the equipment Carefully check the contents of the package s against the list If any items are missing or damaged contact your local TQ agent or TQ immediately sl TQ Education and Training Ltd AB DB 0206 Contents Section Page 1 Introduction 1 Overview Design Philosophy 1 Outline Description of the Power System Simulator 3 Parameter Values of Components The Per Unit System 4 Outline of the Manual 6 2 Technical Description Main Components 7 Grid Supply 7 Generator Unit G1 and Transformer G1TX 7 Modelling and Control of the Prime Mover 12 The Transmission Lines 13 The Distribution Busbar and Utilisation Busbar 16 Resistive and Inductive Loads 19 Double Busbar Interconnection and Switching System 21 Generator 2 Infeed 23 3 Technical Description of Protection and Measurement Systems 25 The Areva Relays 25 Measurement and Data logging in relays and Measuring
73. NPS Thermal Protection is operating is the switching on of the NPS Alarm LED after 20 s the 12 gt 1 Time Delay After 500 s the 12 gt 2 tMax setting the relay should trip Page 196 SECTION 8 0 References 1 2 3 4 5 6 7 8 9 10 Power System Analysis by J Grainger and W D Stevenson Published by McGraw Hill 1994 Electricity Supply Transmission and Distribution by F de la C Chard Published by Longman 1976 Electric Energy Its Generation Transmission and Use by ER Laithewaite amp L L Freris Published by McGraw Hill 1980 Electric Energy Systems Theory by Olle Elgerd Published by McGraw Hill 1982 Electrical Power Systems Volumes 1 amp 2 by A E Guile amp W Paterson Published by Pergamon Press 1978 Electric Machinery Sixth Edition by A E Fitzgerald C Kingsley S D Umans Published by McGraw Hill 2002 Electrical Machines and their Applications Fourth Edition by J Hindmarsh Published by Pergamon Press 1984 Alternating Current Machines by M G Say Published by Pitman 1976 Protective Relays Application Guide PRAG Third Edition by GEC ALSTOM Protection and Control 1987 Power System Stability Synchronous Machines by E W Kimbark Published by Dover 1968 Page 197 NE9270 Power System Simulator 11 Protection of Industrial Power Systems Second Edition by T Davies Published b
74. Power System Simulator j 0 005 pu Fault Level 11 kV 200 MVA 1 pu 500 kVA motor Figure 78 Contribution of induction motor to initial fault current at busbar Current from source bn Current from motor Base MVA 1 MVA So source equivalent X pu 1 200 j0 005 pu 1 0 5 Imake f 7 To 21 68 10 2 2 _ 19 break 0055 3 10 PU Part D Fault Analysis using Bus Impedance Matrices More complicated systems involving generator G1 and the grid supply GS and six lines can be set up on the Power System Simulator Such systems as shown in Figure 79 will have 3 or 4 busbars The diagram for setting up this system on the Simulator is shown in the connection diagram for experiment 8d in Appendix 3 The double Busbar is used to interconnect the lines The fault point is at TP17 no load is supplied by the system Calculations of the fault current at the faulted bus and from the two generators using the bus impedance Zpus method can be compared with measurements recorded in the Disturbance Records and Measurement 1 sections of the relays RD1A RG1B and RGTB Page 110 NE9270 Power System Simulator GRID SUPPLY G1 Faulted Bus Figure 79 Fault Analysis Using Bus Impedance Page 111 NE9270 Power System Simulator Page 112 NE9270 Power System Simulator 6 2 Unbalanced Fault Currents Most systems and loads are reasonably well balanced and may be analy
75. Secondary values can be entered into the relay settings file If primary values are entered the relay calculates the secondary values from the CT and VT ratios Thus primary values will be given here Page 159 NE9270 Power System Simulator The Zone 2 reach is Z2 150 x 4 8 7 20280 Q The Zone 3 reach is Z3 220 x 4 8 Q 10 56 80 0 Resistive Reach Calculations All distance tripping elements must avoid the heaviest system loading Taking a 1 A CT secondary current as an indication of maximum load current the minimum load impedance presented to the relay would be ph 1 1 Typically phase fault distance zones would avoid the minimum load impedance by margin of lt 40 Earth fault zones would use 20 margin This allows maximum resistance reaches of 38 and 50 8 If quoted on the primary side the values above are divided by the CT VT ratio which is 5 Hence the required maximum primary values are 7 6 Q and 10 160 The minimum values are dependant on arc resistance see Table 1 Paragraph 2 4 4 of the Areva Technical Manual which are not relevant in this application Hence select the following Phase Rph Q Earth RG Q Part B Earth Faults In Section 7 it is stated that residual compensation is necessary if the relay is to see correctly the impedance of the line 71 To achieve this for the P442 relay a residual compensation factor KZO has to be inserted i
76. System Components Circuit breakers or contactors for system isolation or connection are shown in Figure 2 Each circuit breaker on the schematic has a manual close open lever nearby The components of the main Power System Simulator a Supply GS and Grid Supply transformer GTX b A generator unit G1 and generator transformer G1TX which may be connected to the Grid Supply through a mesh bus system set of transmission lines Lines 1 to 6 and cables of varying lengths for interconnecting between the power supply points and the loads Line 6 differs from the others in being of several sections of shorter length This arrangement is for studies specifically of the distance protection of transmission lines but it can be used also as a general interconnecting line d distribution busbar which feeds through two parallel connected transformers DTX1 DTX2 a utilisation busbar and a load centre consisting of resistance inductance and capacitance Load 2 and Load 3 An induction motor M may also be connected to the utilisation busbar to study the effects of dynamic as well as static loads e double busbar interconnector is placed centrally in the Power System Simulator panel This provides not only convenient central connection points for the various components but also a study of busbar protection Page 3 NE9270 Power System Simulator f Placed centrally on the Power System Simulator p
77. These are acceptable values The actual tripping current is given by the expression in the earlier section Tripping Current which gives for a setting current of 20 0 2x1A 1 2124 0 165 A without zero sequence filtering Thus enter the following settings in the Menu Goto Config parameters DIFF Function Group DIFF and enable by entering with Parameters Function Parameters Global MAIN Protection enabled Inom C T prim end a Inom C T prim end b Inom C T Yprim end b Inom device end a Inom device end a Leave other value entries as the default entries Function Parameters General Functions MAIN Vnom prim end a Vnom prim end b Leave other value entries as the default entries Function Parameters General function DIFF General enable USER Yes Reference power Sref 0 40 MVA Ref curr lref a not measured 0 577 Ref curr lref b not measured 1 154 777 Matching fact a not measured 1 2124 77 Matching fact Kam b not measured 0 8665 77777 Vector grp ends a b 11 Leave other value entries as the default entries values are calculated by the relay Page 177 NE9270 Power System Simulator Function Parameters Parameter Subset 1 DIFF Enable Yes Idiff gt PS1 0 20 Iref m1 PS1 0 3 m2 PS1 0 7 Ir m2 PS1 4 0 Iref 0 seq filt B enable Yes Leave other value entries as the defa
78. a circle radius Zp This is shown in Figure 108 Page 153 NE9270 Power System Simulator Reach Point Distance Relay 20 km Line LINE TERMINAL Current Transformer ES Voltage Distance Transformer Relay Relay Characteristic on Z Plane Diagram Figure 107 Distance Relay Function Locus is a circle for threshold conditions on the Z plane diagram Figure 108 Locus of the Threshold Page 154 Protected Line Feeder Impedance NE9270 Power System Simulator Trips when A gt 90 ie When fault impedance Z inside circle 97 27 Characteristic angle of relay 6 Line angle Figure 109 A Comparison of the Phase Angle X Between Two Quantities The phase angle between two quantities Zr and 22 4 are compared as shown in Figure 109 threshold is given by 90 The relay operates when 7 gt 90 Static and digital relays such as the Quadramho and Optimho which replaced electromechanical relays are phase comparators In these relays the two inputs are called 4 and 5 where 12 12 2V l is the fault current 2 is the impedance setting of the relay and equals 2Zp In all impedance relays the variable arc resistance at the point of fault causes difficulties in achieving consistency and accuracy of measurement and causes the relay to under reach i e length of line protection is less than the relay setting See References 9 or 16 Thi
79. a further modification to the equivalent circuit of the generator is required this time to the generated emf When the generator is delivering load circuit 1 under steady state conditions Page 100 NE9270 Power System Simulator When fault occurs the reactance of the generator suddenly changes from Xs to so that the generated voltage becomes E V I X is called the voltage behind the transient reactance and is approximately equal to the actual emf induced in each phase of the stator winding The equivalent circuit for the generator under transient conditions is shown in Figure 69 Similarly if the initial sub transient period is considered V 1 X Where is the voltage behind the sub transient reactance I is the rms short circuit current Figure 69 Equivalent Circuit Balanced Fault Currents Balanced fault currents i e same a c current in each phase flow when a three phase short circuit occurs on a system and may be calculated from a network diagram of the system drawn in per unit A simple system is shown in Figure 70 If it is assumed that there is no circulating current between the generators they must be of equal magnitude so Figure 71 can be reduced to Figure 72 Since it is also assumed that X R 1 throughout so that the resistances may be neglected the fault current Zp be calculated as Py current Line Double Large Power System 3 phase short cir
80. acy the relay reach for the first zone of operation was set to 80 of the line length In order to provide protection for the last 2096 of the feeder a typical distance protection system would be provided with a detector or starter element to reach to the end of the following feeder as shown in Figure 111 The detector would not trip directly but would start a timer and would after typically 0 4 second extend the reach of the measuring element if the latter had not already operated Third Zone 400 ms 200 ms Second Zone A 9 0 First Zone Figure 111 Three Zone Distance System Page 156 NE9270 Power System Simulator This zone extension process would increase the measuring unit s reach to typically 120 150 of the feeder length This Zone 2 would cover faults occurring in the last 2096 of the feeder and also in the first section of the next feeder In the latter case the instantaneously acting measuring unit of the next feeder ought to have already operated to trip its own circuit breaker The delayed action of the distance relay for the previous feeder may be regarded as back up protection as illustrated in Figure 111 Remote back up protection for faults on adjacent lines can be provided by a third zone of protection that is further time delayed to discriminate with Zone 2 See Figure 111 On interconnected systems fault current in feed at the remote busbars will cause an increase in the impedance
81. al Manual for the relays should be consulted For phase faults the polarizing voltage threshold is fixed at 0 5 V but is variable for earth faults Page 151 NE9270 Power System Simulator Application to Parallel Feeders Figure 106 shows a typical distribution system using parallel transformers Relays R3 and R4 may both have a non directional overcurrent stage set to trip for a fault on the low voltage LV busbar or as back up to relays on outgoing feeders The HV upstream relays will have a longer operating time than the LV downstream relays that are closer to the fault However if a fault occurs between the LV winding of a transformer and the relay both transformers will still trip This can be prevented by use of a second overcurrent stage with directional control If relays R3 and R4 have a second stage set to operate very rapidly for fault current flowing towards the transformer LV windings only the faulted transformer branch will trip HV RD2A RD2B Figure 106 Typical Parallel Transformer Distribution System Directional control of relays in the protection of parallel feeders without transformers can be demonstrated on the Simulator Connect the Grid Supply to Line 2 and 3 as shown in the connection diagram for Experiment 16 Lines 2 and 3 can represent either transformer reactances or feeder reactances CB22 is to remain closed and CB23 and CB24 are to remain open throughout this experiment Within the
82. al connection port in the side panel on the right hand side of the Simulator Page 55 NE9270 Power System Simulator 4 8 1 2 3 4 5 6 7 8 9 10 4 9 1 2 3 4 5 6 7 8 9 Simulator Start Up Procedure Ensure both emergency stop buttons are out and rear cabinet doors are closed Switch on the mains supply Switch on the mains MCB of power system simulator The grid transformer relay will perform self check for several seconds then CB1 will close automatically If this does not happen contact TQ or a representative Check that generator inertia switch on panel 1 left hand side panel is at Position 1 Check that all test point links e g TP3 TP4 etc on panel 3 all have shorting plugs fitted Check grid incoming volts across all phases use MA Check transformer secondary volts across all phases on instruments adjacent to TP1 test point on the panel 1 schematic use MB Press the reset button on the central control panel Press lamp test button on the central control panel and check all lamps are working Generator 1 Start Up Procedure Use Generator 1 Control Panel Carry out Simulator Start Up Procedure Check field circuit breaker CBF is open Check speed power control pot is at its minimum setting 500 rev min Check excitation control pot is fully anti clockwise 000 Press Start button Increase speed power control to give 1500 rev min 50 Hz 1800 rev min 60 Hz
83. am of test point TP3 Connect into TP3 a 0 10 pu line to limit fault current and provide additional volt drop between the Generator terminals and the voltage sensing VT The present voltage setting for operation of the relay switching the Overcurrent IDMT characteristic to a more sensitive DT setting is 130 V primary line voltage Page 195 NE9270 Power System Simulator Measure the fault current and the line voltage at TP5 using Meter D and the voltage at the location of the voltage sensing element using Meter C A line line fault should be applied at TP5 by means of the Timer Circuit Breaker with the 9 6 inductor connected between two phases set the timer to 0 4s Close CB8 before closing the Timer CB The Generator relay should trip If at this point of the line the voltage has dropped below 130 V the trip time should be lt 0 5s if above 130 V the trip time will be gt 0 5s 5 Negative Sequence Thermal Protection The Negative Sequence Protection can be tested by connecting the Generator to a variable phase phase resistive load Connect Resistive Load 1 to Generator 1 by linking 510 to 55 Close CBs 8 and 9 Supply the load at 220 V and using only one pot of the resistive load adjust the current flowing in two phases to 2 6 A For line line faults or loads symmetrical component analysis gives Line x I2 where 12 is the negative sequence current In this case 12 1 5 A or 58 of 2 6A The first indication that the
84. ample All the individual settings will appear Double click on a setting to be changed A setting selection screen will appear Change the value or instruction and OK it When settings have been changed as required save them then go to the toolbar screen and click on Device then Open Connection Follow instructions to upload the existing file to the Relay There are now two relay setting frames on the PC Screen the Device Frame and the Modified Setting Frame Collapse the modified setting menu back to the PC icon Click on the Green PC icon and drag and drop onto the PC icon of the relay screen Wait until the PC finishes downloading to the relay Follow any instructions necessary Refer to the 51 Software Guide for more detail Page 47 NE9270 Power System Simulator Page 48 SECTION 4 0 General Operation of the Power System Simulator A number of general facilities are provided on the Power System Simulator panel to enable a power system to be set up and its operation investigated The main functions of these facilities are to Connect together the individual components to form the power system to be studied Switch manually and by protective relays the various components in the system Apply and time the duration of faults on the system Measure and record voltages and currents throughout the system Provide alarms and controls for the protection system Central Test and Control Panel Means for connecti
85. and with reference to the relay manuals 2 Connect the timer CB at test point TP20 Set the timer to say 1 5 s Block the instantaneous trip at relay D1A and Instantaneous trip gt 2 at D1B 3 Close CB20 CB23 and CB25 4 Apply a fault at TP20 fault point C The relay at C D1B should operate 5 If relay at C is blocked applying fault at C should cause relay at to operate 6 If both relays and B are blocked applying a fault at C will cause A to operate 7 steps 5 and 6 it is possible to sense from the relay operational LEDs the time grading between relays B and C From the Disturbance Measurements and Records 1 records within the menus of relays B and C it is possible to check the fault current duration CB operating time and relay trip time 8 Ifa fault is applied at B TP17 relay B should operate 9 If relay at B is inhibited applying at fault at B should cause the relay at A to operate Earth Faults Use Distribution Transformer 2 circuit 10 Block I gt 1 1 gt 2 and close CB24 Applying a fault at TP22 will cause relay to operate 11 Blocking relay C In gt 1 and applying fault at TP22 should cause relay B to operate 12 Applying a fault at TP18 should cause relay B to operate block 1 gt 2 13 Applying a fault at TP18 and blocking relay B should cause relay A to operate Page 144 NE9270 Power System Simulator Experiment 13 Multi Shot Auto Reclose Auto reclosing of circuit
86. anel but not shown in Figure 2 are the 24 test points and alarms the test switches which allow application of balanced and unbalanced faults and the synchronisation system and metering for paralleling the Grid Supply with generators G1 or G2 or for paralleling generators G1 and G2 g Each component of the Power System Simulator has an integrated protection system These are not shown on Figure 2 The relays are placed into the front panel and their points of connection to the system are shown in the technical description of the protection system in Section 3 If a relay is taken out of the panel contacts are closed so that the Simulator circuits are not open circuited h The Simulator Power System is 3 phase 3 wire from supply to load There is no neutral wire A single solid earth bar provides earthing for the star points of transformers and other similar apparatus 1 3 Parameter Values of Components The Per Unit System The parameter values of the components of the Power System Simulator represent as far as possible the parameter values of a real system This can only be achieved on a proportional or per unit basis where the actual value of the parameter is expressed as the ratio of that parameter to a chosen base value System representation is achieved by having the same per unit values as the actual system Actual values are obtained by multiplying per unit values by the appropriate base values An understanding of the per unit syste
87. ansformer V Re X e V Symbol Figure 65 T Equivalent Circuit for a Two Winding Transformer The T equivalent circuit for a two winding transformer is shown in Figure 65 The relative values of the total series impedance and the magnetising reactance X are of the order of 10 and 2000 respectively They rarely have to be considered together and in most load and fault calculations the transformer may be represented by only the series impedance Windings of three phase transformers may be connected in Star or Delta Depending on the primary and secondary connections phase shifts of 0 30 and 180 can be produced between the primary and secondary phase to neutral voltages It is therefore necessary to have standardisation of nomenclature and connection procedure as shown in Table 7 Page 91 NE9270 Power System Simulator The distribution transformers in the Power System Simulator are phase connected Yd1 This means that the secondary phase voltage lags the primary phase voltage by 30 The winding connections to produce this phase shift are shown in Table 8 In this diagram the winding between A2 and YN of the Star is wound on the same limb of the transformer as the winding a of the delta Hence these voltages are in phase as shown so causing the 30 phase shift between primary and secondary phase voltages Tap Changing Figure 66 Circulating Produced by Unequal Taps of Two Parallel Transformers I
88. ared with those calculated The P122 and P142 relays connected into the system enable data on both fault currents and steady state currents including sequence currents See Section 3 of this Manual and the relay Manuals Part A Negative Sequence Current Measurement This experiment is a simple exercise in symmetrical component analysis It does not involve fault application only steady state measurement of current A line to line load is fed by a radial system and measurements of current compared with analysis On the Power System Simulator set up a system in which the Grid supply feeds a load through Line 4 and a distribution transformer Connect a switched three phase load resistance R3 at the end of the line and use TP23 to break one phase with the manual circuit breaker Measure the line current to the load For line to line faults or loads symmetrical component analysis gives 7 3 1 where gt is the negative sequence current In this case 5 approximately 2 8 A or 58 of the line current The relay RD1B should indicate these values in the Measurements section of the relay menu Part B Faults on a Transmission Line fed from a Single Source A system similar to that of the example given in Figure 83 can be set up on the Simulator by connecting Line 4 to the Grid Transformer Bus Line to ground line to line or line to line to ground faults can be applied ai the far end of Line 4 at TP17 Remember that the timer and its CB
89. ariation of prime mover power at constant generator excitation It is first necessary to construct a Performance chart for the Salient Pole Generator in the Simulator Construction of the Performance Chart As Generator 1 is a Salient pole machine the performance chart should be constructed as shown in Figure 45 Two quantities have to be calculated first the base value V7 X 4 and the diameter of the saliency circle P Xsd The pu values of must first be converted to the Simulator base values of 2 kVA and 220 V line from those for the Generator given in Section 2 Hence for 50 Hz 1 88 x 200 x 0478pu X 0 66 x 200 0 167pu 220 65 And for 60 Hz X 4 1 88 240 0 69pu Use these values to construct a chart Use a base value of 2 kVA and take the axis to 4 kW Values of load angle obtained from the performance chart are At60 Hz O19 at 2 kW and 2 kVAr At50Hz 6 139 at2 kW and 2 kVAr Page 77 NE9270 Power System Simulator Procedure Note that during this experiment as the reactive power approaches 2 kVAR generator output protection will activate 1 Construct a chart for Generator G1 to a 2 kVA base as described 2 Synchronise the generator to the Grid Supply as described in Experiment 1 3 Using meter MC set the power output at 2 0 kW increasing the excitation to keep the power factor at unity Note the field current and the load angle 6
90. ase Changes in three phase transformers Use an oscilloscope and the phase angle meter to confirm that the phase angle between the primary and secondary line voltages of a distribution transformer is 30 Similarly look at the primary and secondary winding voltages of the generator transformer The phase difference in this case is 30 since the transformer is phase connected Dy11 Part B Unequal taps Unequal ratios in parallel connected transformers are equivalent to a small voltage generator circulating current only around the transformer loop Investigate the effect of unequal ratios by setting unequal taps on the two distribution transformers The smallest difference in percentage taps should be considered initially and the transformers should not be supplying a load Currents power and reactive power should be measured by the M230 meters in each transformer primary and secondary Compare measured and calculated values of current Why do the two primary currents have different measured values Part C Unequal impedances Two transformers will not share a total load in proportion to their ratings if the per unit impedances of the two transformers are not identical and one transformer will become overloaded before the total output reaches the sum of their individual ratings Set up the distribution system to supply a total load of say 50 Resistive and 50 Inductive Insert a 0 1 pu transmission line in the secondary of one of the transform
91. assed as either unit or non unit protection Tripping is for the most part instantaneous on detection of a fault yet its reach like overcurrent protection can extend into other zones Generally it is classed as non unit since there is no comparison of quantities at zone boundaries Theory The distance relay in its simplest form consists of a unit which divides the voltage at the sending end terminal by the current at the same location on a phase by phase basis via the appropriate instrument voltage and current transformers This function is indicated in Figure 107 albeit by an outdated electromechanical balanced beam type relay The balanced beam will swing over to the right hand side to close a contact not shown leading to circuit breaker tripping where V V p eI Thus relay operation gives a direct indication of the fault position measured in ohms of line impedance from the relay location Figure 107 illustrates this system overall operation It ought to be mentioned however that the relay determines only whether the ohmic distance to the fault is less than a given value i e the relay setting and operation to trip occurs only when this measured value is less than the setting It would be desirable to select this relay setting to coincide with the distance to the end of the protected feeder Unfortunately this is not possible due to the extraordinary high measurement accuracy that would be required Consider a feeder of 20 km long
