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Numerical Distance Protection Relay Commissioning and Testing

1. 50 0 50 100 150 200 250 300 350 400 450 Figure 3 26 Phase L3 to ground fault in zone 1 41 3 6 2 2 Zone 2 e Phase LI to ground Figure 3 27 Phase L1 to ground fault in zone 2 Phase L2 to ground Figure 3 28 Phase L2 to ground fault in zone 2 42 e Phase L3 to ground Figure 3 29 Phase L3 to ground fault in zone 2 3 6 2 3 Zone3 e Phase Ll to ground TUV TRIP Figure 3 30 Phase L1 to ground fault in zone 3 43 e Phase L2 to ground ee Figure 3 31 Phase L2 to ground fault in zone 3 e Phase L3 to ground Figure 3 32 Phase L3 to ground fault in zone 3 44 3 6 3 Double phase to ground faults In this section the operation of the relay in the case of double phase to ground faults 1s shown Figures 3 33 3 34 and 3 35 show the relay response for double phas
2. EVO1 1146 6 EVENT IMP PROTO O ZMI TRIP IMP PROTO O ZM2 START INPUT2 IMP PROTO O ZM2 TRIP INPUT3 IMP PROTO O ZM3 START T INPUT4 IMP ZMS3 TRIP INPUTS PROTG O GFC STFWL1 T INPUT6 PROT3 0 GFC STEWL2 CUR GFC STEWLS3 INPUT8 CUR GFC TRIP INPUT9 IMP PSD START V INPUT10 INPUT11 EV02 1147 6 EVENT THOL TRIP THOL ALARM 2 TEF TRIP NPUT3 5 INPUT4 INPUTS TOC S TN INPUT6 Ioc TRIp INPUTS INPUT9 INPUT10 INPUT11 INPUT12 INPUT13 INPUT14 INPUT15 INPUT16 INPUT12 INPUT13 INPUT14 INPUT15 INPUT16 3 0 000 T_SUPRO1 0 000 T_SUPRO1 0 000 T_SUPRO3 4 0 000 T SUPROS 0 000 T SUPRO7 0 000 T SUPRO9 0 000 T SUPR11 0 000 T SUPRO3 0 000 T SUPROS 0 000 T SUPRO7 0 000 T SUPRO9 0 000 T SUPR11 0 000 j T SUPR13 0 000 j T 5 5 SZMI TRIP 1 0 000 T SUPR13 4 0 000 T SUPR15 THER
3. 2 6 N The magnitude of is computed by squared root the total of the real part squaring and the imaginary part squaring The angel of the phasor is computed by taking the arc tangent of the imaginary part over the real part 18 The DFT can extract any frequency from the signal Since the DFT is capable of rejecting everything except the frequency being measured it has a good response to transient overshoot Root Mean Square RMS The Root Mean Square is a method of calculating the magnitude of a periodically varying quantity It can be calculated for a series of discrete values or for a continuously varying function The RMS for a collection of N values x2 is 1 2 X rus x 2 7 and the corresponding formula for a continuous function x t defined over the interval T St T is D der ooa 2 8 RMS ym 5 The RMS algorithm is useful for applications where measuring energy content to approximate heating characteristics is desirable 19 Chapter 3 Results using Line distance protection REL 511 2 3 3 1 Laboratory set up A single line diagram of the laboratory setup of the testing is shown in Figure 3 2 The REL511 2 3 has been connected to the network model through three single phase voltage transformers and three current transformers A three phase resistive load of 9 kW has been connected to the line model A fault in the line can be made through
4. 1 COMMUNICATION PORT 870 5 103 H OPTICAL PORT ON LOCAL Hie CONNECTION MADE WITH THE FRONT CONNECTION CABLE FOR PC 3 COMMUNICATION PORT LON A RESERVED FOR PARALLEL LINE COMPENSATION OR CTSU ALT WEE 1 and 2 WHENIr 0 OROSAIS SELECTED ON RESERVED FOR DIRECTIONAL EARTH FAULT FUNCTION amp RESERVED FOR REF VOLTAGE rj OPTIONAL ONOFF SWITCH FOR THE SUPPLY Figure 3 5 Terminal diagram for DC supply 23 CTs connection de VTs connection DC connection Figure 3 6 Connection on the rear side of the relay CTs and VTs Three single phase voltage transformers VTs are connected to the line model as shown in Figure 3 1 The voltage transformer input is 230V and four outputs are 69V 115V 161V and 230 Since the relay input is U 100 120V phase to phase the VTs output of 69V is used Three current transformers CTs having ratio of 100 1 have already been connected in the line model see Figure 3 7 The signals from the secondary outputs of the CTs are available in the control panel P 2 1 of the line model CTs secondary signals Figure 3 8 Photo of the P 2 1 control panel 24 1 1 1 4 4 17 1 1 1 1 1 1 na E X sss gt TE RE DE M a VNSE T a i DOE N FOR S 1 1 aria qp
5. INPUT4 INPUTS INPUT6 0002 156 6 OR T F T TT INPUT2 INPUT3 F INPUT4 INPUTS INPUT6 157 6 OR OUT SELECTIVE TRIP 0034 OUT INPUT2 NOUT INPUT3 INPUT4 INPUTS INPUT6 0004 170 6 OR OUT INPUT2 NOUT TRO1 729 6 TRIP BLOCK TRIP TRIN TRL TRINLI TRL2 TRINL2 TRL3 TRINL3 TRIP PSL1 TR2P PSL2 TR3P PSL3 1PTRZ 1PTREF P3PTR Acsi arie Kanon 28 09 05 Configuration diagram TRIP LL Power System Protection Chalmers University of Technology Laboratory exercise 1 2 3 4 5 6 INT 221 1000 InternSignals WARNING CPUFAIL CPUWARN ADC SETCHGD FIXD 0 0 FixedSignals OFF ON INTZERO INTONE Prepared T M Hung H Akyea 20 09 05 Approved Daniel Karlsson 28 09 05 Configuration diagram Fesp den Based on are Seu Chalmers University of Technology Laboratory exercise 1 2 3 4 5 6 IOP1 222 1000 V OPosition 511 513 S15 IOP1 S15 5171 517 519 521 1002 804 6 I O module POSITION ERROR BLKOUT OPEN IOO2 BI1 BO1 BI2 BO2 BI3 BI4 BO4 TRIP TRIP ZM1 TRIP BONAMEO2 ZM2 TRIP
6. ZM3 TRIP BONAME04 31002 BII 1002 BI2 j BINAMEO2 1002 BI3 j BINAMEO3 1002 BI4 BINAME04 Prepared T M Hung Akyea 20 09 05 mum o E Wed Darel Karts 28 09 