92. au 56 DISTRIBUTION TRANSFORMER 2 SECONDARY METER P DISTRIBUTION TRANSFORMER 1 SECONDARY METER o 0 50 100 50 100 DYNAMIC LOAD VARIABLE VARIABLE VARIABLE VARIABLE Lt 12 13 LA 12 230 230V AC SA MAX 0600 ee 12 L3 we ooe DYNAMIC LOAD RESISTIVE LOAD 2 INDUCTIVE LOAD 2 CAPACITIVE LOAD 1 CAPACITIVE LOAD 2 INDUCTIVE LOAD 3 RESISTIVE LOAD 3 CONTROL Figure 9 The Distribution and Utilisation Bus DOUBLE BUS PROTECTION BUS B D1 A OVERCURRENT EARTH FAULT TRIPS CB20 AMK DISTRIBUTION TRANSFORMER 1 PRIMARY METER L CB23 DISTRIBUTION TRANSFORMER 1 PROTECTION CB22 DISTRIBUTION TRANSFORMER 1 PRIMARY TAP CHANGE SWITCH 2 5 0 2 5 5 0 50 DISTRIBUTION TRANSFORMER1 AR Y 1 5 475 e 10 096 10 0 D1 A e EARTHING TRANSFORMER 1 e e DISTRIBUTION TRANSFORMER 1 SECONDARY METER M oi 0 1 7 DAM XX EARTH FAULT 1 7 TRIPS CB25 then CB23 CB25 TP20 UTILISATION BUS 0 1 D1 B CB28 12 5 12 5 25 50 100 VARIABLE
93. bled setting group cannot be set as the active group When using the PC and front port only the active setting functions will be visible The configuration column also allows all the setting values in a group of protection settings to be copied to another group To do this first set the Copy from cell to the protection setting group to be copied then set the Copy to cell to the protection group where the copy is to be placed The copied settings are initially placed in the temporary scratchpad and will only be used by the relay following confirmation Page 32 NE9270 Power System Simulator 3 2 Measurement and Data logging in MiCOM relays and Measuring Centres Measurements with the MiCOM Relays Although the main function of the Micom Relays is protection and control of the power system they are also capable of many other data management and data processing functions They divide in to two areas 1 Event and fault records 2 Disturbance records and measurements Event records provide date and time logged records of up to 250 events in which the relay is involved Fault records include information on the last five faults such as fault location faulted phases relay and CB operating time Disturbance records store typically 20 records each of 10 5 seconds long Data is sampled 12 times a cycle Up to 8 analogue channels 32 digital channels and one time channel is available The pre and post fault time can be set These record
94. boundary A fault between the CB and CT would not be detected by feeder protection and the fault would continue to be fed through the feeder Page 133 NE9270 Power System Simulator Zone Boundaries M Figure 99 Overlapping Protection Zones b Figure 100 Protection Zones No Overlap Back up Protection Both main and back up protection is provided on all primary plant and feeder circuits the main protection being a fully discriminative type Below 275 kV back up protection is provided by IDMT Overcurrent relays at 275 kV and 400 kV a second main protection is provided which is fully discriminative Back up protection possesses its own CTs and relays 7 3 Overcurrent Protection As pointed out in the introduction to the previous section when power systems increase in extent and capability fault currents become large and it is no longer sufficient to discriminate between distant faults and faults close up to the source of supply simply on a time basis Equipment close to the source would carry too large a current for too long a time It is therefore necessary to combine current grading with time grading to achieve minimum operating time for all the relays on the system This is achieved by having relays with an inverse time current characteristic so that the larger the fault current the shorter the time of operation Overcurrent relays can have characteristics of various shapes from n
95. ce fault levels were enormously increased as were the importance and cost of equipment involved C Isolation of faulted lines etc was required to maintain system stability Basic Types of Protective Scheme There are two basic types of protective scheme Unit and Non unit Non Unit Protection These schemes do not protect a particular element of the power system the limit of their reach depends on the accuracy with which the protective equipment is designed manufactured and applied the complete set of protective gear is applied at one point only in the system This group includes the fuse and overcurrent relay their components can in most cases be generalised as shown in Figure 97 The quantity or quantities in the power system are too large to be measured directly so sensing devices reproduce each quantity faithfully on a much reduced level these devices include the current transformer and the linear coupler the voltage transformer and capacitor voltage transformer The components of information that best determine the condition of the system are then chosen This may be done by a summation transformer a sequence network or by mixing transformers in a distance relay scheme The information is fed to a measuring device or relay element that produces an output when the fault setting is exceeded In numerical relays much of this logic is carried out in software and digital signal processors The output is small and is amplified unti
96. cessary to inhibit both the restricted earth relay and the standby relay The Overcurrent relay on the primary side of the transformer should have an operating time of 0 30 5 This is as a back up for the differential protection Now apply a fault to earth at TP1 through the 9 6 inductor provided The differential element of the relay should trip b The star winding has two tapping points at which earth faults can be connected they are at 20 TAP A and 40 TAP B of the star winding measured from the star point Their connections are at the central test area of the PSS marked TPA and TPB Apply an earth fault at the 40 and 20 winding tap points through the 9 6 inductor The relay should not trip The equation given in the earlier Section 7 5 Winding Faults can be used to calculate the the maximum value of earthing resistor R that will allow the relay to trip for internal earth faults For the Grid Transformer 2 2 I relay 7220 555x x7 R 3R x 415 x 7 1 For a nominal setting current of 2096 the actual tripping current is 0 165 A as given earlier Thus 33 84 x X Hence R may be calculated for various distances from the star point of the winding For 20 of the winding Tap A Rz 1 350 For 40 of the winding Tap B 5 410 Various values of R can be used above and below these values to test the theory Use the 3 ohm resistor with 3396 tap in the central test area As the values of resis
97. ch the generator operates Page 59 NE9270 Power System Simulator Quadrature axis flux d Direct axis flux Quadrature axis N Direct axis N Figure 38 Flux Paths and Axes of Symmetry for Salient Pole Machine Fr Pole or direct axis gives Quadrature axis Figure 39 MMF and EMF Diagrams for a Round Rotor Generator Page 60 NE9270 Power System Simulator Figure 40 Phasor Diagram For a Salient Pole Generator Page 61 NE9270 Power System Simulator The Performance Chart for a Round Rotor Generator The voltage phasor diagram of Figure 37 can be converted to a power diagram or capability chart by multiplying each phasor by V X and neglecting resistance The resulting capability chart is shown in Figure 41 Note the specification on this chart of stator current limit rotor current limit and turbine power limit puMVA Stator Current Limit BC VI OC VE X V E X st 9 Rotor current 9 limit 2 8pu O e O B puMVA VAr Absorption VAr Generation Figure 41 Capability Chart for Turbine Generator The power factor is equal to the ratio of turbine power limit generator apparent power rating and is stated in the description of the machine i e 588 MVA 22 kV 0 85 pf three phase 50 Hz a c generator 1 pu generator MVA rating is 588 MVA Thus the turbine power limit is 588 x 0 85 MW The
98. cident with the direction of the polarizing voltage phasor and decreases to zero 90 either side of that axis The directional decision given by the product of these quantities is applied in the relay software after the current threshold and before the following associated time delay In the Micom relays as in most other relays phase fault directional elements are polarized by the quadrature line voltage and the earth fault elements are polarized by the zero sequence voltage Reverse Vic Axis of maximum directional sensitivity 0 Characteristic angle Lagging phase angle of I Figure 105 Directional Characteristics of Overcurrent Relays Thus for the line current la in Figure 105 the polarizing voltage is For most system loads la lags the phase to neutral voltage Va by 45 to 60 It is therefore desirable that the axis of the directional element is phase shifted to achieve a maximum directional signal along the actual current axis This is obtained by phase shifting the polarizing voltage Vp within the relay software The phase angle between the line current and the polarizing voltage Vp is called the characteristic angle setting This is the angle through which Vp is phase shifted Thus for most practical purposes will be set to an angle of 30 or 45 for the phase elements The angle for earth faults depends on the method of earthing and the chapter entitled Application Notes in the Technic
99. circulate secondary current as the saturated CT is effectively short circuited on the secondary side A relatively large voltage Vs is then produced across the relay causing it to trip In this circumstance the current can be reduced below the setting value of the relay by inserting extra resistance in series with the relay This resistance is known as the stabilising resistance This is shown in the lower diagram The voltage Vp across the resistor must be larger than Vc to produce the required trip current Ip the relay However Vp should be no more than half the CT knee point voltage Vy The relay trip current is usually selected between 0 05 A to 0 20 A 5 20 of CT secondary current although the relay may be unstable at the lower settings The value of the stabilising resistor to obtain the relay setting voltage can be calculated as shown in Figure 118 If a higher setting current is needed a shunt resistor may have to be connected across the relay and to obtain the required Vs Page 166 NE9270 Power System Simulator Fault Short circuit Saturated CT Relay setting current Figure 118 Principle of High Impedance Protection For Figure 118 Upper Diagram S and Vp Ik R2I Rrjy Lower Diagram ly LR Also R Rp and VA Burden Burden R VA Burden I R Winding Faults As with generator protection the diff
100. comes significant in low speed operation The software of the Drive controls includes feedback loops with integral and differential control elements Field orientation in the Power System Simulator enables the stator current of the induction motor to be decoupled into flux producing and torque producing components by implementing a 90 degree space angle between specific field components This process imparts dc motor characteristics to the induction motor with dynamic controls that are less complex and faster The software of the vector drive is configured to provide two separate controls for the prime mover Control of speed Control of power delivered by the generator Control of speed is used when the generator is operating as a single separate supply unit Control of power is used when the generator is synchronised to the Grid supply which has fixed voltage and frequency This control enables the motor generator unit to accurately simulate the behaviour of a power station generator whose electrical power output to the Grid is determined only by the mechanical power control of the turbine The excitation of the generator determines the reactive power output of the generator Speed and power are controlled on the Power System Simulator by a single speed power potentiometer situated in the central Test and Control area of the Simulator See Figure 3 A simplified diagram of the control circuit for the vector drive is shown in Appendix 4
101. condary star point of the transformer can be earthed Page 12 NE9270 Power System Simulator 2 4 The Transmission Lines The six three phase transmission lines modelled within the Power System Simulator are shown by one line schematic diagrams at the top centre of the panel The diagrams include test and connection points and are reproduced in Figure 7 Neutral lines are not included in the Power System Simulator but a single solid earth bar is provided for the connection of earth faults and for earthing star points of transformers and generators The earth bar has a single point connection to the external earth of the supply to the Power System Simulator The Power System Simulator lines operate at 220 V and the base impedance is 24 20 The per unit value of reactance for a 132 kV 275 kV overhead transmission line is typically 0 002 per km on a 100 MVA base Thus the per unit value of reactance for a 125 km line is 0 25 on a 100 MVA base A per unit value of 0 25 at 220 V and 2 kVA is 0 25 x 24 2 which is 6 05Q So Lines 4 and 5 are represented by two inductors each of 6 0 reactance nominal Each inductor is equivalent to 125 km of 132 kV line on a 100 MVA base In general the Power System Simulator nominal or base voltages of 415 V 220 V 110 V and a rating of 2 kVA are equated approximately on a per unit basis to a 275 kV 132 kV 66 kV system on a 100 MVA base If a higher voltage line with smaller per unit values is to be represent
102. ction amp Control to allow communication with its range of protection relays Modbus is a universal protocol The front port is particularly designed for use with the relay settings program 51 that is a Windows NT based software package The keypad is the most limited method of access as navigation through the menu is blind Menu Structure for Px40 relays There are small variations in display and navigation between Px40 ad Px30 relays See the P632 Technical Manual The relay s menu 15 arranged in a tabular structure Each setting in the menu is referred to as a cell and each cell in the menu may be accessed by reference to a row and column address The settings are arranged so that each column contains related settings for example all of the disturbance recorder settings are contained within the same column The top row of each column contains the heading that describes the settings contained within that column Movement between the columns of the menu can only be made at the column heading level A complete list of all of the menu settings is given in the relay Technical Manuals All of the settings in the menu fall into one of three categories protection settings disturbance recorder settings or control and support C amp S settings One of two different methods is used to change a setting depending on which category the setting falls into Control and support settings are stored and used by the relay immediately after
103. cuit Embedded generation Generation that is connected to a distribution system possibly at LV instead of HV and hence poses particular problems in respect of electrical protection Energising quantity The electrical quantity either current or voltage which alone or in combination with other energising quantities must be applied to the relay to cause it to function Independent time measuring relay A measuring relay the specified time for which can be considered as being independent within specified limits of the value of the characteristic quantity Instantaneous relay A relay which operates and resets with no intentional time delay NOTE All relays require some time to operate it is possible within the above definition to discuss the operating time characteristics of an instantaneous relay Inverse time delay relay A dependent time delay relay having an operating time which is an inverse function of the electrical characteristic quantity Inverse time relay with definite minimum time 1 0 An inverse time relay having an operating time that tends towards a minimum value with increasing values of the electrical characteristic quantity Knee point e m f That sinusoidal e m f applied to the secondary terminals of a current transformer which when increased by 10 causes the exciting current to increase by 50 Main Protection The protective system which is normally expected to operate in response to a
104. cuit Figure 70 A Simple System Page 101 NE9270 Power System Simulator Y VY u Neutral Bus Figure 71 Balanced Fault Currents Circuit A Neutral Bus X and X are in parallel Figure 72 Balanced Fault Currents Circuit B If the voltage in the faulted section is 1 0 pu voltage then the fault level VA at the fault point is 1 0 pu voltage x pu current i e equal numerically to 7 pu Sometimes the faulted section of the system is connected through a busbar to a larger power system If the fault level at the busbar is known then the power system which produced that fault level may be made equivalent to a 1 0 pu voltage generator and a series reactance X pu The fault level for the equivalent system is 1 0 1 0 x pu Y 1 hich i to which is equa y pu Thus if the fault level or infeed from the power system is known and is equal to VA pu on the system base values then X pu 1 VA pu Page 102 NE9270 Power System Simulator D C Components of Fault Current So far it has been assumed that the only currents that flow on the occurrence of a three phase short circuit are a c currents This is not so d c currents are also produced i t R X v t L K Figure 73 Single Line Circuit Diagram vt t EN RES C d N d 92 I t l I I t 1 es M ME i t
105. current to produce a magnetic field The strength of the magnetic field is given by the magneto motive force mmf which produces a flux density The rotor is driven by the prime mover to induce emf in each phase of the stator winding When the stator phase windings carry load current I they produce together a magnetic field F4 which rotates in Page 57 NE9270 Power System Simulator synchronism with the rotor This magnetic field which is called the armature reaction mmf interacts with the mmf of the rotor to produce a resultant magnetic field F This mmf produces the flux density B in the air gap of the machine which will induce the internal emf per phase of E The phasor relationship between the mmfs is shown in Figure 35a for a lagging power factor load The position of the mmf F with respect to Fr is determined by the load power factor as shown Figure 35b If the magnetic circuits of the machine are assumed to be linear so that B each of the can be considered to produce by superposition a proportional emf in each phase of the stator winding The mmf and emf phasor diagrams are therefore similar triangles Remember however that the mmf diagram is a space diagram and the emf diagram is a time diagram a b in air gap of generator EMFs and current in an armature phase Figure 35 MMF and EMF Diagrams The armature reaction mmf F4 can be considered to produce an emf E
106. d k where 1 1 _ noma _ kina k mb pu refa refa X x CY x For any other line current X and x will not equal 1 Kma and Kmp are the amplitude matching factors for the a and b windings respectively They remove dependance on the nominal currents of the transformers And the numbers compared and processed by the relay software are smaller The matching factors must satisfy the following conditions The matching factors must always be 5 The ratio of the highest to the lowest matching factors must be lt 3 e The value of the lower matching factor must be 2 0 7 Page 169 NE9270 Power System Simulator Vector Group Matching Vector group matching is required within the relay software to bring the primary and secondary relay currents into phase This is achieved by rotating the secondarylow voltage b side currents with respect to the primary high voltage a side currents according to the vector group of the transformer to be protected and for odd vector groups by multiplying by 1 N3 to retain amplitude matching l b baba l 2 7 1 E Ho b 11 x 30 V oe n Primary a Secondary b l 2 isthe Vector Matched Secondary Figure 120 Vector Group Matching for a Dy11 Transformer Vector Group 11 The relay software computes gt by the process illustrated i
107. dary currents circulate via the interconnecting pilots resulting in no relay current flowing However for a fault within the protected zone current transformer output currents do not sum to zero resulting in relay current and thus correct tripping of the line circuit breaker In practice the associated current transformers tend to saturate due to the higher value of fault current Thus for through fault conditions the comparison of in going and outgoing currents tends to be imperfect giving rise to some appreciable spill current flowing in the relay with the attendant risk of malfunction This risk is Page 164 NE9270 Power System Simulator normally overcome by using a fraction of the through fault current to restrain the relay from operating In the case of transformer protection the percentage restraint used may be typically 20 of through fault current at low values of fault current increasing to 80 at the higher current values A circuit diagram for a three phase transformer with a biased differential system is shown in Figure 116 60 MVA TRANSFORMER 600 5 A 66 33 kV 1200 2 89 A Ll s A Neutral Earthing Resistor Restraint Coils DIFFERENTIAL RELAY Operating Coils Figure 116 Three Phase Transformer Differential System Most three phase power transformers are delta star and therefore the primary and secondary line currents are 30 out of phase To bring the CT secondary currents in phase the star side of the
108. e machine and the induced emf in the stator phases remain the same The only reactance in the circuit to limit the current is a leakage reactance X which is called the transient reactance of the machine on the direct or d axis The initial transient current is therefore o Ij X This decays exponentially as the additional current in the field dies away It has a time constant of Typical values are shown in Table 6 on page 66 Additionally extra currents opposing the sudden increase of stator current occur as eddy currents in the rotor iron These currents cause a further increase in the initial current since the effective leakage reactance of the machine is further reduced This new reactance is the sub transient reactance so that I E X4 In modern high speed circuit breakers 2 cycle breakers contact separation takes place about 40 ms after short circuit initiation depending on the speed of the protection system This time is slightly longer than the sub transient time constant for small and medium sized generators and is about as long as that for very large turbine generator sets The transient reactance is therefore acceptable in calculations of short circuit currents for determining circuit breaker contact break requirements For the calculation of the initial short circuit current however X should be used When a generator is supplying load current at the time the fault occurs
109. e two values of resistance and two values for inductance These values are chosen at 25 and 50 for R3 and L3 and 50 and 100 for R2 and L2 This allows a selection of loads at 25 50 75 100 and 125 Three position switches are provided for each Load Bank for changing from thyristor controls to fixed load Tables 2 and 3 give the design currents for all loads both switched and variable Do not use the capacitor banks with the potentiometer controlled loads the capacitors have a lower impedance to the generated harmonics and may WARNING overheat Page 20 NE9270 Power System Simulator Single or R2 R3 or R2 R3 L2 L3 or L2 L3 Power Factor Combined Line Current A Line Current A Load 25 50 75 100 125 Variable O to 15 24 O to 12 32 Variable Table 2 Design Currents and Powers Loads R2 R3 L2 and L3 220 V R1 R4 L1 L4 Power Factor Resistive Inductive Line Current A Line Current A 50 or Off 3 75 1 0 Variable 0 7 6 0 7 83 Variable 100 6 35 3 27 0 94 Table 3 Design Currents and Powers Loads R1 R4 L1 and L4 2 7 Double Busbar Interconnection and Switching System The double busbar system shown in the centre of the panel is shown in Figure 16 together with its associated protection system The double busbar system consists of a Main busbar and a Reserve busbar Each busbar has two sections which may be connected by busbar sect
110. eas have to be completed DIFF REF2 IDMT1 and IDMT2 REF2 amp IMD2 refer to End or winding b of the transformer IDMT1 refers to the end a of the transformer IDMT2 is for standby earth fault protection and IDMT1 is for Overcurrent back up protection on the primary side of the transformer The relay Menu tree is shown in Figure 126 The tick marks indicate where the enables have to be made Micom P632 Parameters Device ID Config parameters DIFF Function parameters Global General functions Parameter subset 1 v for Enable settings Figure 126 Setting Menu for the Micom P632 Biased Differential Relay Differential Protection DIFF The calculations carried out by the relay have been discussed earlier namely that of the amplitude matching factors and k44 5 But these have to be calculated first to check that they meet the three conditions specified However the relay will only accept a reference power 5 6 Of 100 kVA or over Thus to obtain acceptable amplitude factors and a threshold or tripping current artificial values of Sref and V and Vp must be used The values chosen are S ref 0 40 MVA Vnom a 0 40 kV Vnom p 0 20 kV Page 176 NE9270 Power System Simulator Thus I 400 000 4 3 x 400 577A 400 000 3 x 200 1154A If the CT ratios are 1000 1 and 700 1 instead of 10 1 and 7 1 kp 1000 1154 0 8665 and 700 577 1 2124
111. ed the 6 O inductor will represent a longer length of line The nominal reactances of the line inductors are Lines 2 3 75 km 0 15pu 3 6 O Lines 4 and 5 125 km 0 25pu 6 00 Line 1 50 km 0 10pu 240 Line 6 50kmx5 0 10 5 2 40 5 The effective X R value of the inductors is approximately 12 when connected into the system This value is higher than that of real lines which is good for fault and protection studies but not so good for load flow and line loss studies For load flow and line loss studies known values of resistance can be connected into the lines Line and Cable Inductors Knowledge of the actual value of reactance and a c resistance of the line and cable inductors is important in calculating system currents It is important to know how the reactances vary with increase of current The inductors are steel cored coils made with low loss steel large section windings and air gaps to achieve as linear a voltage current characteristic as possible up to about 20 A However due to the non linear nature of the magnetising curve of the steel there will be some variation in inductive reactance over the range of current Accuracy characteristics for the line inductors are given in Figure 8 These are based on many tests made on the line inductors for Simulators The mean linearised variation of reactance with current is shown based on measured values at 8 A All inductors achieve an accuracy of 5 from 0 to 16 A at least The variatio
112. een phases while the third lamp is connected across one phase only With this circuit the lamps will vary in brightness in sequence and the speed of the variation will indicate if the incoming generator is running too fast or too slow The synchronising switch can be closed when the lamp connected across phase C is extinguished and the other two lamps are of equal brightness This is the most commonly used lamp method If the phase sequence is incorrect all the lamps will be dark simultaneously Note that the lamps must be able to withstand twice the normal phase voltage A1 B1 C1 Figure 50 Rotating Lamps Siemens Halske Method Page 69 NE9270 Power System Simulator Synchroscope Procedure The control panel and synchroscope for this procedure is shown in Figure 30 Connection is made initially between the GRID supply and the GEN 1 Bus by connecting the GRID TRANSFORMER Bus to the GEN 1 bus Either the left or right hand routes between the busbars is used see Figure 4 This procedure is for connecting Generator 1 to the main or GRID supply at the GEN 1 Busbar The synchronizing switch is therefore CB8 that is duplicated in the central control panel 1 Before switching the supply on check that the Generator Inertia switch is in position 1 and the excitation and power pots are wound down to minimum position 2 Above the Generator 1 Control Panel there is a synchroscope that has two inputs Reference Bus and Incoming Bus
113. ems the consequences of prolonged loss of connection to generation or important loads could be severe Multi section busbars provide complex interconnection of lines or feeders An external fault on one line may be fed from any number of lines connected to the busbar system The loading on the CT in that line may therefore saturate causing severe imbalance in the differential protection system Thus the stability of differential protection systems for busbars under through fault conditions is a serious problem However it can be overcome by using a high impedance relay with a series stabilising resistor The relay setting voltage and stabilising resistor are calculated from through fault stability considerations see High Impedance Relays Figures 128 and 129 show the grouping of the three CTs for each line for the measurement of earth faults and phase and earth faults For earth faults Figure 128 three parallel connected CTs produce a residual current for phase faults Figure 129 the currents in individual phases are compared by means of a fourth or neutral bus wire XG XH xd XK Differential Relay Figure 128 Grouping of the Three CTs for the Measurement of Earth Faults In Figure 129 the relay has three elements and therefore responds both to earth and phase faults This is essentially the system used in the Power System Simulator and Figure 130 shows the interconnection of CTs for earth fault detection in a two section busbar sys
114. ent in the arc between the opening contact of the circuit breaker is zero at this time making it the most convenient time to blow the arc out In HV transmission systems the X R ratio is high and therefore the resistance can be neglected in a first analysis Thus the fault current lags by nearly 90 behind the applied voltage so that the voltage will be at its peak value when the is current zero Figure 87 and Figure 88 illustrate the most common situation for circuit breakers in transmission systems Source Va Line 1 000 QUO L L vite Figure 87 Fault Conditions for a Circuit Breaker Circuit Diagram V Voltage across cb E 227 eg 2kHz Peak ot y d 0 5 5 kHz power frequency recovery volts EL Ls L V e g 10 30 kHz damped Figure 88 Fault Conditions for a Circuit Breaker Graph The generator or supply side of the circuit breaker is called the source side and the load or power transmission side is called the line side of the breaker The system on each side of the breaker will have inductive and capacitive reactance the latter being associated mainly with insulating bushings Before the fault current is interrupted the voltage at the circuit breaker is Page 121 NE9270 Power System Simulator When the fault current is interrupted the line side voltage V returns to zero while the source side voltage Vs becomes equal to the supply voltage How
115. ent in the relay e g fault record protection alarm control alarm etc the default display will be replaced by Alarm Faults Present Entry to the menu structure of the relay is made from the default display and is not affected if the display is showing the Alarms Faults present message Browsing the Settings Menu The menu can be browsed using the four arrow keys following the structure shown in Figure 21 Thus starting at the default display the key will display the first column heading To select the required column heading used the lt and keys The setting data contained in the column can then be viewed by using the U and 11 keys It is possible to return to the column header either by holding the f key down or by a single press of the clear key It is only possible to move across columns at the column heading level To return to the default display press the key or the clear key from any of the column headings It is not possible to go straight to the default display from within of the column cells using the auto repeat facility of the 1 key as the auto repeat will stop at the column heading To move to the default display the ff key must be released and pressed again Passwords There are two levels in the Menu that require a password in order to proceed level 1 and level 2 The instruction is simply Enter Password xxxx The default password at both levels is AA A A if using the PC and fron
116. ential Protection Operating Characteristic 2 Stator Earth Fault Protection As back up protection to the Differential Protection for earth faults standby earth fault protection may be provided by either a CT coupled relay in the earthed neutral connection or a voltage operated relay element connected across an earthing impedance or coupled into the earth connector through a transformer There is considerable variation in the earthing arrangements for generators Earth fault currents can range from 10 A to 200 A depending on the impedance in the star point to earth path For minimum damage high impedance is preferred and often the fault current is set with a maximum value equal to the rated current of the generator There is a limit to the percentage of the stator winding that can be protected by this method It is difficult to protect the last 596 of the stator winding as the voltage driving the fault current is too small However limiting the damage to the generator is a priority and other methods can be used to protect the whole winding Residual overvoltage neutral voltage displacement protection On a healthy three phase power system the addition of each of the three phase voltages to earth is nominally zero However when an earth fault occurs on the system this balance is upset and the sum of the phase voltages to earth is equal to a residual voltage This condition causes a rise in the neutral voltage with respect to earth which
117. ents The technical description and general operation of the PSS is contained within Sections 2 3 and 4 The technical description of the individual components of the PSS follow in Section 2 with the technical description of the protection system for each component in Section 3 Information on the central test and control section and the general operation and use of the PSS is given in Section 4 Sections 5 6 and 7 together include a set of experiments that demonstrate the use of the Power System Simulator The experiments include guidance on the procedures calculations and sufficient information to set up relays and instrumentation However it will be necessary to refer to both this manual and the relay manuals when carrying out experiments on protection systems In each section an outline of the required theory is given together with a list of references A fuller treatment of relevant theory and practice is contained in A Course on Power System Engineering by Professor A L Bowden The experiments are divided into three broad areas steady state operation Section 5 fault studies Section 6 and system protection Section 7 Page 6 SECTION 2 0 Technical Description Main Components This Section provides a technical description with specifications where necessary for each of the main components of the Power System Simulator Technical Drawings for all components of the Simulator and their controls are provided with the Simulato
118. erator excitation current above 1 3A Construct a voltage phasor diagram for this load as shown in Figure 63 and compare measured and calculated values of Generator Bus voltage V Now connect a 25 switched inductive load to the utilization bus in parallel with the resistive load Adjust the generator excitation to maintain 220 V at the Distribution Bus V Record current power factor kVAr KVA and kW at the Generator Bus Repeat this procedure for a 50 switched inductive load and a 75 switched inductive load Note that the line current should not be increased above 7 0 A nor the generator excitation current above 1 3 A These are the limiting conditions for this and other similar experiments Construct phasor diagrams for the loads as shown in Figure 63 Page 86 NE9270 Power System Simulator Power Power IV VI Coso Reactive Power V V I Sing If V 1 0pu pu current is equal numerically to pu power Figure 63 Phasor Diagrams Page 87 NE9270 Power System Simulator Page 88 NE9270 Power System Simulator Experiment 5 Voltage Regulation for Constant Power Factor Load This experiment is similar to the Experiment 4 but the power factor at each step must be kept constant A value of 0 89 is chosen for the power factor so that the switched loads of Table 2 on page 21 can be used 1 2 3 4 5 6 Set up on the Power System Simulator the system shown in Figure 62 For no
119. ercurrent zone in the direction of increasing retraining current in fault free operation It can be as high as four times the normal current in certain operating cases such as when a parallel transformer has failed Therefore the second knee point can be set m 5 for a default setting of 4 1 Tripping Current The tripping current for which the relay responds for single side feed can be determined for the primary or secondary side of the transformer from the kam z amplitude matching factors Page 172 NE9270 Power System Simulator For primary a side Iq SET E oma la gt IS the nominal setting or trip value e g 20 x 1 A vector group matching factor has to be included with the amplitude matching factor for one phase or two phase feed Depends on Differential Measuring System 1 2 or 3 and Zero Sequence Current filtering See pages 9 7 to9 9 of the Areva Technical Manual Restricted Earth Fault Protection or Ground Differential Protection To protect a greater percentage of the winding than is possible with differential protection restricted earth fault protection is used as shown in Figure 123 For external earth faults the residual current produced by the three line CTs is balanced by the CT current in the earth connection Thus all CTs must have the same ratio For internal faults no residual current is produced by the line CTs only the earth connection CT is energised The relay set
120. erential protection should include earth faults on the windings themselves Consider the delta star transformer shown in Figure 116 The star point of the secondary winding is earthed through an earthing resistor of resistance R Q If an earth fault occurs on one phase of the star winding at a distance x from the star point the voltage behind a circulating earth current is ap where is the star line voltage Page 167 NE9270 Power System Simulator The circulating fault current in the star winding is therefore R3 Referring this current to the delta side of the transformer Ig is obtained as xV V X S I RB Va where Vy is the primary line voltage see Figure 127 on page 183 The current Ig flows through the CTs two on the primary delta side No fault current flows through the secondary CTs Thus the secondary CT current which flows through the relay is xV 1 LI relay 3R V where is the CT ratio on the delta side Thus 2552 x V 5 This equation enables the relay setting or x R to be determined With a reasonably high value of resistance say 1 pu it is difficult to protect more than 40 of the winding for a relay setting of 20 Differential Protection in Numerical Relays Instead of using interposing CTs or star delta main CT connections numerical relay such as the P632 implement ratio and vector correction or ma
121. ers Each has two sockets for connection through the test points into the circuit being studied These transducers give instantaneous values of voltage proportional to system currents or voltages 1 V 40 V and either 1 V 2A or 1 V 10 A The output terminals of the transducers are BNC sockets as the transducers are normally used in conjunction with an oscilloscope or plotter They are valuable for looking at and measuring transient currents and voltages following a fault application Two other BNC connectors for Load Angle and RPM are provided for recording the transient load angle and speed of generator Gl 4 7 Remote Access to the Relays and Measurement Centres The menu tables of the MiCOM relays can be accessed not only via the front port but also via a communications link to a remote PC This allows menu cells in setting files to be displayed on the screen of a PC using 51 software or access to the SCADA S10 program for carrying out remote operation and monitoring of the power system The relays are interconnected via a shielded twisted wire pair known as K Bus Up to thirty two relays may be connected in parallel across the bus The relay rear ports provide K Bus RS485 serial data transmission and are intended for use with a permanently wired connection to a remote control centre The K Bus is connected through a protocol converter known as KITZ either directly or via a modem to the RS232 port of a PC The KITZ provid
122. ers Parameter subset 1 IDMT1 Enable yes Rush restr enabl Yes lref P 1 0 Inom lref P dynamic 1 0 Inom Characteristic P Standard Inverse Factor kt P 0 07 Min Trip Time 0 05 seconds Leave other value entries as the default entries Page 179 NE9270 Power System Simulator Page 180 NE9270 Power System Simulator Experiment 18 Grid Transformer Differential Protection It is difficult to describe set procedures for specific experiments in this application area Procedures are more investigative and the following are recommended In all experiments the Timer CB should be connected in series with the fault CB with a set time of about 0 25 s Part A Phase Fault Settings for the Differential Protection Various fault conditions can be applied at TP1 within the zone of the differential protection Using the inductor of 9 6 O in the fault path to limit the fault current apply phase to phase faults and phase to earth faults at TP1 Investigate the settings required to operate the relays in the three phases The relay setting should not be reduced below 20 of the relay rated current to retain stability for through faults Through fault stability can be tested by applying a fault out side the differential relay zone at the far end of say Line 2 Make sure the Grid Bus Protection relay is set correctly Part B Earth Faults on the Star Winding Differential Protection a For this initial experiment it may be ne
123. ers and investigate the effect its inclusion has on the division of load between the two transformers Repeat if possible with transmission lines of different values Compare measured and calculated values of power reactive power currents and voltages for the two transformers How would you insert an inductance of 0 06 pu Part D Unbalanced loads This is an exercise in symmetrical component analysis to determine the magnitude and paths of primary currents It requires knowledge of the fact that for positive sequence currents the transformer is Yd1 but for negative sequence currents it is Yd11 Investigate the current flow in the primary and secondary lines of a distribution transformer when the delta secondary supplies a single load connected between any two lines A similar experiment can be carried out on the grid transformer for a single phase load on the star connected secondary side See Figure 127 on page 183 for the current distribution in the transformer windings Page 95 NE9270 Power System Simulator 5 5 Load Flow Studies Since the Power System Simulator can have two controllable generators G1 and G2 and a grid supply and has five lines and several load points it can be used as a tutorial support for more studies of load flow analysis These studies are normally carried out in the more advanced stages of power engineering courses Load flow analysis is the solution of non linear equations relating the complex power at each
124. es signals over the communications bus that are RS485 based and are transmitted at 64 kb kilo bits per second The K Bus and KITZ connections are shown in Figure 33 The KITZ and Modbus converters are small modules placed near to the remote PC The interface to the converters and remote PC is located in the side panel on the right hand side of the Simulator Page 54 NE9270 Power System Simulator Twisted pair 5485 communications link R5232 K Bus Public switched Courier moster station telephone network eg substation contra room Remote Courier master station sg area control Figure 33 Remote Communication Connection Arrangements Courier is the communications language used by Areva to allow remote interrogation of its range of relays via a K Bus and KITZ protocol converters In the Courier system all information resides within the relay Each time communication is established with the relay the requested information is loaded to the PC Each relay is directly addressable over the bus to allow communication with any selected relay The protocol includes extensive error checking routines to ensure the system remains reliable and secure An alternative to the Courier protocol is Modbus a similar master slave communication protocol for network control In the Simulator Modbus is used for interrogating the M230 Communicating Measurement Systems The interconnection bus for the M230 instruments also has an extern
125. est possible time and with satisfactory grading with other relays Other phase faults will produce less fault current and slower operating times Relay point C Fault Point TP20 The total reactance to the point of fault is 8 7 Thus the fault current at 127 8 7 Q 14 60 A at 220 V 29 20Aat110V 2 CT secondary current 29 20 14 2 09 Consider the relay characteristics in Figure 103 On the right hand side vertical axis are given the Time Multiplier settings TMS These are settings within the relay which enable the calculated setting for a TMS 1 0 to be proportionally reduced i e TMS 0 5 indicates operation in half the time calculated Note that the axes of the characteristic are log log The numbers along the X axis are multiples of the threshold current or setting current s on the secondary side of the CT The relay will operate only above the setting current This current is obtained by finding the maximum steady load current in the system The CT secondary current is then found by dividing the load current by the CT ratio This should come to about 1 Afora 1 A rated CT The value obtained is normally increased by 20 to give a margin of safety However in this case a setting current of 1 0 A would be acceptable which means the CT primary threshold current is 14 0 A Hence find the operating time for a secondary current multiplier of 2 09 2 2 09 1 0 and a TMS of 1 0 The value obtained is about 9 5 s For a minimum
126. ever before this final steady state voltage is reached there is a transient voltage oscillation This oscillation occurs because of the energy exchange between the inductances and capacitances of the system following sudden circuit interruption The natural frequency of oscillation is 1 1 H f 2n4LC and is higher for the line side voltage see Figure 88 The final value of the voltage between the circuit breaker contacts Va is the difference between V and Vs This also is shown in Figure 88 The maximum theoretical value of V is twice the supply voltage but the actual value is less due to system losses that cause damping Page 122 NE9270 Power System Simulator Experiment 10 Demonstration of Transient Over voltages on the Simulator Circuit breaker CB11 which is connected to the Double Bus Switching Scheme is a solid state thyristor switch When the CB11 lever is closed the firing circuit to the thyristor gate is switched on and the thyristor is triggered and held in a conductive state so that current can flow through it When the CB11 lever is opened the firing circuit is switched off and the thyristor becomes open circuited at the next current zero Additionally the firing circuit of the thyristor can be switched off by operation of the double bus relay at position BUS A Figure 89 shows a system which can be set up on the Simulator Figure 146 in APPENDIX 3 shows the connection diagram Line capacitors are used t
127. f the relay as shown in Figure 27 When the connection is made and the power switched on the relay will run through a self check When the relay has finished its internal checks the following message should appear Description MiCOM Pxxx 1 Open the 51 program on the PC The Start up Screen will appear See Figure 28 Click on the Relay Using the on Screen up down arrows choose the relay platform required e g Px40 for front port access 2 Click on the relay The MiCOM application Screen appears Click on the Settings and Records button Page 45 NE9270 Power System Simulator MiCOM relay Umm 25 pin download monitor port 9 pin T Y front camms port Seriol communication port 1 or COM 2 Serial dato connector Copyright permission from Areva up to 15m Figure 27 Front Port Connection 51 Startup Me E 51 IED support software IED front port acc i Exit Contact Addresse Copyright permission from Areva Figure 28 Start Up Screen 3 Settings and Records blank page appears The command options available in the tool bar are File View Device Help This Screen enables the user to edit settings under File or retrieve them from the relay using Device and edit them Edited files can then be sent back to the relay 4 Click on File in the tool bar A number of commands appear in the drop down Me
128. f the taps of the two parallel connected transformers are unequal E a circulating current will be produced as shown in Figure 66 The circulating current is given by E E 5 4 t Lip Is is mainly reactive The relationship between the voltage V and the currents flowing in the circuit are given by the parallel generator theorem or Millman s theorem see References Page 92 NE9270 Power System Simulator Line terminal markings and vector diagram of induced voltage Winding Connections Phase Main Displacement Group Number HV Windings LV Windings YyO Yy6 Dyl 30 3 Y di D y Il 30 4 Y d Il Table 8 Time Phasor Diagrams for Three phase Transformers Page 93 NE9270 Power System Simulator Page 94 NE9270 Power System Simulator Experiment 6 Three Phase Transformer Operation The following studies may be carried out on the Power System Simulator s distribution transformers The parallel connected distribution transformers can be fed from the Grid supply through Line2 The overall circuit connection diagram for experiment 6 is shown in Appendix 3 Part A is a simple introductory experiment Parts B and C are investigations of the conditions to be satisfied for efficient operation of transformers in parallel Part D is relevant to more advanced studies on unbalanced loads or faults supplied by three phase transformers Part A Primary to Secondary Ph
129. f the transformer CT ratios are chosen to suit the nominal ratio of the transformer so that out of balance current must flow for off nominal taps Page 165 NE9270 Power System Simulator Problems of CT ratio correction the V3 factor and mismatch can often more conveniently be dealt with by the use of an interposing delta star transformer as shown in Figure 117 The interposing CT allows standard ratio line CTs to be used and provides vector correction ratio correction and zero sequence compensation The interposing CT ratio is again chosen to correspond with the mid point of the tap changer range Interposing CT provides Vector correction Ratio correction Zero sequence compensation Figure 117 Interposing Delta Star Transformer High Impedance Relays An alternative means of achieving tripping stability for through faults in differential or circulating current protection schemes is to use a high impedance relay rather than relay restraint coils This relay is used extensively in busbar protection schemes and for restrictive earth fault protection where through fault current can vary considerably for the zone boundary CTs In the upper equivalent circuit in Figure 118 there is little or no current flowing through the relay if current circulates between the CTs The voltage across the relay is very small But if the CT X becomes saturated due to a large transient through fault current the other CT Y is the only CT to
130. he speed power pot before pressing the green START button for the motor Bring up the speed to 1500 rev min for 50 Hz 1800 rev min 60 Hz Close the circuit breaker CBF in the Generator field circuit Increase the excitation to give an output voltage equal to that of the Grid supply 10 Watching the lamps gently alter the speed so that the lamps change in sequence more slowly Note 11 which two lamps glow as the synchroscope is at top dead centre When these two lamps are of equal brightness close the duplicate circuit breaker CB8 which is just below the excitation pot Circuit breaker CB8 connects the Generator 1 to the GEN 1 BUS Generator 1 is now synchronised to the Grid supply The speed power pot now controls power output of the generator Generator excitation controls reactive power Page 71 NE9270 Power System Simulator Page 72 NE9270 Power System Simulator Experiment 2 Variation of Armature Current with Excitation Vee Curves Theory As stated in the General Theory a generator unit connected to a large power system has two controls a prime mover control a governor and a generator excitation control a voltage regulator The governor on the prime mover is the only control of power produced by the generator unit excitation control cannot affect the power output However excitation control does control directly the reactive power delivered by the generator This experiment is intended to demo
131. hronized at normal frequency and a terminal voltage of 150 V Apply the line line fault at TP3 The Differential Protection should operate and the start LED for Overcurrent may flicker If the voltage is increased to 220 V line the Overcurrent could trip instantaneously as well if the fault current is greater than the gt 2 Current Set of the relay presently 15 0 A Lower this setting and inhibit the Differential relay to test the instantaneous stage operation of the Overcurrent element 3 Earth Fault Protection First set up the Timer Circuit Breaker for a line to ground fault without the inclusion of the 9 6 inductor Set the Timer at 1s Run the Generator unsynchronized at normal frequency and a voltage of 230 V These values are necessarily high due to the current limiting effect of the generators earthing resistor Apply a line ground fault at TP3 The Differential Protection should trip The Neutral Voltage Displacement protection should only show a start If it does start inhibit the differential trip protection and reapply the fault to prove tripping in 0 5 see settings It will be found that if the voltage setting for 10096St EF VN3H the 100 Stator EF protection is lowered below 10 0 V the protection will trip due to third harmonic voltages under normal running and load conditions 4 System Back up Protection The voltage sensing VT for the voltage controlled Overcurrent Protection VT is positioned downstre
132. hrough the timer and its CB a three phase fault at the test point TP13 Referring to the Measurement 1 menu and Disturbance Records of the relays record the values of the phase currents in the lines 6 Compare the currents measured in steps 3 and 5 above Is there any significant difference Note that in practice prefault load currents are often neglected in calculations Part C Contribution Made to the Total Fault Current by an Induction Motor Load As discussed in Section 6 an induction motor can make a significant contribution to the initial fault current at a busbar An example is given in Figure 78 to illustrate this point A system similar to that given in Figure 78 can be set up on the Power System Simulator as shown in experiment 8 part c connection diagram in Appendix 3 The Grid Supply feeds the utilisation bus through a short line 0 15 pu and the distribution transformer DTX2 With no load on the Utilisation Busbar apply a short duration three phase to earth fault say 0 3 seconds at test point TP23a and record the fault current on an oscilloscope connected across a transducer inserted into a phase at TP23a Now start and run the induction motor from the utilisation bus and again apply a three phase fault at test point TP23 Compare the recorded fault current traces for the two load conditions The fault current trace with the induction motor will be greater at t 0 but should decay within about four cycles Page 109 NE9270
133. ided at key points Figure 23 shows their location and designation The meters are connected into the power system with 7 1 CTs at 220 V and 15 1 at 110 V The front panel of the M230 contains a liquid crystal display with three lines of characters for phases A B C for example and four push buttons for navigating the Menu two for up down between Menu levels two for left right between measured quantities See Figure 22 taken from the M230 Manual 10 EXPORT kWh 30 IMPORT kWh 1 RESET 0000000 00 0000000 00 2 RESET 20 IMPORT kvarh 40 EXPORT kvarh 3 RESET 0000000 00 0000000 00 4 RESET SETTING 05 2001 07 05 53 PF TOTAL 0 000 3 Frequency 00 000 Hz 0 0003 PHASE a 0 000 3 PHASE b 0 000 3 PHASE 000 00 W PHASE a 000 00 PHASE a dames mu 000 00 PHASE a 000 00 W PHASE b 000 00 var3 PHASE b 000 00 VA PHASE b 000 00 W PHASE 000 00 var PHASE OOVA AVERAGE A 000 0 V 000 00 W TOTAL 000 00 var 3 TOTAL 000 00 TOTAL 000 0 V LINE a b 000 0 LINE b c 000 0 V LINE c a 000 55 a b 000 55 U LINE b c 000 55 THD U LINE c a 000 0 V PHASE a AVERAGE A 000 55 THD U LINE a b 041 56 a b 000 0 V PHASE b 000 00 V 000 5596 THD U LINE b c 046 31 b c 000 0 V PHASE c 030 4696 THD U LINE c a 004 75 0000 0 mA PHASE a 0000 0 mA PHASE b 00
134. iment Front comms port Downlood monitor port Copyright permission from Areva Figure 20 Front Panel of the P142 The front panel of the relay includes the following as indicated in Figure 20 a 16 character by 2 line alphanumeric liquid crystal display LCD 7 key keypad comprising 4 arrow keys lt and U an enter key 2 a clear key and a read key 12 LEDs 4 fixed function LEDs on the left hand side of the front panel and 8 programmable function LEDs on the right hand side Under the top hinged cover the relay serial number and the relay s current and voltage rating information Under the bottom hinged cover battery compartment to hold the AA size battery that is used for memory back up for the real time clock event fault and disturbance records a 9 pin female D type front port for communication with a PC locally to the relay up to 15 m distance via an RS232 serial data connection This port supports the Courier communication protocol only a 25 pin female D type port providing internal signal monitoring and high speed local downloading of software and language text via a parallel data connection Page 29 NE9270 Power System Simulator The fixed function LEDs on the left hand side of the front panel are used to indicate the following conditions Trip Red indicates that the relay has issued a trip signal It is reset when the associated fault record is cleared from the front display Alternatively
135. ing delayed for a few seconds However if pole slipping occurs power oscillations between the system and generator can cause large torque oscillations Under these conditions it is necessary to isolate the generator from the system This is achieved by means of a pole slipping detection relay which can allow without tripping power swings up to but not greater than 90 Procedure for Demonstration of Power System Instability G1 G1TX Line 1 or Grid bus Fault point Figure 93 System for Demonstrating Power System Instability Consider the system shown in Figure 93 which may be set up on the Simulator Note that the system must be first connected from the Grid Bus to the Gen 1 Bus before Gen 1 is synchronised onto the Gen 1 Bus as described in Section 5 Apply a phase phase phase fault at connection S7 via the timed fault circuit breaker Use the timed fault circuit breaker to remove the fault after a set time Connect the oscilloscope to the transient Load Angle BNC connector Connect the Trigger connection to the external input of the oscilloscope Set the oscilloscope for single shot capture of the waveform After synchronisation inhibit the under frequency relay and over voltage relay or set them at an acceptably high value The overcurrent relay can be inhibited or set at an operating time of 1 second for a fault at S7 to act as back up for the timer Increase the power output of Generator 1 to approximately 1 kW First switch
136. inguished Fully Open Energised Make Fully Closed Transient Fault Circuit v d 4 Arcing Closing Time Time Time lt gt lt gt Operating Time Dead Time lt gt System Disturbance Time Relay ready to to further fault incidents Reclose Initiated by Protection after successful reclosure 4 gt 4 gt Dead Time Closing Pulse Time lt Reclaim Time Time Instant of Fault Reclose Operates Resets on to fault Operates Resets 4 gt Operating Time Trip Coil Contacts Arc Contacts Closing Circuit Contacts Contacts Trip Coil Contacts Arc Contacts Energised Separate Extinguished Fully Open Energised Make Fully Closed Energised Separate Extinguished Fully Open Permanent Circuit DR Arcing Closing Time Time Time 4 gt lt gt Operating Time Dead Time Relay locks out for protection re operation before reclaim Reclose Initiated by Protection time has elapsed gt gt Dead Time Closing Pulse Time Reclaim Time Starts Reclaim Time Resets Figure 104 Single Shot Auto Reclose Schemes for a Transient Fault and a Permanent Fault Page 146 NE9270 Power System Simulator Experiment 14 High Set Instantaneous Settings The MiCOM P142 relays have four stages of overcurrent settings which can be set to a variety of IDMT or DT settings By using a combination of these settings it is possible to shorten the operating time of all relays
137. ion switches CB10 and CB15 The Main and Reserve busbars may be connected by busbar couplers CB13 and CB17 Each section of the busbars has two incoming feeders with circuit breakers and isolators to select main or Reserve busbar The isolators are black two position manual switches when vertical the isolator is closed when horizontal the isolator is open A single outfeed is provided in each section each provided with a circuit breaker and isolator in a similar way to the infeeds All incoming and outgoing feeders are provided with M230 meters The busbar interconnection and switching system reflects modern practice and provides the Power System Simulator with a flexible interconnection system It also provides a means of demonstrating busbar zone protection Circuit breaker CB11 on one of the infeeds is provided with a thyristor switch in each phase These switches are for investigating transient voltages resulting from the interruption of fault current at a current zero Page 21 NE9270 Power System Simulator v sna NOILOALOYd SNE KAAM KAAM snd NIV Sn8 3AH3SdH O SL BOL bh ZL LEGO Sali NOILOALOYd V SNA INOZ 9 82 59141 L 61 8 NOILDa10 d 8 SN z INOZ SL 90 sng aAHasau snd NIV KAAM KAAM KAAM a sng NOILO3LO d sna a1anoa Figure 16 Double Busbar Page 22 NE9270 Power System Simulator 2 8 Generator 2 Infeed The Generator 2 Bus
138. ities and the distance to the fault to be given The relay has separate measuring elements for each zone and for phase to phase and earth faults Before commencing any experimental study the user must become familiar with the operation of the Menu system in the relay Technical Manual and in the 51 Software in the PC provided Locate the Group 1 Settings section The following study on the Power System Simulator illustrates the determination of the base or scheme settings Sections 2 3 and 4 in the Areva Technical Manual are particularly relevant Part A Phase Faults Zone Settings Figure 113 shows a one line diagram that should be set up on the Power System Simulator Line 2 together with the impedance of the grid transformer represents the source impedance The line to be protected is the first two sections of Line 6 0 20 pu Line 6 Line 4 0 1 pu 0 1 pu 0 1pu O 1pu 0 1 pu Grid Supply Relay P442 TP6 7 TP8 TP9 Figure 113 One line Diagram Three Zone Distance Protection Scheme The line length two sections of line 6 100km assumed The line impedance 4 8 The line angle 80 The required Zone 1 reach of the relay is Z 1 80 x 4 8 Q 3 84 280 This is a primary impedance The relay will use secondary values of impedance in its calculations obtained by multiplying the primary impedance by the CT VT Ratio The CT Ratio 10 1 The VT Ratio 220 V 110 V So CT VT Ratio 5 Primary or
139. its have five separate fixed function LEDs on their front panel These functions are P122 Grid Bus TRIP ALARM e Trip WARNING e Alarm HEALTHY I Iref e Out of Service I gt gt lref e Healthy le gt Broken Conductor e Enter The first four LEDs in the P122 units perform most of these functions Page 230 APPENDIX 5 Miscellaneous Information For future reference record the serial number of your NE9270 and the serial numbers of major ancillary components in the table below Use the following pages to record any other information which you feel may be of use Product Description Product Number Serial Number Power System Simulator NE9270 Page 231 NE9270 Power System Simulator NOTES Page 232 NE9270 Power System Simulator NOTES Page 233 NE9270 Power System Simulator NOTES Page 234
140. ively increases the a c current to be interrupted Breakers are therefore given an unbalanced short circuit current rating which is a multiple of the balanced short circuit current rating for T 80 ms and 30 The unbalanced rating exceeds the balanced rating by some 25 It must be remembered that if is a maximum at t for one phase it will not be necessarily so for the other phases This may be seen in Figure 75 the phase currents for a short circuited generator Since the steady state short circuit currents for the three phases must add to zero at tg so must be corresponding d c components in the three phases Page 104 UU LU AAA DC Component DC Component LEER ANA M MITT AREE Figure 75 Phase Currents for a Short Circuited Generator NE9270 Power System Simulator Further Phenomena caused by Machine Operation Induction Motors Although induction motors are primarily loads they are able to generate current into faults for short periods The problem was recognised in the UK in the late 1960 s and was highlighted through measurements The curves shown in Figure 76 were obtained following tests on a large induction motor Terminal voltage 11 kV Phase Currents Figure 76 Test Curves The simplest method of handling induction motor fault currents is to consider the a c component only which starts off at a high value and decays rapidly Initial fault currents are
141. kets connected into a three phase line They are divided into two sets and b Each set consists of a red yellow and blue socket An external connection must be made between the a sockets and b sockets for current to flow between them Special loop connectors are provided to link a and b sockets Other leads and loop connectors are provided to enable external devices to be inserted between the a and b sockets There are in addition two single test points TPA and TPB for tapping into the secondary winding of the Grid Transformer Additional test points are also included on the line and are marked MP1 to MP21 These are tapping points only for use with the phase angle meter which is positioned just below Link 4 on the front panel Instrumentation As well as the instruments used to monitor the operation of the Generator and its connection to the Grid there are throughout the Simulator numerical measurement centres for voltage current power factor frequency power and reactive power as considered appropriate These are described in Section 3 The phase angle meter is used for looking at the line voltages and the phase shift across three phase transformers or between lines for which tapping points MP are provided in the lines across two phases Transducers and System Monitoring At the bottom of the Test Points and Alarm section there are five Hall probe transducers two are voltage transducers three are currents transduc
142. l it is sufficient to trip the circuit breaker interrupting the fault current in the primary circuit or power system Unit Protection Unit protection or restricted protection schemes respond only to fault currents particular to one system component or clearly defined zone They compare the value of some quantity at the input of the zone with its value at the output of the zone Protective equipment must be applied at all boundaries of the protected zone so that the scheme can readily discriminate between internal and external faults In this group are the circulating current and voltage balance differential schemes together with the phase comparison carrier Page 132 NE9270 Power System Simulator current systems Unit protection can be applied throughout a system and since it does not involve time grading can be relatively fast in operation Relays in a unit protection scheme operate almost instantaneously Sensing Device Measuring Device Amplifier Figure 97 General Components of Non Unit Protection Scheme Busbar Protection Feeder Protection Figure 98 Overlapping Protection Zones a Zones of Protection Ideally system zones protected by unit fully discriminative schemes should overlap as shown in Figure 99 The location of the current transformer CT usually defines the zone boundary Where zones do not overlap as in Figure 100 protection is obtained by a back up scheme or by an extension of the zone
143. larm messages can either be self resetting or latched in which case they must be cleared manually To view the alarm message press the read key When all alarms have been viewed but not cleared the alarm LED will change from flashing to constant illumination and the latest fault record will be displayed if there is one To scroll through the pages of this record use the read key When all pages of the fault record have been viewed the following prompt will appear Press clear to reset alarms To clear all alarm messages press C to return to the alarm faults present display and leave the alarms uncleared press the read key Depending on the password configuration settings it may be necessary to enter a password before the alarm messages can be cleared see section on password entry When the alarms have been cleared the yellow alarm LED will extinguish Alternatively it is possible to accelerate the procedure Once the alarm viewer has been entered using the read key the C key can be pressed this will move the display straight to the fault record Pressing C again will move straight to the alarm reset prompt where pressing C once more will clear all alarms Changing Settings from the Front Panel To change the value of a setting first navigate the menu to display the relevant cell To change the cell value press the enter key which will bring up a flashing cursor on the LCD screen to indicate that the value can be changed Thi
144. lay is positioned on the secondary side of the transformer outside the protected zone of the transformer The CT ratios for the P122 relay are 10 1 This relay is graded with the P142 relays in the Distribution and Utilization System _ The P122 Overcurrent Relay is the simplest relay in the Simulator It also has a clearly written Technical Manual For those unfamiliar with the relays it may be the best relay to consider first Whereas most relays are best accessed through the front port and settings changed on the PC with S1 software the P122 Menu is simple enough to be accessed by the front key pad The Menu contents description is given in the Areva Technical Manual The important sub menus are Configuration Protection and Broken Conductor To get to the Configuration and the Protection menus press to Output Parameter which requires the normal AAAA Password for entry then for Configuration and by further to Protection Broken Conductor is found under the Automatic Ctrl Menu Go U from this Menu and then until Broken Conductor is found Go U to enter settings For further information see the Areva Technical Manual All protection elements trip Circuit Breakers CBs 1 and 2 Page 39 NE9270 Power System Simulator R A Y B 415 V 3 Ph B C N TL 16 A fuses A 116 tle TT a winding 7 1 415 V Dy11 C Y b
145. lectrical power output from the generator which is maintained constant by means of a wattmetric feedback from the generator See Appendix 4 The encoder still provides feedback to the speed loop but is ineffective when the generator is synchronised to the mains To achieve a load angle swing when a fault is applied to the generator the tight closed loop monitor control needs to be removed or reduced Hence it is necessary to remove the integral function 1 from the speed loop and to provide a means of varying the proportional gain P so that swings of varying severity can be produced This can be achieved electronically within the control circuitry of the vector drive and is switched into operation by means of a Generator Inertia Switch on the front panel of the Simulator See the diagram in Appendix 4 The Generator Inertia Switch under GEN 1 on the main panel has four positions Positions 2 3 and 4 are used for stability studies Position 1 which includes the integral function is used for all other operations on the Simulator With the inclusion of proportional gain for both speed feedback and power input to the speed loop the Swing Equation for the motor generator becomes 2 d do dt Or d _ 48 imd GP dd 4 6 Effective inertia of the motor generator set and Ky is the proportional of the speed loop Damping due to the speed feedback Set power P Electrical powe
146. lectricity Distribution Network Design 2nd edition by E Lakervi and E J Holmes Published Peter Peregrinus Ltd 1995 Page 199 NE9270 Power System Simulator Page 200 APPENDIX 1 ANSI IEC Relay Symbols The Per Unit System ANSI IEC Relay Symbols Description ANSI IEC 60617 Description ANSI IEC 60617 Overspeed Relay 12 Inverse Time Earth 51G Fault Overcurrent Tu Underspeed Relay 14 Definite Time Earth 51N Fault Overcurrent Jas Distance Relay 21 Voltage Restrained 51V Controlled UA I Overcurrent Relay U 26 Power Factor Relay 55 Rel Undervoltage Relay 27 Overvoltage Relay 59 Directional 32 Neutral Point 59N Overpower Relay gt Displacement Relay Underpower Relay 37 Earth Fault Relay 64 ne Undercurrent Relay 37 Directional 67 Overcurrent Relay m Negative Sequence 46 Directional Earth 67N Relay Fault Relay gt 2 gt Negative Sequence 47 Phase Angle Relay 78 Voltage Relay Thermal Relay 49 Auto Reclose Relay 79 gt I c Instantaneous 50 Under Frequency 81U Overcurrent Relay gt gt Relay Inverse Time 51 Over Frequency 810 Overcurrent Relay I Relay gt Circuit Breaker 52 Differential Relay 87 Table 9 ANSI IEC Relay Symbols ANSI American National Standards Institute IEC International Electrotechnical Commission 1 201 c V NE9270 Power System Simulator The Per Unit System Dd a Co
147. lt currents at important points in the system d Courier and Modbus communication systems for remote power system monitoring and connection to a SCADA system Central to the design is the selection and specification of system components which have similar per unit values to those of high voltage systems Real systems can be set up on the Power System Simulator and calculated values of voltages currents and power flows can be directly compared with measured values The voltages chosen for the Power System Simulator 415 V 220 V 110 line to line The choice of a 2 kVA base for the whole system gives a base current of 5 A at 220 V The base current is suitable for the operation of commercial relays through current transformers with a 1 A secondary rating This choice of base current and the corresponding base impedance of 24 2 assists together with other practical features in minimising errors in measurement due to junction resistances and relay burdens For general guidance in the selection of per unit values the Power System Simulator base values have been compared to a high voltage system of base values 275 kV 132 kV 66 kV and 100 MVA Some compromises are made in the choice of per unit values A large number of experiments can be performed on the Power System Simulator due to its flexibility and scope Therefore the experiments within this manual are specially chosen to demonstrate most of its capabilities The experiments are
148. lues of current in each section of the circuit Note that when calculating the currents using a circuit similar to that in Figure 85 a reactance of 3 x 9 6 should be inserted in the dotted line leading from the zero sequence network The three ammeters in meter K are all connected and measure the fault current and the currents flowing back to the transformers Page 117 NE9270 Power System Simulator Supply LI 1 iis _604 A 1 76200V 14 50 420 _604 A 1450 42 Q Zero 65A 539A gt qe E 14 5 Q 105 Q 14 5 Q Figure 85 Interconnection of the Sequence Networks Load Current Neglected Page 118 NE9270 Power System Simulator Analysis For Figure 85 76200 0512505 14 5 42 H2243 End A I 604 604 65 1273 A I 604 604 65 539 I 604 604 65 539 Part D Faults on Transmission Line with a Double End Feed Faults on a transmission line between two busbars each busbar connected to a generator will be fed from both ends Such a system and its analysis for a Line to line ground fault is shown in Figure 86 This system arrangement can be set up on the Power System Simulator by connecting Line 4 and line 2 between generator G1 and the grid supply GS This system is shown in the connection diagram f
149. lues of power output 1 kW 1 5 kW and 2 kW 5 Plot a graph of the armature current against the field or excitation current 19 for the three values of power generated as shown in Figure 53 NOTE For correct results do not use generator excitation levels below 80 mA or above 600 mA Page 76 NE9270 Power System Simulator Experiment 3 The Generator Performance Chart The Performance Chart of a synchronous generator provides information on the power P and reactive power delivered to a constant voltage constant frequency busbar Figure 41 earlier shows typical chart for a 588 MVA generator The chart produced is scaled in per unit on the machine rating Thus 1 per unit VA is equal to 588 MVA This base VA applies equally to the P and Q axes The length of line OB is equal to V X 4 As V line OB is 1 pu Line OC is equal to V Ef X g Thus the ratio of lines OC OB is Ef V and the per unit excitation of the generator is equal to length OC length OB The chart enables variation of both power and reactive power to be observed Experiment 2 was concerned with variation of excitation only at constant power and observing variation of armature current Experimentation in this study is intended to illustrate a Variation of reactive power Q and the load angle 5 due to variation of generator excitation at constant prime mover power b Variation of power P reactive power Q and the load angle 5 due to v
150. m is essential to appreciate the theoretical significance of measurements made on the Power System Simulator A summary of the per unit system is given in APPENDIX 1 The base values of voltage and apparent power voltamps chosen for the Power System Simulator and of the derived base values for current and impedance are given below Base voltages 415 V 220 V 110 V line values Base voltamps 2 kVA Base currents 2 78 A 5 25 A 10 5 A Base impedances 86 0 24 2 0 6 05 O For transmission lines variation of the per unit value is possible by varying the length of the line or by parallel connection For a component such as a generator there is a need for compromise in the single per unit value chosen for electric parameters However variation of the angular momentum is possible and a number of values are provided The per unit value of the components of the Power System Simulator are given in Table 1 all to a 2 kVA base Individual component values are derived and discussed in later sections of this manual The per unit values given are nominal values which may differ slightly from the values measured on each Simulator This is particularly true for the transmission line and cable reactances whose linearity is only within reasonable error limits up to about 20 A see Line and Cable Inductors on page 13 Additionally the current transformers have an accuracy of lt 5 up to 10 times rated current It is therefore advisable to keep s
151. maximum operating time of 0 33 0 25 s which is 0 48 s But due to the inverse characteristic of relay R1 the minimum operating time at relay point R1 for a fault current of 13000 A is 0 24 s This time is less than the minimum operating time of R2 and comparable to that of R3 In some cases the minimum operating time at relay point RT may not be considered short enough In such cases an additional relay will operate due to the decrease in voltage at relay point R1 for close up faults These relays are called voltage controlled Overcurrent relays Page 135 NE9270 Power System Simulator 00001 FAULT LEVEL ae NEN NET THAT A 10 zm NITE 0001 001 0 6 2300 0 8 1 0 0 02 OPERATING TIME IN SECONDS Sec Figure 101 Overcurrent Grading Page 136 CL X VC U Lda 00712 L OOLLO 0419 L L OlLWa SINHO OV 9 VA 00S YHAWYOASNVEL NE9270 Power System Simulator Experiment 12 Grading of Overcurrent Protection for Three Phase Faults A system similar to the system illustrated in Figure 102 can be set up and studied on the Power System Simulator A one line diagram of the system on the Power System Simulator is shown in Figure 102 n A ui B n C Line 2 DTX1 4 3 i 0 15pu 4 D 127 gt 19 20 m Figure 102 Experimental Study 12 All impedances are represented by reactances System quantities referred to 220 V are typically Grid sup
152. ment 8 Part B Symmetrical Faults Loaded System 212 Experiment 8 Part C Symmetrical Faults Induction Motor Contribution 213 Experiment 8 Part D Symmetrical Faults Four Bus System 214 Experiment 9a and 9b Unsymmetrical Faults 12 Measurement and Transmission Line Faults 215 Experiment 9c Unsymmetrical Faults Transformer Terminated Line 216 Experiment 9d Unsymmetrical Faults Double End Feed 217 Experiment 10 Transient Over voltages 218 Experiments 12 14 and 15 Overcurrent Protection Relay Grading High Set and Back Trip 219 Experiment 13 Overcurrent Protection Auto Reclose 221 Experiment 16 Overcurrent Protection Directional Control 222 Experiment 17 Distance Protection 223 Experiment 18 Grid Transformer Protection 224 Experiment 19 Busbar Protection 225 Experiment 20 Generator Protection 226 APPENDIX 4 Control Circuit for the Vector Drive 227 Relay Override and Enable Buttons 228 Micom Relays Programmable LED Assignments 229 APPENDIX 5 Miscellaneous Information 231 SECTION 1 0 Introduction EE a no o 2t T 2 44 9 EM 5 T ii 7 E abona a mj Figure 1 Power System Simulator NE9270 1 1 Overview Design Philosophy The majority of educational and training courses on power system engineering normally include laboratory work on individual components of the power system including Generators Transformers e Lines e
153. mmon VA Base Base Volts LA must 1 1 must 1 A T V T3 So that Ae i Neutral Figure 134 The Per Unit System Single phase volts line volts p u volts Single phase base volts base line volts Bue single phase VA _ 3phase VA _ Single phase base VA 3 phase base single phase base VA _ 3 phase base VA B m Single phase base volts 3 x base line volts Single phase base volts _ single phase base volts Base Impedance base line current single phase base VA _ base line volts ow 3 phase base VA MVA Zou Zr vo pu Zpu x i VA 202 APPENDIX 2 Protection Definitions and Terminology Back up protection A Protective system intended to supplement the main protection in case the latter should be ineffective or to deal with faults in those parts of the power system that are not readily included in the operating zones of the main protection Biased relay A relay in which the characteristics are modified by the introduction of some quantity other than the actuating quantity and which is usually in opposition to the actuating quantity Burden The loading imposed by the circuits of the relay on the energising power source or sources expressed as the product of voltage and current volt amperes or watts if d c for a given condition which may be either at setting or at rated current or voltage
154. mo j mo A Ajddns 5 In _ ______ 5 Addns a alii euoz 2 lt 002 mo Figure 131 Full Double Busbar Schematic Page 186 NE9270 Power System Simulator Experiment 19 Busbar Protection Study of References 9 and 10 together with the relay manuals is advised in order to determine the setting current for these relays The stabilising resistor of these relays has been set to 180 Calculations using the equation Vs VA Ip Ip obtained from Figure 118 show that for a setting current of 0 20 A the stabilising resistor is 178 Q The maximum available value of this resistor is 220 at setting currents much lower than 0 20 the resistor required is greater than 220 The CT knee voltage is 81 V the VA burden is 1 VA and the minimum setting voltage Vs is assumed equal Vp and to 2 Two test points are available for applying faults to the two sections of the main busbar TP13 and TP14 TP13 is positioned near the section breaker and should therefore operate for both overlapping zones Faults at TP14 should operate the right hand section only Zone 2 Also within the section zones are TP11 12 15 and 16 on the feeders The PSS Drawing HV Bus 79963 should be consulted for full details Apply phase phase not phase phase phase faults via the test inductor X and the timed ciruit breaker set at 0 3 seconds The relays should not operate for through
155. move the fault Setting the Timer The timer has a digital time display The timer has a reset mode and display keys The reset key resets the operating time indicator The mode key shifts from Run mode to Set mode when it is required to enter a set time in the lower display To go back to Run mode from Set mode press the Display key Using the four up keys numbered 1 to 4 sets the time Pressing any of these keys increases the digit displayed from 0 to 9 then to 0 again i e cyclically A decimal point is displayed initially between the fourth and third digit In this position the maximum set time is 9 999 seconds Trying to go above this value will move the decimal point to between the second and third digits This process is repeated to move the decimal point further to the right Note TO recommend that your fault times are less than 9 95 seconds Page 53 NE9270 Power System Simulator 4 6 Test Points Transducers and Instrumentation Test Points There are twenty four test points throughout the Simulator They are invaluable not only for inserting monitoring and recording equipment but also as additional points of interconnection between components They increase considerably the flexibility of the Simulator The twenty four test points are alongside the test points 558 and 559 so that connections can be easily made between three phase cable connections and the test points See Figure 30 Each test point consists of six soc
156. n 6 Gen Rotor Angle Unstable 80 Stable 40 0 2 0 4 0 6 0 8 1 0 1 2 1 4 Time secs Figure 92 Transient Stability The Swing Curve Page 125 NE9270 Power System Simulator Figure 92 shows a typical swing curve of a generator for both stable and unstable conditions This curve describes the variation of 5 with time and can be solved numerically by computer It is expressed mathematically in its simplest form as 2 P P MES dt where M is the angular momentum of the generator unit This is a simple description of the fundamental concepts of stability analysis which is a very large subject Further study of the subject may be made using the books mentioned in References Page 126 NE9270 Power System Simulator Experiment 11 Stability Studies Scaling the Angular Momentum of the Generator Unit The motor generator set has a closed loop control consisting of an inner torque or current loop and an outer speed loop The speed loop has set inputs including feedback from a digital encoder fitted to the drive shaft of the motor set The digital encoder has 1024 pulses rev which allows the transient variation of 5 to be obtained by means of a specially designed electronic circuit The angle 5 may be obtained from the BNC terminal marked Load Angle in the Transducer section of the main panel When the generator is synchronised to the mains a set input to the speed loop determines the e
157. n Zone 1 These relays are connected to current transformers on either side of the bus section switch and on each incoming and outgoing feeder All current transformers have a ratio of 7 1 The Zone 1 relay trips CBs 10 11 12 14 15 The Zone 2 relay trips CBs10 15 16 18 19 Distribution and Utilisation Bus The main protection for the distribution system is provided by four P142 relays two in each branch of the system one on the primary side and the other on the secondary side of the distribution transformers Figure 19 shows the connections for the P142 relays The four relays provide not only time current characteristics but also a wide range of other features Fault current operating time and voltage data are amongst the information provided by the relay The CTs for the P142 relays are 7 1 on the primary side and 14 1 on the secondary side The relays can be set to provide together with the Grid Bus Overcurrent relay graded protection for the system Auto reclose can be used in feeder protection and directional control of relays can be investigated in the protection of parallel transformers or feeders Circuit breaker fail and back trip can also be investigated Page 44 NE9270 Power System Simulator 3 5 Essential Operating Procedures Reading Fault Records from a Relay Front Panel When a relay trips alarm messages will be indicated by the default display on the relay screen and by the yellow alarm LED flashing The a
158. n Figure 120 The only setting information to be input to the relay is the vector group identification number provided that the phase currents on both sides of the transformer are connected in standard configuration There are 11 groups altogether given on pages 3 101 to 3 103 of the Areva P632 Technical Manual No vector group matching operation is carried out on the primary high voltage side Zero Sequence Current Filtering However suppose that the primary phase windings are connected in a star or Y configuration the star point of which is grounded In the event of system faults to ground the circuit for the zero sequence component of the fault current would close via the grounded star point that lies within the transformer differential protection zone and would thus appear in the measuring systems as differential current The consequence would be undesirable tripping For this reason the zero sequence component of the three phase system must be eliminated from the phase currents on the high voltage side by filtering In accordance with its definition the zero sequence current is determined from the phasor sum of the amplitude matched phase currents If the secondary low voltage side is connected in star as it is in the Simulator zero sequence filtering must also be applied This is illustrated in Figure 121 Page 170 NE9270 Power System Simulator I I 2 gt I I gt I SIME gt 1 gt I A gt I
159. n below 8 A is not greater than 3 At 30 A the percentage variation varies between 10 and 14 The reactances of the line and cable inductors although provided should be measured at 8A prior to Carrying out any experiments on the Simulator The a c resistance of the inductors should also be measured The measured values of reactance X and resistance R should then be entered in the right hand columns of Table 1 Figure 8 can then be used to determine the best value of reactance for a particular experiment Page 13 NE9270 Power System Simulator LINE CAPACITOR 1 LINE CAPACITOR 2 S12 CABLE 1 S22 CABLE 2 531 536 544 LINK 3 CABLE 3 39 S47 LINE CAPACITOR 3 CABLE 4 521 I 1 S29 4 LINE 5 533 LINE CAPACITOR 4 2 1 S51 4 Figure 7 The Transmission Lines Page 14 NE9270 Power System Simulator Percentage 25 30 A C current A Figure 8 Mean Percentage Variation of Coil Reactance with Current Based on Value Measured at 8 A Line Capacitances Two switched line capacitors have been provided at each end of the lines with two four pin connectors They may be connected into a line to form n or sections The value of the switched line capacitors Line Capacitor Number Position 1 uF Position 2 uF Position 3 uF Position 4 uF Capacitors are connected between line and ground At 220 V
160. nce Figure 80 Symmetrical Components When a vector is multiplied by a the magnitude remains unchanged but the phase angle is advanced by 120 Using this operator all the phase currents may be defined in terms of the a phase symmetrical components since 2 2 2 L Lgtl tl I Lgt l t al a 4 Page 113 NE9270 Power System Simulator Solving the equations gives the symmetrical component values in terms of the phase values a a a Lo 3U 1 1 I SU 471 Lj SU 4 1 al 5 By applying Equations 5 the symmetrical component values may be derived from any three unbalanced phasors Having derived the symmetrical component values each component is assumed to flow in a separate network containing only that component When a solution is obtained for each component separately they are superimposed using Equation 4 to form the unbalanced phase values Since each of the symmetrical components is a balanced set of vectors a single phase calculation can be conducted for each network The technique therefore enables an unbalanced problem to be resolved into three problems each within a self contained balanced circuit In a three wire system the three phase currents sum to zero In a four wire system the neutral current is given by L d but since 1 EE ANA a I 31 9 n a Neutral currents are therefore directly related to zero phase sequence currents Sequence Impeda
161. nces of Power System Components In general different power system devices have different circuits and impedances to the different sequence components The negative impedances of lines and transformers are equal to their positive sequence impedances The negative sequence impedance of a generator is approximately equal to its sub transient reactance Earth Figure 81 Equivalent Circuit Page 114 NE9270 Power System Simulator The zero sequence impedance of lines may be two to three times larger than the positive sequence impedance The zero sequence reactance of a core type transformer is equal approximately to its positive sequence leakage reactance but the zero sequence equivalent circuit of a transformer depends on its winding and earthing connections see Figure 81 and References The zero sequence impedance of a generator is very small and often neglected Analysis of Unbalanced Fault Currents The analysis of unbalanced faults based on symmetrical components is included in most textbooks on power system analysis and will not be summarised here see References 50 4 X X x 71 0 7 W km __ 654 d 72 60 60 11 132 kV 70 21 2 5 71 0 2 pu Z2 0 15 ZO Figure 82 Schematic Diagram Analysis of a line to Ground fault on an Elementary Power System Load Current Neglected E 580 290 35 BE 4650 290 35 Q
162. nd three pole auto reclose with check synchronizing Fault currents are calculated and impedances measured Quadrilateral impedance characteristics define up to 5 Zones of protection Figure 26 shows the relay connection to the systems The relay requires both CTs and VTs because it measures impedance and thereby the distance to a fault on a line The phase voltage input on the supply side of the circuit breaker is for check synchronization i e for comparing the phase of the voltage on either side of the circuit breaker in order to determine the right time to reconnect the line to the supply lt Junction S8 Junction 54 gt ey VBUSBAR A B 10 1 t tact 1 3 220 110 V NE a VB Vc Junction S11 Figure 26 Relay P442 Distance Protection CT and VT Arrangements Page 43 NE9270 Power System Simulator Double Busbar Interconnection and Switching System Refer to Figure 16 Protection is provided for two zones of the busbars by a high impedance differential protection scheme This arrangement enables the principles of busbar protection to be demonstrated It does not fully represent a practical system which would consist of four zones of protection plus a check protection scheme See Section 7 Space does not permit the inclusion of a full system in the Simulator The relays used for this protection are two P142 relays one for the right hand section Zone 2 and one for the left hand sectio
163. nding R 220 at Tap B 40 of winding The box provided has four resistors above and below these two values Try these resistors for the faults at Tap A and Tap B Do not use the 9 60 inductor in the earth connection View the earth fault current values in the relay measurement section If differential and restricted earth fault relays do not operate the standby overcurrent relay should operate but not before the overcurrent relay RGT for a fault at TP1 The time of operation of standby or unrestricted relays is normally seconds and as many as 10 s in practice Note the fault current paths and magnitudes shown in Figure 127 for phase and earth faults Note from the relay operate LEDs which of the phases are tripped for the faults shown Page 182 NE9270 Power System Simulator a I N3K Source RR RR I N3K I V3K b Source gt p 2I N3K Figure 127 Fault Current Paths and Magnitudes for Phase and Earth Faults Line Voltage Page 183 NE9270 Power System Simulator 7 7 Busbar Protection Within an integrated protection scheme overcurrent or distance protection provides back up protection for unit protection of feeders and expensive plant such as transformers Differential protection schemes can also be applied to busbars single multi section In simple low voltage bus bar systems it is not considered necessary but for more complex high voltage syst
164. nerator feeding a large system through a transmission system or for a simple transmission system the form of the power flow equation and of the phasor diagram is the same It must be noted that in all cases there is a maximum value for the power that can be delivered by a power system and that if resistance and capacitance is neglected this occurs when 90 Voltage Regulation A voltage phasor diagram can be drawn for the equivalent circuit shown in Figure 59 by considering the current 1 to be equal to the sum of two currents and that are at right angles to each other is in phase with V and J lags V by 90 The resulting phasor diagram for a lagging p f load is shown in Figure 60 From this diagram V V AV zn AV If 6 is small V V AV RI XI Page 82 NE9270 Power System Simulator _ PR QX V r If the load is capacitive or a leading p f load the plus sign becomes a minus sign Similarly it is seen that AV XI RI 4 P 4 _ PX QR V r If the load is a capacitive or leading p f load the minus sign becomes a plus sign Thus if X R 1 a flow of reactive power determines the volt drop and b The flow of power P determines the transmission angle and these statements are substantially independent of each other xL RI V AV 5 RI XI q Figure 60 Resulting Phasor Diagram for a Lagging p f Load Since inc
165. ng and switching components are distributed throughout the Simulator but system monitoring and operational controls are provided collectively and centrally on the Simulator panel These central facilities are shown in Figure 30 and include Grid supply instrumentation and monitoring points Generator instrumentation and monitoring points and generator speed excitation and power controls A synchroscope that allows two separately controlled power supply systems to be connected at specified busbars called the reference bus and the incoming bus A Test Points and Alarms section for monitoring the system Use of the generator controls and synchroscope are described in Sections 2 and 5 All other general facilities are described in the following sections Page 49 NE9270 Power System Simulator eoe eOoeeoe SYNCHRONISING LAMPS SYNCHROSCOPE REF BUS INCOMING BUS GRID BUS dj GEN 1 BUS ON VOLTAGE V SPEED POWER EXCITATION GENERATOR 1 CONTROL e e e 4 START STOP 33 X 66 X GENERATOR 2 GENERATOR 2 BUS T GENERATOR 2 INFEED METER Rb e GENERATOR 2 BUS CB36b INFEED e i SPEED POWER EXCITATION GENERATOR 2 CONTROL e TEST POINTS TP6 a b TP18 a b a b a b GENERATOR 1 FAULT TIME TRANSIENT LOAD ANGLE SPEED e e 1V 20 TRIGGER 1 200 REV MIN OPEN OPEN CLOSED e r e e e
166. nnection Diagram for Experiment 17 Page 223 NE9270 Power System Simulator Experiment 18 Grid Transformer Protection RGT RGT R X RGT RGT REF gt SB GTXB 1 O uz 0 52 S25 S26 Figure 151 Connection Diagram for Experiment 18 Page 224 558 2 TP58 NE9270 Power System Simulator Busbar Protection Experiment 19 SOYOUMS gt 10 jenuew s199 OLD 69 9 80 X JexeoJg O ess vigo lt 2 80 lt Xt vO eo LZ adu Figure 152 Connection Diagram for Experiment 19 Page 225 NE9270 Power System Simulator Experiment 20 Generator Protection 445 LOY d LOY dl sao X Figure 153 Connection Diagram for Experiment 20 Page 226 Control Circuit for the Vector Drive APPENDIX 4 y JeMod y spauuo gt Aid 24 pasop 5 pue pe qeue sny SI Cid 7942 pesiuouupu s si Ua U3UM sjn220 y 03 1ndur uy juejsuo En juejsuo2 VMS 29 eneu 038 LL Ol uonisog LO 00 uonisog Jopoou3 OJOZ JesygO juejsuoo JOJOJA OC jqeu4 Juano SL doo PIOH
167. nstrate this aspect of generator control by varying the excitation of a generator and observing the magnitude and power factor of the armature current The phasor diagrams in Figures 51 52 and 53 illustrate the result of variation of excitation for constant power output Locus of E LX and constant Source power generated is constant Figure 51 Phasor Diagram for the Variation of Eg with lg Page 73 NE9270 Power System Simulator E decreasing Leading Power Factor Lagging Power Factor E increasing Figure 52 Phasor Diagram Variation of with Eg Page 74 NE9270 Power System Simulator Per unit power output N 0 5 0 75 42 9 1 0 NOU 0 25 Zz I rne Figure 53 Synchronous Generator Vee Curves Procedure GTX GS ay X CB2 G1 G1TX Figure 54 Generator Connection Diagram for Experiment 2 Carry out the experiment on Generator 1 connected to the Grid Supply as shown in Figure 54 1 2 Generator 1 should be synchronised to the mains as described in Experimental Study 1 3 Measurement should be taken at meter MC Meter MD includes the generator transformer Page 75 NE9270 Power System Simulator 4 The power output of the generator unit is set at 500 W by adjustment of the power control Values of armature current and power factor should be recorded for various values of excitation current Repeat for other va
168. nto the relay software so that the replica impedance is correctly specified The replica impedance is equal to KZOx Z4 See Residual Compensation For Earth Faults in the relay manual The residual compensation factor KZO is equal to 1 KZO Where KS NIN For a 0 20 pu section of line the simulator KZO 0 1 Zg 41 However is typically about 2 5 This can be obtained on the Simulator by inserting an additional impedance Zz in the circuit between the fault point and earth Ze may be determined in the following way As the earth loop impedance Zp is equal to it is also equal to K 1 Z 4 Page 160 NE9270 Power System Simulator Thus the additional line impedance required is K 1 Z1 which must be equal to 327 as 3lg flows through Ze whilst Ig flows through Z1 Thus _ amp DZj Z 3 From this expression if 2 5 41 2 Thus if the line length is 0 20 pu Ze 0 10 pu This may be achieved on the Simulator by connecting Line 1 between the fault point and earth at 7 Note that for a line to ground fault only one phase of Line 1 is connected to earth A residual compensation setting has to be entered into the relay Menu which for K 2 5 is KZO 0 50780 pu Part C Power Swing Blocking Power swing blocking is only required when carrying out stability tests when Line 6 in full or in part is connected between the Gen 1 Bus and the
169. ntroduction Power system protection covers a wide range of application areas and the Power System Simulator contains a majority of them Each application area is a subject for study in its own right Whilst each application draws on a fundamental knowledge and understanding of power system analysis and engineering the protection systems techniques and relays used can vary greatly This manual is not intended to provide a course in system protection although such courses can be designed around the Power System Simulator but to demonstrate the use of the Simulator in studying the main application areas Thus guidance is given on system and scheme operation and related theory together with illustrative examples using the Power System Simulator Guidance is also given on the use and setting of all the relays but the user should refer to the relay Technical Manuals for further more detailed information Books listed in the References are particularly relevant to this section Page 131 NE9270 Power System Simulator 7 2 Principles of Power System Protection This section discusses the principles underlying the design of protective systems rather than describing individual systems or schemes Definitions and terminology used are given in Appendix 2 The components of electrical power systems are susceptible in varying degrees to faults of various kinds caused by internal failures or by external factors Faults include insulator flashover and busbar fa
170. nu New and Open Click on Open A listing of settings files appears Click on the one required for editing according to its description Page 46 5 NE9270 Power System Simulator For the Px40 range these are ne9270p142busa 9270p142busb 9270p142d1 a 9270p42d1 B 9270p142d2 a 9270p142d2 b 9270p442 2dist 9270p343 gen Click on the one to be edited The P 30 and P 20 Settings and Records screens have to be similarly accessed for the P632 and P121 relays respectively The Settings File for the P14x relay appears as shown in Figure 29 Settings and Records Courier Untitled MiCOM P142 Ei File Edit View Device Window Help x C s 42 amp gt OVERCURRENT J SYSTEM DATA EARTH FAULT 1 gt CB CONTROL CB FAIL amp I gt DATE AND TIME SUPERVISION e CONFIGURATION FAULT LOCATOR je CT AND VT RATIOS INPUT LABELS g COMMISSION TESTS OUTPUT LABELS e CB MONITOR SETUP oes Group 1 te Group gt Group 3 it Group 4 For Help press F1 Not Connected NUM 2 Copyright permission from Areva Figure 29 Settings 6 7 8 9 10 11 12 13 To modify individual settings click on Group1 Remember that Configuration generally controls the enable instructions for relay elements Settings will appear as in Figure 29 with the Protection Settings in the right hand pane To get at individual settings double click on Overcurrent for ex
171. o P will be seen by the relay A Thus a fault at P may be seen as being closer to relay A than is actually the case The relay is said to under reach Residual Compensation For Earth Faults Distance relays operate for three phase faults line line or phase faults or earth faults For phase faults it is necessary to measure line voltages and delta currents so that the relay may see the positive sequence impedance of the line Thus for phase faults LANCER e seen I N 1 1 For earth faults the determination of is not so straightforward because of the unknown nature of the fault loop from the faulted end of the line to the supply earth s The current in the fault loop depends on the total impedance of the fault loop determined by the method of earthing the number of earthing points and the sequence impedances of the fault loop The voltage drop to the fault point is the sum of the sequence voltage drops between the relay point and the fault that is Va 410 The current in the fault loop is given by I 1 1 1 And the residual current Iy at the relay point is given by 2 Where I I and I the phase currents at the relaying point From the above expressions the voltage at the relaying point can be expressed in terms of the phase currents at the relaying point the transmission line Page 157 NE9270 Power System Simulator zero sequence to positive sequence impedance ratio K
172. o provide Cs and C see Section 2 TP10 TP11a Timed Fault Switch E 220 V line Line 4 0 25 pu Line 1 0 1 pu V Vi GS 1 179 C C F 3 uF calculated frequency of V 560 Hz Figure 89 A C Circuit Interruption Test C 0 5 uF calculated frequency of V 2 5 kHz Line 4 is connected to a line capacitor and then to the thyristor switch CB11 Line 1 is connected between the a sockets of test point TP11 and the timed fault The source end of Line 1 is first connected to a line capacitor before being connected to terminals a The fault is single phase to earth and is connected at the end of Line 1 at the a terminal of TP11 and the timer CB The timer acts as back up and may be set to 0 2 s The voltages can be captured and recorded by connecting a voltage transducer and associated oscilloscope between TP10 and TP11a The source and line side voltages V and V can be similarly and simultaneously recorded by connecting two voltage transducers across the capacitors and respectively The transducers are connected to the two channels of an oscilloscope When the fault is switched on the P142 relay at BUS A will trip almost instantaneously switching off the triggering circuit to the thyristor and subsequently the fault current at the next current zero Figures 90 and 91 show the voltage waveforms obtained for the circuit in Figure 89 Various values of capacitance or line length can be u
173. of the generator 4 Keeping the power constant increase the excitation from the value obtained in 3 NOTE For correct results do not use generator excitation levels below 80 mA or above 600 mA Note the load angle 5 and reactive power at various excitations and draw on the operating chart a locus of the points on the chart defined by the values of P Q and 5 Return to the unity power factor setting and then decrease the excitation taking measurements as before 5 Keeping the excitation constant at the value set in 3 vary the power P and note the variation of the load angle 5 and reactive power Q at various values of P Draw on the chart a locus of the points defined by P Q and 6 6 The results obtained from 3 4 and 5 are illustrated in Figure 40 7 Why might the measured load angles differ from the predicted load angles 2 pu 4 kVA 2 kW Locus LET A 4e Q Figure 55 Results Obtained from Experiment 3 Ringed numbers on the diagram refer to procedure numbers from Experiment 3 Page 78 NE9270 Power System Simulator 2 a Es P PEN For a salient pole generator Kaj 2 AO For a round rotor generator sd Page 79 NE9270 Power System Simulator 5 3 General Theory of Transmission of Power and Reactive Power Equivalent Circuits Transmission lines and cables possess inductive reactance and resistance per unit length these are series parameters They also p
174. on Points Including Trip Indicators and Overrides Page 52 NE9270 Power System Simulator 4 4 Simulator Control Systems and Relay Overrides The relays within the Simulator have opto inputs and output relays which are assigned to a variety of functions external to the relays and relating to the overall operation of the Simulator regarding circuit breakers alarms and interlocks The input output designations for each relay are shown on the drawings provided with the Simulator When studying the operation of the protection schemes it is desirable at times to override a relay operation e g a protective relay may be overridden in order to time the operation of a back up relay The override function is set up at the relay concerned and the amber override button lights up when pressed see Figure 32 Within the central control panel shown in Figure 30 the relay override lamp comes on when any relay function on the simulator is overridden The lamp test button allows all relay trip lights to be tested When a relay operates and its associated circuit breaker opens the alarm sounds and the relay light flashes The alarm can be switched off by pressing the yellow Accept button shown in Figure 30 which also stops the relay light flashing The tripped circuit breaker however can not be manually closed again until the blue Reset button is pressed The relay operate lights are also switched off when the blue Reset button is pressed 4 5 Fault
175. onic Distortion THD Uab THD Ubc THD Uca Integrated Maximum Demands Maximum demand Pe Q 5 Energy Table 5 Measured Parameters The M230 has RS485 connections and a MODBUS communications protocol for remote viewing measurements Wh varh Page 36 of NE9270 Power System Simulator uonnqujsiq 1uBr youesg jure uonnqujsiq uoueJg uonnquisiq uoueJg 97 22 sng eiqnoc LZ sng uondiu2sog OZC6AN dcda Veda VIO 29 opo SOJJUSD 5 VIN uono9joJg eouelsiq sng 10jeJeuoc J0 6Jouoc sng J9ulJoJSUeJ uondiosog Cold Ered Lou 81094 19 opo Figure 23 Key Points for the Communicating Measurement Centres Page 37 NE9270 Power System Simulator Page 38 NE9270 Power System Simulator 3 4 Individual Protection Schemes and Relays This section provides identification and a brief description of individual protection schemes and associated relays for each component of the Power System Simulator identified in Section 2 A fuller explanation of
176. only the positive and negative components of current and 2 can flow through the Relay at The zero phase sequence current circulates only through the earthing transformer on the secondary side of the distribution transformer Symmetrical component analysis shows that at the point of fault 5 p so that on the primary side of the distribution transformer the current in the faulted line is gt which is equal to 2 3 The fault current on the primary side of the distribution transformer is 30 A 2 which is 15 A Thus the fault current at Relay B is 2 3 of 15 A which is 10 A The CT secondary current is 10 0 7 A which is 1 43 A The relay characteristics in Figure 103 give an operating time for the relay of approximately 1 0s for this value of current a threshold current of 1 0 A and a TMS of 0 05 Note that Relay A will not act as a distant back up as the CT ratio for A is 10 1 So the relay current may be below threshold of 1 A Page 141 NE9270 Power System Simulator Relay Point A The relay at A should act as back up to Relay B for a fault at B TP18 Symmetrical component analysis for this fault situation is given in Part of Experiment 8 Unbalanced Faults If a fault to earth is applied at TP18 fault current can circulate through the star points of both the grid transformer and the distribution transformer But only the current from the Grid transformer will flow through the CTs for the Relay D1A at Po
177. onnection cables fixed inside the Simulator To make the circuits clearer and easier to follow use the links instead of long lengths of flexible cable Use the test points 58 and 559 within the Test Points and Alarms Section to connect to individual phases of the three phase cables These provide individual red yellow and blue connection points from a cable socket 4 2 Earth Connections To study earth faults on a system it is necessary to be able to connect to earth star points of transformers and any phase at any test point throughout the system Each transformer star winding is provided with an earth connection and an earth point is provided for the test points see Section 4 An earth bar runs across the Simulator behind the panel to enable earth connections to be made The earth bar is connected to an external earth point and is separate to the earth bar for instrumentation and relay supplies within the Simulator Page 51 NE9270 Power System Simulator 4 3 Switches and Circuit Breakers CBs Supply Switches and Emergency Trip The main supply switch for the Simulator is near the left hand edge of the panel marked Main Supply MCB To switch on the Simulator press the MCB up until it latches CB1 closes automatically when the relay has performed its self test If the relay settings are not as recommended in this guide the relay will come out of service and CB1 will not close Two large red emergency stop buttons are a
178. or experiment 9d of Appendix 3 Connect a load at the Gen 1 Bus End P supplied mostly by G1 by increasing its excitation and power A two line fault can be applied between lines 2 and 4 Measurements of fault currents can be extracted from the Measurement 1 menu and Fault Records in the relays at either end of the lines Page 119 NE9270 Power System Simulator End End Q Load Positive Seq Circuit Notice Seq Circuits connected in parallel Each Seq Circuit has two parallel paths of varying impedance ratios i e Positive 0 35 0 25 1 4 Negative 0 32 0 22 1 45 Zero 0 35 0 1 3 5 Figure 86 Faults on a Transmission Line between two Busbars and Analysis for a Line to Line Ground Fault Part E Advanced Fault Studies More complicated networks can be set up as shown in Figure 79 to which unbalanced faults can be applied The experimental procedure for these experiments is the same as those given in Part D of Experiment 8 For these Experiments analysis will involve the specification of the Zbus matrices for each of the three sequences positive negative and zero See the references in section 8 Page 120 NE9270 Power System Simulator 6 3 Transient Over voltages A C Circuit Interruption Introduction When a fault is detected by a protective scheme it causes a circuit breaker to trip and to break or interrupt the fault current A C circuits are interrupted at a current zero because the curr
179. ormal inverse to extremely inverse to assist grading between relays and to grade with fuses which also have an inverse characteristic Typical relay inverse time current characteristics are shown in Figure 101 A one line diagram of the system and its protection is combined with time against fault current for each of the three relays R1 R2 and R3 Page 134 NE9270 Power System Simulator For example relay R3 operates in 0 23 s for a fault current of 1100 A at the relay point Further down the line protected by R3 the operation time is 0 34 s for 500 A The real significance of the inverse characteristic however is seen in comparing the operating times for R3 R2 and R1 Relay R2 can also operate for a fault of 1100 A at relay point R3 but in 0 48 s The difference in time between operation of the relays R3 and R2 is 0 25 s for a fault at relay point R3 This time allows for operation of the relay and circuit breaker at R3 The operating time of relay R2 at relay point R2 is 0 33 s for a fault of 2300 A which is less than 0 48 s but greater than the shortest operating time of 0 23 s for relay R3 A more dramatic reduction in operating time due to the inverse time characteristic is seen by comparing relays R1 and R2 A maximum operating time for relay R1 is defined by taking the minimum time of operation of relay R2 and adding 0 25 s say to allow for circuit breaker operation Thus at relay point R2 and a fault current of 2300 A relay R1 has a
180. ossess capacitive reactance and conductance these components are connected between the line and neutral and are called shunt parameters An equivalent circuit representing the series and shunt parameters per unit length of transmission lines is given in Figure 56 Equations for the voltage V and current on the line can be obtained based on this equivalent circuit These equations may be reduced to give only the voltages and currents at the ends of the lines V L V and 1 The impedances between the ends of the lines can also be lumped together to form the equivalent circuits shown in Figure 57 Series Impedance Z R jX per unit length Shunt Admittance Z jB per unit length Capacitive Susceptance 1 X Figure 56 Equivalent Circuit Series and Shunt Parameters per Unit Length of Transmission Line Circuit Y T Circuit Figure 57 Equivalent Circuit Impedances between Ends of Lines Page 80 NE9270 Power System Simulator Power and Reactive Power Flow in Power Systems By convention the complex power 5 is defined as S VI for a load and 5 El for a generator So that in either case by convention S P jQ if the current lags the voltage and S P jQ if the current leads the voltage where P is the real power and Q the reactive power These equations can be used to develop general equations for power and reactive power flow in power systems if the impedances of the system are
181. pendix 3 Phase phase phase faults can be applied via the timer set to 0 3 s and its circuit breaker at test point TP20 on the secondary side of the distribution transformer This is a system that will be considered later in Section 7 for grading overcurrent protection The overcurrent settings in the relays RD1A RD1B and RGTB need not be blocked for this experiment The fault duration will be long enough for records and measurements of fault current to be made in these relays Comparison should be made between calculations of fault current and recorded data in the P142 and P122 relays that can be found in the Measurement 1 menu and the Disturbance Records Refer to Section 3 of this Manual and the Relay Manuals Part B Faults on a Loaded System 1 Connect lines 2 and 3 between the grid supply and the distribution transformer DTX1 Connect test point TP13 between the lines using the Double Bus system to include meters MF and MG in the circuit See the connection diagram for experiment 8b in Appendix 3 2 Close all CBs except the load CB25 Measure the voltage at the fault point 3 Apply through the timer and its CB a phase phase phase fault at the test point TP13 Referring to the Measurement 1 menu and Disturbance Records of the relays record the values of the phase currents in the lines 4 Now supply a three phase 50 switched resistive load at the 110 V utilization busbars Measure the voltage at the fault point 5 Again apply t
182. phase Grid Transformer GTX with a phase connection of Dy11 The star point of the secondary winding can be earthed Refer to Technical Drawing 79960 for details Figure 4 shows the schematic diagram of the Grid Supply Busbar and Grid Transformer together with the test points TP1 and TP2 circuit breakers CB1 and CB2 and associated protection relay and meters as given on the front panel of the Power System Simulator The Grid Bus has two outgoing feeders connected to the Generator 1 Bus through circuit breakers CB3 CB4 CB5 and CB6 and six additional cable sockets This Mesh Busbar or Substation arrangement provides increased flexibility in the interconnection of power systems 2 2 Generator Unit G1 and Transformer G1TX On the front panel of the Power System Simulator is a schematic diagram of the generator unit G1 and Transformer G1TX including the location of test points TP4 and TP5 circuit breaker CB8 and associated protection scheme This diagram is shown in Figure 5 The interconnection of the Generator G1 and associated equipment is detailed in Technical Drawing 79961 The generator transformer is rated at 5 kVA 220 220 V and has a phase connection of Dy11 The generator stator winding is star connected The neutral end of the winding may be connected to earth through an earthing resistor of 128 O Current transformers CTs are provided at either end of each phase winding for connection of the Generator Protection relay MI
183. ply voltage 127 V phase Grid transformer reactance 1 38 Line 2 reactance 3 70 Q Distribution transformer reactance 3 600 Total 8 70 Q TXs Note that the reactances of the Line and Transformers are not exactly the same for each Simulator Given values of reactances are approximate or mean Relays The relays within the system and associated current transformers CTs Relay C MiCOM P142 Position RD1 B Voltage 110 V line CT ratio 14 1 Relay B P142 Position RD1 A Voltage 220 V line CT ratio 7 1 Relay A P122 Position RGTB Voltage 220 V line CT ratio 10 1 The standard inverse curve for the relays in all relay manuals as the IEC Standard Inverse Curve is reproduced in Figure 103 Page 137 NE9270 Power System Simulator 10 00 1 20 1 00 0 90 0 82 2 0 70 E 060 O gw 1 00 0 50 0 40 o 0 S 0 30 5 2 0 10 0 10 0 05 0 025 0 01 1 00 10 00 30 00 Current multiples of Is Figure 103 Characteristic Curve SI x 30DT Standard Inverse moderately inverse Definite Time Above 30 15 138 NE9270 Power System Simulator Procedure for Setting the Relays Part A Phase Faults Phase phase phase faults normally give the maximum fault current for which the relays should operate in the short
184. r The main supply to the Console is 380 415 V 3 phase plus neutral The supply point is on the left hand side of the Console panel Power supply is taken into the unit via terminals inside the case and through 20 A line fuses F1 F2 and F3 Technical Drawing 79960 details the main supply connections to the Simulator The main supply is switched on by a 30 A MCB The MCB has emergency and under voltage trips and is interlocked through the Emergency Stop switches and door limit switches To switch on the supply to the Simulator the MCB should be pressed up until it latches but follow the directions given in Sections 4 8 and 4 9 before switching on the Simulator or the Generator Set The Main Supply feeds the Grid Transformer and Grid Bus the Vector Drive for the Generator 1 Set the M230 and DH96 meters and the relays CB Controls and the Transducers A supply to External Equipment through 10 A fuses is also provided A large red emergency stop button is situated near the right hand edge of the Console desk The MCB trips out when the emergency button is pressed To restart the Simulator after an emergency button has been pressed the button must first be turned to release it from the locked position The optional SCADA system also includes an emergency stop feature 2 1 Grid Supply The 415 V supply is fed to a Grid Supply busbar which feeds through circuit breaker CB1 and further 16 A line fuses a 5 kVA 415 V 220 V three
185. r of magnitude than the series impedances They are however relevant to calculations of transient over voltages 6 1 Symmetrical Faults This section considers the effects of three phase or symmetrical short circuits on power system performance leading primarily to the calculation of the resulting balanced currents that flow in the system These fault currents depend on the location of the fault and the distribution and nature of the power system components In the faulted section the short circuit current is between 10 and 40 kA in high voltage systems Transient Reactances of A C Generators When a three phase short circuit is applied to the terminals of an unloaded a c generator the current that flows initially is much greater than that calculated from the steady state equivalent circuit Figure 68 shows the current in a phase of an a c generator it shows that between the large initial current and the steady state short circuit current the fault current decays over many cycles Page 99 NE9270 Power System Simulator Figure 68 Current a Phase of an a c Generator Initially the sudden change of current in the stator windings will create a magnetic field which will try to reduce the flux in the machine This change in flux however induces a current in the rotor field winding which opposes the change The increased field current cancels out the field reducing effect of the stator field therefore the flux in th
186. r output Also the angular momentum is given by M Jo where is the total inertia of the motor generator and coupling and is the synchronous angular speed The total inertia of the motor generator set in the simulator J 0 0894 Kg m Values of may be set within the software of the Vector Drive Three values of have been set and may be selected by the Generator Inertia Switch The values of that correspond to the switch positions Page 127 NE9270 Power System Simulator Position 2 2 05 Position 3 0 87 Position 4 0 45 Thus as decreases the effective inertia of the generator set increases Equation 6 does not include electrical time constants The time constants of the rotor of the motor is approximately 200 ms However the current controller of the drive boosts the current output to achieve close tracking of the current demand with minimum delay Position 1 of the Inertia Switch is the Start and Run setting for the drive Generator Protection for Power Swinging Conditions During power swinging not only does the load angle oscillate but the voltage current and power factor vary as well If the oscillations disappear in a few seconds it is desirable that the generator protection does not trip This is achieved by for example the overcurrent relay being set for faults only within the generator protection zone and the operation of the reverse power relay be
187. ransient Over voltages on the Simulator Transient Stability Studies Experiment 11 Stability Studies 7 Experiments Protection Systems Introduction Principles of Power System Protection Overcurrent Protection Experiment 12 Grading of Overcurrent Protection for Three Phase Faults Experiment 13 Multi Shot Auto Reclose Experiment 14 High Set Instantaneous Settings Experiment 15 Back Tripping Experiment 16 Directional Control of Relay Tripping Distance Protection Experiment 17 Three Zone Distance Protection Scheme Differential Protection Setting the P632 Transformer Differential Protection Experiment 18 Grid Transformer Differential Protection Busbar Protection Experiment 19 Busbar Protection Generator Protection A Main Protection Systems Experiment 20 Generator Protection 8 References APPENDIX 1 ANSI IEC Relay Symbols The Per Unit System ANSI IEC Relay Symbols The Per Unit System APPENDIX 2 Protection Definitions and Terminology APPENDIX 3 Connection Diagrams Experiments 2 and 3 Generator Control Experiments 4 and 5 System Voltage Regulation Experiment 6 Three Phase Transformers Parts A B C and D Experiment 7 Load Flow Experiment 8 Part A Symmetrical Faults Unloaded System 96 97 99 99 109 113 117 121 123 125 127 131 131 132 134 137 145 147 149 151 153 159 164 176 181 184 187 187 187 195 197 201 201 202 203 207 207 208 209 210 211 Experi
188. ratings of 1 3 A Page 97 NE9270 Power System Simulator Page 98 SECTION 6 0 Experiments Fault Currents Transient Over Voltages and Transient Stability Transient conditions are produced in a system immediately after a fault has occurred The balanced flow of energy around the system under steady state conditions has been disturbed and the disturbance takes time to fade away and the system to return hopefully to normal A fault or short circuit on the system causes transient currents and can cause transient instability There is usually a secondary disturbance following a fault and this is caused by the opening of circuit breaker contacts to isolate the faulted section of the system This causes transient over voltages In most circumstances the circuit breaker will automatically reclose after a set time in the hope that the fault has been cleared If the fault has not been cleared the breaker will make i e contacts close onto a fault The series reactances and resistances of power system components in steady state operation have been described in an earlier section These parameters are not always applicable for transient current calculations particularly for a c generators and motors these new parameters are described briefly below Shunt impedances consisting of the capacitances and insulation resistance of lines machines and switchgear may be ignored in calculating short circuit currents since they are greater by some orde
189. re carried out Parameters of the following components should be measured Generator G1 Series reactance by open circuit and short circuit test Generator Transformer G1TX Series reactance and resistance by open circuit and short circuit test e Transmission lines and cables Reactance and resistance measurement by a c and d c voltage and current up to 30A e Distribution transformers DTX1 and DTX2 Series reactance and resistance by open circuit and short circuit test Values obtained by TQ should be entered into Table 1 using the columns provided so that actual measured values are used rather than nominal values 5 2 Generator steady state operation The generator operation discussed in this initial section assumes that the machine has a cylindrical round rotor and uniform air gap and there is no saturation of its magnetic circuits Generator units consist of two elements a prime mover turbine or diesel engine and an electrical a c generator as shown in Figure 34 Mechanical energy is produced by the prime mover and converted to electrical energy by the a c generator Control of the prime mover therefore controls the electrical power supplied to the power system this is usually achieved by a governor mechanism P Mechanical P Electrical gt Prime Mover Generator Control Control of of Power Excitation Figure 34 A Generator Set Large a c generators have a rotor excited by c
190. rease in voltage whilst lagging power factor loads can cause a severe reduction not only of voltage but also of the maximum power that can be delivered Clearly for maximum power transfer and maintenance of voltage near 1 0 pu it is necessary for high power factors to be maintained Page 85 NE9270 Power System Simulator Experiment 4 Voltage Variation and Control This study is intended to demonstrate that the voltage difference between the sending end of a line and the load or receiving end depends mainly on the flow of reactive power Q and not the power P providing the X R ratio of the system 15 relatively large However the decrease in voltage at the receiving end due to reactive power flow limits the power that can be delivered Procedure 1 On the Power System Simulator use Line 2 0 15 and set up the system shown in Figure 62 and as shown in APPENDIX 3 Figure 62 Set Up for Experiments 4 and 5 2 3 4 5 6 7 For no load condition set the excitation of generator G1 to produce 220 V at the Distribution Bus Meter ML This voltage is designated V Note the voltage at the Generator Bus Meter MD This voltage is designated V Connect a 50 switched resistance load to the utilization bus Increase the generator excitation to produce a voltage of 220 V line at Vr Distribution Bus and note the voltage Vs at the Generator Bus the line current kW kVA and power factor Do not increase the gen
191. reases with voltage statements and b are particularly true at 400 kV and 275 kV the error in neglecting A altogether 15 lt 3 at 275 kV and lt 10 at 33 kV Power Flow and Voltage Regulation for Lines where Capacitance is Included A transmission line or cable absorbs an increasing amount of reactive power as the load current increases it is given by FX The line or cable will also generate reactive power equal to If the resistance of the line may be neglected large and the voltage is considered constant there will be a load on the line for which Page 83 NE9270 Power System Simulator 25 i e net VArs absorbed or generated by the line is zero From this expression _ 22 JE Pc From the general equations for a transmission line it may be shown that when the line is terminated by a load equal to L C the characteristic or surge impedance the voltage and current are everywhere on the line in phase and there is no voltage drop Le Vo Ve the power delivered by the line under these conditions is y APE AC Py the Natural Load surge impedance load of the line Reactive Power MVAr km No Load Full Load 400 kV line 400 kV cable 132 kV line 132 kV cable 33 kV line 33 kV cable sign means reactive power generated sign means reactive power absorbed Table 7 Reactive Power Generated and Absorbed by Lines and
192. ree phase star delta wound with a phase connection of Yd1 Primary tappings on each transformer are at 2 596 intervals up to 10 The two transformers have matched impedances Primary star points can be earthed The delta secondary of the transformers can also be earthed through an earthing transformer a three phase inductor with an interconnected star or zig zag winding The connection of this inductor on the delta side of the transformer is shown in Figure 12 Each phase winding is divided into two halves and one half is connected in reverse to the other Thus the inductor presents a high reactance to positive and negative sequence currents but presents a low reactance to zero sequence currents as they are all in phase Protective relays type MiCOM P142 and associated circuit breakers together with M230 meters are connected into the system on the primary and secondary sides of both transformers Six Test Points are included in this Section The loading on the Utilisation Busbar consists of a Static Loads variable and switched resistance inductance and capacitance loads Resistive three phase loads have ratings up to 3 kW See Section 2 5 b Dynamic Load The Dynamic Load consists of a cage induction motor driving a dc generator which acts as a controllable load for the motor The Dynamic load is connected to the Distribution Bus through circuit breaker CB34 positioned at the right hand end of the Distribution Bus A red lamp
193. rent is defined as the phasor sum of the matched currents on the primary and secondary sides of the transformer The restraining or bias current is defined as half the phasor difference between the currents on the primary and secondary sides of the transformer When the in feed to an internal fault from both ends is exactly the same in amplitude and angle then both currents cancel one another out i e the restraining current becomes zero and the restraining effect disappears Disappearance of the restraining effect when there is an internal fault is a desirable result since in this case transformer differential protection has maximum sensitivity The first section of the tripping characteristic is the most sensitive region with the lowest selectable threshold value j The default setting of 0 2 takes into account the magnetizing current of the transformer which flows even in a no load condition and is generally less than 596 of the nominal transformer current The first section of the tripping curve runs horizontally until it reaches the fault current line for single side feed The second section of the tripping curve covers the load current range accounting for not only the transformer magnetizing current which appears as differential current but also for differential currents that can be attributed to the transformation errors of the current transformer sets The second knee point of the tripping characteristic determines the end of the ov
194. resistors and inductors are connected in delta Each pot controls the phase angle of two thyristors connected in inverse parallel the triac connection Figure 15 shows the connections for a three phase load Page 19 NE9270 Power System Simulator Figure 15 General Connection Diagram for Delta Connected Resistive and Inductive Loads For the analysis of this circuit see the textbooks mentioned in the References or others The use of this circuit does of course result in the production of harmonics namely the third fifth seventh and ninth Such harmonics occur in real power systems and affect measured readings particularly of reactive power and power factor However the main reason for using them in the simulator is to enable the loads to be remotely controlled by a SCADA system This is achieved by using motorized potentiometers to vary the value of resistance and inductance When using the thyristor controlled loads the power P and reactive power Q should be adjusted separately using the resistive R and inductive L loads P and Q are then equal to the apparent power S VA measured for the and L loads respectively Power factor angle is given by Tan Q P To provide alternative clean loads with minimum harmonics the resistors and inductors can be used independently from the thyristor controls R1 L1 and R4 L4 have two values of resistance and one value for inductance plus an off position R2 L2 and R3 L3 hav
195. rotor current or excitation limit is typically 2 8pu When the generator delivers power at a lagging power factor it generates reactive power VArs but when delivering power at a leading power factor it absorbs reactive power The active power per phase of the generator is P VI coso From the phasor diagram of Figure 37 but neglecting R P may also be expressed in terms of the load angle 6 8sin3 1 diua 1 S Figure 42 shows the variation of P with the Power Angle Curve PAC Under steady state operation this curve indicates the power conversion capability of the generator a certain mechanical power P is supplied to the generator this curve indicates the angle 5 at which the generator will operate e g and in Figure 42 Page 62 NE9270 Power System Simulator Figure 42 Power Angle Curve for Generator The maximum power in Figure 42 at 5 90 corresponds to the theoretical stability limit indicated by line AO in Figure 41 A practical power limit is shown in Figure 41 This is obtained from the requirement that there should be typically 12 5 power MW in hand or reserve to allow for transient stability swings at any power level In a 0 80 power factor generator this requirement would mean 0 125x 0 80 0 10 MVA Hence a practical stability limit may be constructed as shown in Figure 43 Figure 43 Practical Power Limit Page 63 NE9270 Power System Sim
196. rt IDMT1 tlref P gt elapsed IDMT1 tlref N gt elapsed General Starting DIFF Starting P343 Generator Protection gt Start P142 BusA I gt Start V gt 1 Start Status CB11 Rev pwr Start Status CB12 Stator EF Start Status CB14 Freq Start Status CB13 NPS Alarm Status CB10 LED 7 V Dep O C Start Status CB15 LED 8 Any Start 142 gt 1 Start P142 D1 A gt 1 Start Status CB16 gt 2 Start Status CB18 IN gt 1 Start Status CB19 gt 1 Trip Status CB17 gt 2 Trip Status CB10 IN gt 1 Trip Status CB15 Page 229 NE9270 Power System Simulator P142 D1 B gt 1 Start gt 2 Start IN1 gt 1 Start gt 1 Trip I gt 2 Trip IN gt 1 Trip Any Start P142 D2 B Backtrip to CB23 P142 D2 A LED 1 gt 1 Start LED 2 gt 2 Start LED 3 IN gt 1 Start LED 4 gt 1 Trip LED 5 I gt 2 Trip LED 6 IN gt 1 Trip LED 7 Any Start P122 Generator Bus LED 1 gt 1 Start TRIP LED 2 gt 2 Start ALARM LED 3 IN gt 1 Start WARNING LED 4 gt 1 Trip HEALTHY LED 5 gt 2 Trip I gt lref LED 6 IN gt 1 Trip I gt gt lref LED 7 Successful Auto close le gt LED 8 Broken Conductor All the relays except the P122 un
197. s an auto reclose element The auto reclose relay operates circuit breaker CB26 A transient line fault is applied at test point TP23 To use the auto reclose press the auto reclose button For further information see chapter 2 of the P142 Technical Manual Settings can be entered into the RD2B relay via the PC and relay front port TO suggest that the following settings are entered Configuration Auto reclose Enable Group 1 Auto reclose Number of shots 3 Dead Time 1 3s Dead Time 2 9S Dead Time 3 55 CB Healthy Time 20s Start Dead Time on Protection resets Reclaim Time 9S Trip1 Main No Block Trip 2 Main No Block Trip 3 Main Block Inst Prot 1 gt 1 and gt 2 Idmt Initiate Main AR IN2 gt 1 IN2 gt 2 DT Initiate Main AR Note The operation of DT is instantaneous The reclaim time is the reset time of the relay following a successful reclosure Dead times vary according to application from 0 3 s for motors up to 10 s for industrial and domestic consumers To demonstrate the automatic operation of the relay manually remove the fault by switching the fault application breaker during either of the two dead times Page 145 NE9270 Power System Simulator Instant of Fault Operates Resets Operating Time Trip Coil Contacts Arc Contacts Closing Circuit Contacts Contacts Energised Separate Ext
198. s are in graphical form and can be examined from the front port of the relay by PC and 1 MiCOM software Measurement records contain RMS and magnitude values of quantities such as voltage and current as well as integrated quantities such as power reactive power and energy These records can be viewed on the relay or on a PC connected to the front port The RMS values are given for steady state power system operation and are calculated by the relay from the sum of the measured samples squared over a cycle of sample data These values are referred to as true r m s values as they include both fundamental and harmonic components Magnitude values of voltages are listed in the Measurement Sections of relay menus Phase angles are also given as well as sequence values and earth currents These values are produced directly from the Discrete Fourier Transform of measured samples of current and voltage The magnitude of a quantity refers to the RMS value of the Fourier fundamental component The relay protection functions use these values They are therefore important measurements for fault studies Page 33 NE9270 Power System Simulator Page 34 NE9270 Power System Simulator 3 3 Communicating Measurement Centres M230 A comprehensive measurement system is provided throughout the Simulator in addition to the measurements available from the relays Communicating Measurement Centres in the form of the MICOM M230 unit are prov
199. s can be overcome by using a reactance relay which measures only the reactive component of the line However when the fault resistance is of such a high value that load and fault current magnitudes are of the same order the reach of the relay is modified by the value of the load and its power factor and it may either over reach or under reach The reactance relay has been superseded now by relays with quadrilateral characteristics as shown in Figure 110 Most digital and numerical relays now offer this form of characteristic The polygonal impedance characteristic is provided with forward reactive reach and resistive reach settings that are independently adjustable In addition the reactance characteristic of Zones 1 and 2 is arranged to swing about the reach point in such a way as to compensate for effects of pre fault load flow and allow correct Zone 1 measurement Note that Zone 3 is offset from the zero reactance axis to cover the busbars behind the distance relay as back up to other protection This region of Zone 3 is often referred to as Zone 4 Page 155 NE9270 Power System Simulator ZONE P Programmable ZONE P Reverse ZONE 4 Copyright permission from Areva Figure 110 Earth Fault Quadrilateral Characteristics The Three Zone Scheme The most economical distance relays possess measuring elements only for Zone 1 These elements will trip instantaneously Earlier it was stated that for reasons of accur
200. s linearly from a negative maximum at the star or neutral point N to a positive maximum at the winding terminal For a stator earth fault at the star point the amplitude of the third harmonic in the voltage at the terminals is approximately doubled both when the generator is off load prior to the fault and when it is fully loaded This is also true for the amplitude of third harmonic measured in the star point voltages for an earth fault at the generator terminals The third harmonic threshold has to be set above the normal level in the system due mainly to magnetic circuit non linearities in transformers This threshold is given as VN3H in the relay Menu 3 Overcurrent Protection A two stage non directional overcurrent element is provided in the P343 relay This element is used to provide time delayed back up protection for the system and high set protection for fast tripping for internal machine faults The relay element uses phase current inputs from CTs at the terminal end of the generator The first stage has a time delayed characteristic that can be set as either Inverse Definite Minimum Time IDMT or Definite Time DT The second stage has a definite time delay which can be set to zero to produce instantaneous operation Each stage can be selectively enabled or disabled The first stage can provide protection for system faults and as such should be co ordinated with downstream protection The current setting of the second stage
201. s will only happen if the appropriate password has been entered otherwise the prompt to enter a password will appear The setting value can then be changed by pressing the f or keys If the setting to be changed is a binary value or a text string the required bit or character to be changed must first be selected using the lt and keys When the desired new value has been reached it is confirmed as the new setting value by pressing Alternatively the new value will be discarded either if the clear button is pressed or if the menu time out occurs For protection group settings and disturbance recorder settings the changes must be confirmed before they are used by the relay To do this when all required changes have been entered return to the column heading level and press the key Prior to returning to the default display the following prompt will be given Update settings Enter or clear Pressing will result in the new settings being adopted pressing will cause the relay to discard the newly entered values It should be noted that the setting values will also be discarded if the menu time out occurs before the setting changes have been confirmed Control and support settings will be updated immediately after they are entered without Update settings prompt Changing Settings by PC from the Front Port The 51 Software and Settings program within the PC provided is accessed by connecting the PC to the front serial port o
202. sed to change the natural frequency of the oscillations Note You may need several attempts before you obtain a satisfactory waveform Page 123 NE9270 Power System Simulator Ch1 2V DIV Ch2 1V DIV V V Transducers Frequency at V Ch1 625 Hz 2 ms DIV 1V 40V Frequency at V Ch2 2 66 kHz Figure 90 A C Interruption Test Source Side and Line Side Voltages Ch1 5V DIV Transducers Timebase 2 ms DIV 1V 40V Figure 91 A C Interruption Test Voltage Across Breaker V y Page 124 NE9270 Power System Simulator 6 4 Transient Stability Studies Introduction When a fault occurs on a system it causes not only transient currents but also electromechanical transients associated with the generator units connected to the system A generator unit consists of a prime mover and a generator Under normal steady state conditions of operation the electrical power supplied to the system by the generator P is equal to the mechanical power produced by the prime mover P if losses are neglected When a fault occurs on the system P will be suddenly reduced Thus gt P As cannot change instantly the power P causes the generator unit to accelerate and the surplus mechanical energy is stored in the rotating mass of the generator unit
203. sed using a single phase representation Measurements taken of system voltages support this view However there are situations where the level of imbalance is severe the most common being system faults To cater for system unbalance a different set of analysis techniques is required Simple configurations of unbalanced load can be handled by conventional circuit theory representing each phase in detail The method is tedious and can only be extended to a small range of systems without introducing interphase mutual effects To avoid these and other problems the method of symmetrical components has been devised The Method of Symmetrical Components Any set of unbalanced three phase phasors can be resolved into three sets of balanced phasors to simplify the analysis The three sets of balanced phasors used by symmetrical components are 1 Positive phase sequence phasors which are three equal phasors 120 spaced Phase rotation a b c 2 Negative phase sequence phasors which are three equal phasors 120 spaced Phase rotation a b 3 Zero phase sequence phasors which are three equal phasors all in phase These components are shown in Figure 80 The sequence component phasors are combined in the following way gt da ba Tage dut dodo daa da tla 0 3 To aid algebraic operations use is made of the 120 operator a where a 1 120 120 120 120 120 Positive Negative Zero Sequence Sequence Seque
204. sition B Analysis of the faulted circuit gives I 15 11 6 A It also shows that a ground current of 16 A flows to the star point of the distribution transformer and a ground current of 15 A flows to the star point of the grid transformer Relay B has an earth fault setting threshold of 1 0 A a TMS of 0 05 and CTs of 7 1 so that the operating time for a relay current of 15 A 7 2 14 A is therefore 0 48 s Allowing 0 30 s time grading between relays B and A the operating time for Relay A is 0 70 s Relay A has 10 1 CTs A trip time of 0 90 s can be obtained for a relay current of 15 10 A 1 50 A with an earth setting threshold of 1 0 A and a TMS of 0 05 For a fault at TP2 close to Relay A the estimated total earth fault current is 56 0 A and the Grid transformer earth current is 40 A The estimated trip time for relay A with the above settings is 0 070 5 Earthing resistance or reactance should always be used to limit fault current for close up faults to the Grid supply Setting the P142 Relays for Overcurrent Protection Refer to Section 3 of this Manual for a general description of the P142 Relay and for accessing the relay menu via the relay front port Enter the following settings into the relays RD1B and RD2B have the same overcurrent settings RD1A and RD2A have the same overcurrent settings On the PC provided with the Simulator access MiCOM S1 and open the Settings screen Under File find the relay address and do
205. t Px20 to the most sophisticated Px40 The final number indicates additional capabilities For example P141 Feeder Management Relay P142 plus auto reclose P143 plus auto reclose and check synchronizing Page 25 NE9270 Power System Simulator Overcurrent OC Stages Three Phase and Earth P122 P343 P442 P632 Overcurrent OC Stages Directional Three Phase and Earth Sensitive Earth Fault Restricted Earth Fault Voltage Controlled OC Negative Sequence OC OV Under Over voltage Neutral Displacement Under Over frequency Broken Conductor Breaker Failure amp Back Trip Auto reclose 3ph Check Synchronization Setting Groups Blocking logic Distance Protection Transformer Differential Generator Differential 100 Stator Earth Fault Loss of Field Reverse Power Measurements True RMS Instantaneous Records Fault Records Event Records Disturbance Records P142 Feeder Management Relay P122 Overcurrent Protection P343 Generator Protection P442 Full Scheme Distance Protection P632 Transformer Differential Table 4 Relays and Their Protection Functions Page 26 NE9270 Power System Simulator Relay System Overview The System Overview for a P143 is shown in Figure 19 to illustrate the organization and component parts of MiCOM relays On the left hand side
206. t port or 1 gt gt gt f then Enter using the keypad Page 31 NE9270 Power System Simulator Other default displays hose voltage 00 ma c OO mer 9 0 e amp Sytem data View records Other column headings het d Data 1 Dato 2 1 Dak No ILIE will return Data 1 2 Date 2 2 ES m cell Data n 2 Pesseword Time and date ny gt directional Other setting A Other selting A Other setting A calls in cells in calls in column column 2 column n Data d Data gt char angle Copyright permission from Areva Figure 21 Settings Menu Structure Relay Configuration The relay is a multi function device that supports numerous different protection control and communication features In order to simplify the setting of the relay there is a configuration settings column column 09 that can be used to enable or disable many of the functions of the relay The settings associated with any function that is disabled are made invisible i e they are not shown in the menu To disable a function change the relevant cell in the Configuration column from Enabled to Disabled The configuration column controls which of the four protection settings groups is selected as active through the Active settings cell A protection setting group can also be disabled in the configuration column provided it is not the present active group Similarly a disa
207. tance are small it may be difficult to determine accurately the boundary between trip and non trip A similar experiment carried out for the Restricted Earth Fault Protection with higher values of resistance may be more conclusive Note that the 9 6 ohm inductor is not used in addition to these resistors Part C Restricted Earth Fault Protection As the differential protection may not operate effectively for earth faults at the 2096 winding tap the restricted earth fault protection can be set to operate for faults at this point Page 181 NE9270 Power System Simulator For an internal fault on the transformer winding the Restricted Earth fault element of the relay may be tripped by a relay current produced only by the 7 1 CT in the earth connection of the star connected secondary winding The tripping current can be calculated using the expression given in the earlier Tripping Current Section Thus I Trip TL 0 33A or 2 3 A primary This current is produced by a value of earthing resistance R given by 124V 2 3 R x 20 or 40 for tapping points A and B respectively The actual value of secondary voltage 124 V is slightly less than the nominal value about 3 due to the drop in secondary voltage when the fault is applied This will cause a decrease in R for both restricted and differential protection The values of R calculated to achieve the tripping current at Tap A and Tap B are R 11Q at Tap A 20 of wi
208. tched the sum of the current phasors of all ends is equal to zero in fault free operation under idealized conditions Only an internal fault in the protection zone of differential protection will generate a phasor sum of end currents that differs from zero namely the differential current lg In practice however differential currents occur even in fault free operation and can be attributed essentially to the influencing factors given under Biased Differential Protection Schemes namely magnetizing current unbalanced CTs and on load tap changers Whereas the magnetizing current is determined by the level of the system voltage and can therefore be viewed as constant irrespective of load level the transformation errors of the current transformer sets are a function of the through current level The threshold value of a transformer differential protection device is therefore not implemented as a constant differential current threshold but is formed as a function of the restraining current Ik The restraining current corresponds to the current level the protected transformer The function lg is represented as the tripping characteristic The tripping characteristic for the biased differential protection provided by the relay is shown in Figure 122 Page 171 NE9270 Power System Simulator 8 00 I let 6 00 4 00 2 00 l 1 202 Figure 122 Tripping Characteristics of Differential Protection The differential cur
209. tching within the relay software thus enabling most combinations of transformer winding arrangements and CT connections to be catered for However page 3 39 of the Areva P632 Technical Manual gives a standard configuration of two star connected CTs whatever the connection of the main transformer primary and secondary The theory on amplitude and vector groups matching on pages 3 95 to 3 115 applies only to this standard configuration Selection of other CT connections requires changes in the vector group matching Amplitude Matching The requirements for amplitude matching and the determination of the amplitude matching K factors are given on p3 97 of the Areva P632 Technical Manual The reasoning behind the process is not given but can be explained simply from the diagram in Figure 119 Page 168 NE9270 Power System Simulator Figure 119 Principle of Amplitude Matching It is known that ref 43 x V u ref LH and In 1 B where S e is the nominal rating of the transformer and and are the individual reference currents for the windings These currents are calculated by the relay V and V are the nominal line voltages of the transformer The CT secondary currents X and Y are given by X amd Tacna d cuits Where and are the primary nominal currents of the CTs For a balanced System X Y If now X and multiplied by the factors 4 an
210. tection of one or more elements of a power system A protective scheme may comprise several protective systems Protection system A combination of protective gear designed to secure under predetermined conditions usually abnormal the disconnection of an element of a power system or to give an alarm signal or both Rating The nominal value of an energising quantity which appears in the designation of a relay The nominal value usually corresponds to the CT and VT secondary ratings Residual current The algebraic sum in multi phase system of all the line currents Residual voltage The algebraic sum in a multi phase system of all the line to earth voltages SCADA Supervisory Control and Data Acquisition Page 205 NE9270 Power System Simulator Setting The limiting value of a characteristic or energising quantity at which the relay is designed to operate under specified conditions Such values are usually marked on the relay and may be expressed as direct values percentages of rated values or multiples Stability The quality whereby a protective system remains inoperative under all conditions other than those for which it is specifically designed to operate Stability limits The r m s value of the symmetrical component of the through fault current up to which the protective system remains stable Static relay An electrical relay in which the designed response is developed by electronic
211. ted from the transmission system so far as earth faults are concerned The earthing policy for the generator unit can therefore be made independently from that for the transmission system Normally the generator star point is earthed through a resistor or a transformer and resistor to limit the fault current to a value no greater than the rated current of the generator 7 9 A Main Protection Systems 1 Biased Differential Protection The main protection of the stator winding for phase phase and phase earth faults is provided by a biased circulating current differential current scheme In practice both circulating current and high impedance schemes are used Page 187 NE9270 Power System Simulator The principles of Biased Differential Protection are described in Section 7 5 of this Manual The operating characteristic for P343 generator protection is shown in Figure 132 and illustrates the settings factors to be defined in the relay menu The Differential Current setting Gen Diff Is 1 is set as low as possible normally 5 of rated current Diff Is 27 the threshold above which the second bias is applied is set to 120 of rated current The initial bias slope Gen Diff k1 should be set to 0 for optimum sensitivity for internal faults the slope of the second bias slope Diff k2 is typically 150 Operate Restrain hth P2158ena Copyright permission from Areva Figure 132 Relay P343 Biased Differ
212. tem Note that the CTs mark the boundaries of the zones and that the zones overlap across the Section breaker Page 184 NE9270 Power System Simulator 2 Differential Relay boo Figure 129 Grouping of the Three CTs for the Measurement of Phase and Earth Faults Zone 1 Zone 2 KG mall T Figure 130 Interconnection of CTs for Earth Fault Detection in a Two Section Busbar System Figure 131 shows a full double busbar scheme with three protective zones The CTs on either side of the bus coupler CBs define the separation of zone C from zones A and B In addition to the three zones there is a check system which looks at both busbars as a single zone The protection for both the check system and a zone must operate for the zone relays to trip This two out of two arrangement ensures that critical plant Page 185 NE9270 Power System Simulator is not inadvertently tripped due to failure of the protection system rather than the plant itself Note the supervision relays which operate if a CT connection is broken Aejas SJOJSIS9J Buisi iqe1S e aJ uoisiAJedng X99U9 2 807 auoz V 8407 8 10 S9U91IMS JO eJOS S 9 Buneuriuuosiq s o S LO 5 12 Buneunuuosiq Ajddns GAT mo c
213. the application of the relays is given in Section 7 of this Manual Figure 23 shows the location and designation of the relays The Grid Supply Transformer GTX Protection for this transformer is provided by the P632 Transformer Differential Protection Relay The connection diagram for the transformer and relay are shown in Figure 24 Note that the correct polarity of the CTs is indicated by dot notation Note also that there are no interposing transformers in the differential connections to balance in magnitude and phase the circulating currents between CTs The relay achieves balance by calculations based on knowledge of CT ratios and the vector grouping of the transformer It makes for a neater system but information entered into the relay must be correct This is discussed in detail in Section 7 The relay possesses several elements in addition to that for the main biased differential protection for phase and earth faults These are for back up protection The first of these is the Restricted Earth Fault Protection REF or Ground Differential scheme on the LV star side of the transformer This will protect a major proportion of the star winding but not all of it A second level of back up is provided by standby earth fault protection This is an overcurrent relay with a fairly long operating time An overcurrent element is also connected to the primary CTs to provide back up for transformer faults fed from the Grid A P122 overcurrent re
214. the Generator 1 and Generator 2 Control and Synchronizing Panels adjacent to each other and the Synchroscope enables the Generators to be synchronized either as parallel generators of as a separate remote generator The connectors for linking Generator 2 with the Simulator are located on the side of the Simulator A 37 way cable socket provides low voltage dc and communicating and control links A separate 16 way power socket provides supplies and main circuit connections See Technical Drawing 79967 Page 23 NE9270 Power System Simulator Page 24 SECTION 3 0 Technical Description of Protection and Measurement Systems This Section is divided into two parts the first describes the general features of the Areva numerical relays and their main features the second part provides identification and a brief description of the protection schemes and their associated relays for each component or system of the Power System Simulator A fuller explanation of the use of the protection schemes and the setting of the relays is given in Section 7 3 1 Areva Relays Relay technology has advanced considerably since the 19807 The first major advance was the replacement of electromechanical relays by static relays in which analogue electronic devices produced the relay characteristics In the late 1980 s and throughout the 1990 s changes in relay construction became more rapid as digital technology replaced analogue The first digital
215. the Inertia Switch from position 1 to position 2 3 or 4 and then apply the fault by switching the fault breaker As soon as the fault is concluded switch back through the switch positions to Position 1 Typical traces are shown in Figures 94 95 and 96 The results depend greatly on the fault times Generator swing increases with inertia switch position and increase of power output and line length In the above system extra lines can be inserted either in place of the S5 to S6 link or in series with Line 1 Pole slipping will be identified both by the sound of the motor drive and the absence of a return swing on the oscilloscope trace Pole slipping should not occur but if it does the Inertia Switch should be quickly returned to Position 1 or stop the generator However pole slipping is unlikely as the generator is salient pole and its rating is relatively large Page 128 NE9270 Power System Simulator Figure 94 Transient Load Angle Inertia Position 2 Fault Time 0 2 s Line 1 0 1 pu Figure 95 Transient Load Angle Inertia Position 3 Fault Time 0 3 s Figure 96 Transient Load Angle Recorded Swing Curve Fault Time 0 125 Inertia Switch Position 4 Page 129 NE9270 Power System Simulator Page 130 SECTION 7 0 Experiments Protection Systems 7 1 I
216. ting can be low say 10 since this system does not suffer from any of the disadvantages of overall transformer protective systems A high impedance relay may be used to prevent imbalance of the CTs due to saturation Restricted earth fault protection on the delta side is possible using the system described for the star winding when an earth connection is provided by means of an earthing transformer Alternatively a simple residual current scheme can be connected into the delta lines See Figure 124 Residual current zero sequence current will flow in the delta supply lines due to a fault on the delta winding As a backup for the restricted earth fault protection a standby earth fault protection is provided in the earth connection This is an overcurrent IDMT relay with a long inverse time characteristic that must be time graded with other IDMT relays on the system Figure 123 Star Winding Restricted Earth Fault Protection Page 173 NE9270 Power System Simulator Source Figure 124 Delta Winding Restricted Earth Fault Protection Restricted Earth Fault Protection with Numerical Relays Numerical relays such as the P632 can be used for restricted earth fault protection as shown in Figure 123 However a biased differential scheme is used which does not require stabilizing resistors The protection function is determined by comparing the phasor sum of the phase currents of the relevant transformer winding
217. tor fault A further system backup overcurrent element is provided at the neutral end of the winding This is a voltage controlled element Normally this overcurrent element is set with a high threshold current But if a fault occurs on the power system such that the voltage at the generator terminals drops below a settable threshold the overcurrent element will switch to a lower and more sensitive setting This element should be graded with other overcurrent elements on the power system The overcurrent relay P122 Generator bus relay is one such relay Also connected into the neutral end of the stator winding is the negative sequence element Negative sequence currents flowing in the power system can cause damaging overheating of the rotor surface The setting of the relay is therefore dependent on both the magnitude and duration of the negative sequence current the Dt factor There are also several relay elements that warn of abnormal operation over voltage and over under frequency and a reverse power element detects motoring power flow into the generator from the power system Most relays trip CBs 8 and F except Reverse power and under frequency that trip CB8 only Page 42 NE9270 Power System Simulator Transmission Line Protection The P442 Full Scheme Distance Relay provides transmission line protection This relay provides single and three phase tripping for faults on overhead lines and cables It also has single a
218. tor winding the generator can still supply current to the fault even when the main breaker is open Thus it is important to trip the field circuit of the generator by circuit breaker CBF which is normally connected via a make before break contactor to a field suppression resistor to dissipate the stored energy in the field The prime mover should be shut down as quickly as possible for internal faults However this is not executed for Generator 1 as faults are simulated Page 191 NE9270 Power System Simulator Setting the P343 The following settings should be entered into the settings files for Group 1 only To assist in defining the quantities listed in greater detail than given above the page numbers in the Areva P343 Technical Manual are given in each section Configuration page 17 Ch2 Active Settings Group 1 Setting Group 1 Enabled Setting Values Primary Group 1 Group 1 Gen Diff page 17 Gen Diff Function Percentage Bias Gen Diff Is1 500 0 mA Gen Diff k1 0 Gen 0 1152 10 00 Gen Diff k2 150 0 Group 1 Power page 62 Operating Mode Generating 1 Function Reverse P gt 1 Setting 80 00W 1 Time Delay 5 005 Power1 DO Timer Os P1 Poledead Inh Enabled Power2 Disabled Page 192 NE9270 Power System Simulator NPS Thermal page 57 12 gt 1 Alarm Enabled 12 gt 1 Current Set 500 0 mA 12 gt 1 Time Delay 20 00 s
219. truments are normally used Voltmeters e Lamps one for each phase e synchroscope The voltmeter method is described on the previous page The voltmeter method is not often used The use of three lamps one for each phase allows both phase sequence determination and synchronizing to be carried out synchroscope is an analogue instrument with inputs f and f that enables f4 f to be observed convenient way The faster the instrument pointer rotates the greater the difference between f4 and f If fz is greater then f4 the pointer rotates clockwise If f is less than f4 the pointer moves anti clockwise synchroscope is in fact an analogue of the vector diagram shown in Figure 47 b The process of synchronizing must be preceded by confirmation or a test to confirm that the generators or systems have the same phase sequence of R Y B Synchronising Methods a A synchroscope has a rotating hand and a dial indicating slow and fast that refers to the frequency of the incoming generator relative to that of the existing supply The slow anticlockwise indication means that the incoming frequency is too low a fast clockwise indication means the incoming frequency is too high The speed of the incoming supply should be adjusted until the rotating hand is rotating very slowly in the fast direction When it points to the vertical index mark the synchronising switch can be
220. u Figure 77 Curve of Short Circuit Current in the Proximity of a Slightly Under Excited Generator Current curve envelopes A Short circuit on the 525 kV side of the transformer of a 1000 MVA generator transformer unit Time constant of decay of the d c component 300 ms B As shown in A but with short circuit on the line at a distance of 50 km 135 ms C Curve of balanced current Small generators without AVRs can produce rapid a c decrement resulting in fault currents not much bigger than load currents Faults are very difficult to detect under these circumstances If AVRs are fitted the fault current can be maintained at a higher value for longer and the fault is then simpler to detect A further complication associated with decrement occurs on switchgear close to generators If the a c decrement is more rapid than the DC decrement then the first few cycles of current do not pass through zero See Figure 77 Page 107 NE9270 Power System Simulator Page 108 NE9270 Power System Simulator Experiment 8 Symmetrical Faults The following are examples of studies that can be carried out on the Simulator In all cases the values measured are to be compared with those calculated The connection diagrams for Paris A to D are given in Appendix 3 Part A Faults on an Unloaded System Connect Line 2 between the Grid Supply and the distribution transformer DTX1 as shown in the connection diagram for experiment 8a in Ap
221. uble click to enter the menu The main headings required are Configuration and VT Ratios and Groupl Configuration Settings The following settings should be entered for all four relays Active Settings Group 1 Settings Group 1 Enabled Earth Fault 1 Disabled Earth Fault 2 Enabled Note for Earth fault 1 the residual current is measured directly from the system by a CT in the earth connection For Earth fault 2 the residual current is calculated from the measured three phase currents There are no CTs on the Distribution transformer earth connections so Earth Fault 2 is used CT and VT Ratios Main VT Primary Main VT Secondary Phase CT Primary Phase CT Secondary Page 142 NE9270 Power System Simulator Group 1 Click on Group1 to show Application Headings Select Overcurrent double click to show settings Enter the following Function IEC S Inverse IEC S Inverse gt 1 Direction Non Directional Non Directional gt 1 Current Set Prim 14 A gt 1 TMS 0 025 Earth Fault 1 Function IEC S Inverse IEC S Inverse IN 1 Current 14 IN gt 1 TMS 0 025 Setting the P122 at position RGTB The P122 Overcurrent Relay is the simplest relay on the Simulator It has a simple clearly written Technical Manual It is best to start with this relay if you unfamiliar with the relays on this apparatus Most of the relays
222. uely the load flows from which the injected currents and complex powers at the buses can be calculated The load flow problem may be formulated by specifying bus 1 as the reference bus thus define V4 and 61 usually 0 as reference node 2 as the Generator Bus thus defining V5 and and node 3 as the load bus thus defining P3 and Q3 Examples of load flow studies are given in Section 8 of this Manual The connection diagram for experiment 7 shown in Appendix 3 shows how the system can be set up so that quantities in all lines can be measured by M230 meters Generators G1 and G2 can be used or GS and G1 Note that the system should be set up between G2 or GS and G1 Bus before G1 is synchronised onto the G1 Bus using the duplicate CB8 as described in Section 5 The angles 62 between V5 and V4 and 63 between V3 and V4 can be measured using the phase angle meter The capacitor need not be included but is in the system to raise the voltage V3 Set up V4 and V5 initially at approximately 1puV 220 V and switch in a 50 resistive load at Bus 3 Adjust the generator excitation to increase V5 as the load increases to 1 0 pu 220 V and measure 11 I and I5 P gt and and and This is intended to get a feel for the circuit behaviour and its control Eventually it is suggested that the switched loads might be used at the Utilization Bus and capacitance added as required but the generator excitation current must never exceed its maximum
223. ulator Performance Chart for a Salient Pole Generator From the phasor diagram for the salient pole generator Figure 40 it may be shown that 2 p Sind 7 x x Sinza 2 A sd 2 X Figure 44 shows the variation of P with 5 obtained from equation 2 1 0 First Term Second Term n reluctance Figure 44 Variation of P with 5 Figure 44 shows that saliency causes a reduction in 5 for a given power compared with a round rotor generator The machine is stiffer It is not possible to construct a circle diagram about the point A in the phasor diagram Figure 40 because the saliency effect varies with power factor The locus of point Z in Figure 45 is thus obtained by drawing rays from point X and marking of 5 from the circumference of the saliency circle The locus obtained for point Z is not a circle but a limacon See references by J Walker and R M Gove EU 2 OZ VI gt gt 2 lt lt Xs Figure 45 Operating Chart For A Salient Pole Machine Note that in Figure 45 VO Total Power VF FO Page 64 NE9270 Power System Simulator Where from equation 2 on page 64 2 VF 6115 and FO 1 sin2a X d 2 Asi Xsd FO is the Saliency or Reluctance Power obtained without excitation The construction of the theoretical stability limit may also be obtained geometrically Reference by RM Gove See
224. ult entries Restricted Earth Fault REF2 end b As with the DIFF Settings artificial settings for Sref Vb and the CTs must be used to obtain satisfactory amplitude matching factors The same values as before are acceptable plus the CT ratio for the star point or Y connection is set at 700 1 Settings are entered as Parameters Function parameters General functions REF2 General enable USER Yes Select Meas Input End b Reference power Sref 0 40 MVA Ref curr lref not measured 1 154 kA Matching fact Kam Nb not measured 0 8665 77777 Matching fact Kam Yb not measured 0 6066 7 Leave other value entries as the default entries values are calculated by the relay Standby Earth Fault Protection IDM2 This is back up for earth faults and has a long operating time of seconds Parameters Function parameters General functions IDM2 General enable USER yes Parameters Function parameters Parameter subset 1 IDMT2 Enable yes Iref P Blocked Iref P dynamic Blocked lref N 0 2 Inom lref N dynamic 0 2 Inom Characteristic N Standard Inverse Factor kt N 1 2 s Leave other value entries as the default entries Page 178 NE9270 Power System Simulator Overcurrent Protection on Primary IDMT1 Primary Back up to Differential Protection Parameters Function parameters General functions IDMT1 General enable USER Parameters Function paramet
225. ults overheating of plant etc Also included are those system conditions that would develop into a fault if allowed to persist as for example negative phase sequence heating of generators Protective systems have been developed to detect fault conditions in individual components and to initiate the opening of circuit breakers that isolate the faulted section while keeping as much of the power system in operation Early power systems were radial in layout Protection was required to limit the damage caused by short circuit currents Short circuit currents cause overheating that destroys insulation welds core laminations and produce electromagnetic forces which distort windings Speed of operation of the protection was required to reduce the duration of the fault Discrimination i e restricting isolation to the faulted section only was relatively easy It was generally achieved by time grading by deliberately delaying the operation of protection on sections nearer the source This method has obvious limitations but the power levels and fault levels by present standards were low The interconnection of power systems by extensive transmission and distribution systems with generating sources operating in synchronism demanded more rigorous performance requirements of protective systems because a Current could be fed in either direction through a given section of a power system and directional sensing was therefore necessary b Power and hen
226. vailable one near the left hand edge of the panel and one at the bottom centre of the panel near the transducers The MCB trips out when an emergency button is pressed To restart the Simulator after an emergency button has been pressed the button must first be turned to release it from the locked position Circuit Breakers Figure 31 shows the arrangement for circuit connection or interruption by circuit breaker Manual opening or closing of the breaker is achieved by the lever switch indicates open or out 1 indicates closed or in The red and green lights indicate the closed and open status respectively of the breaker OPEN CLOSED e CLOSED 555 Figure 31 Manual Controls for the Circuit Breakers Circuit breakers are closed manually except which is closed automatically when the Simulator is switched on Many of the circuit breakers are opened automatically by relay trip operation on the occurrence of a fault Indication of which circuit breaker is opened by a relay is stated in the outlined areas on the panel diagram as shown in Figure 32 Note that the point at which the box is joined to the line indicates where the current transformers are placed within the three phase system S63 Instantaneous Override CB21 OPEN Trip qi mop DIST n TX 2 RELAY A 3PH OVERCURRENT amp EARTH FAULT TRIPS CB21 TP18 I D M T Override Figure 32 Relay Locati
227. ve sequence relay has two settings an alarm setting 1521 related to 120 and a current trip setting related to the I gt t thermal characteristic for the generator The trip time is calculated by the relay by matching the thermal 12 t characteristics with specified values of Kg the generator thermal capacity Page 190 NE9270 Power System Simulator constant K factors vary between 20 and 5 for smaller air cooled generators to large hydrogen cooled generators respectively Within the relay Menu the l2 gt 1 settings refer to the alarm stage and 1 gt gt 2 settings to the trip time Both have current settings The 1 gt 1 alarm current setting should be less than the 1222 thermal current setting The alarm stage time setting 12 gt 1 Time Delay must be chosen to prevent operation during system fault clearance maximum operating time for the negative sequence thermal withstand protection may be set 12 gt 2 where a machines thermal characteristics are uncertain Reference to the relay Technical Manual Section 2 11 should be made for further information 2 Tripping Sequence For large generator units complete tripping main breaker field breaker and turbine is only carried out for internal faults For all external faults the generator back up protection trips only the H V breaker In the Simulator operation of main protection trips in all cases the main circuit breaker CB8 However for an earth fault on the sta
228. y Pergamon Press 1996 12 Power Systems Analysis Second Edition by CA Gross Published by Wiley 1986 13 Power System Control and Stability by P M Anderson AA Froud Published by lowa State University First Edition 1977 Second Edition 2002 14 Electric Transients in Power Systems by Allan Greenwood Published by Wiley Interscience 1971 15 Power System Protection Vol 3 Application by The Electricity Association Published by The Institution of Electrical Engineers IEE London UK 1995 16 Electric Power Systems Fourth Edition by B M Weedy B J Cory Published by Wiley 1998 17 Network Protection amp Automation Guide N PAG by Alstom T amp G Energy Automation and Information First Edition July 2002 18 Embedded Generation by Jenkins Allan Crossley Kirschen amp Strbac Published by The Institution of Electrical Engineers IEE London UK 2002 19 Power Electronics Third Edition by Cyril W Lander Published by McGraw Hill UK Ltd 20 Operating Chart for the Salient Pole Generator Construction by J Walker Proc IEE Vol 100 1953 21 Operating Chart for the Salient Pole Generator Construction by R M Grove Proc IEE Vol 112 1965 Page 198 NE9270 Power System Simulator 22 Protection of Electricity Distribution Networks 2nd edition by J M Gers and E J Holmes Published by the Institution of Electrical Engineers 2004 2005 23 E
229. ystem currents at 220 V less than 20 A and not greater than 30A under fault conditions The individual components are described briefly in the following sections Page 4 NE9270 Power System Simulator System Identification Line volts 3 Phase Parameter values component Refer to V VA Figure 2 50 2 60 2 2 2 At base base Xpu Rpu 50Hz 60Hz Grid supply 415 V Grid transformer 415 220 V Generators 6 5 7 8 4 pole 0 478 0 69 0 167 0 24 0 047 0 068 0 167 0 241 0 039 0 056 0 191 0 276 0 044 0 064 0 017 0 025 0 028 0 027 Tao sec 0 75 Transformer 220 220 V 0 052 Transformer 220 110 V 0 13 Transformer 220 110 V 0 13 Earthing 220 110 V Transmission lines Line 1 Line 2 Line 3 Line 4 Line 5 Line 6 Cable Table 1 Parameter Values of Power System Simulator Components Note The Generator does not have damper bars Parameter Values Per Unit values are nominal as shown Page 5 NE9270 Power System Simulator Columns for ohmic values are available for entry of values obtained by tests on each simulator see section 2 4 and Section 5 1 4 Outline of the Manual The function of this manual is to provide a technical description of the Power System Simulator PSS and to demonstrate its use and range of capabilities by means of illustrative experim

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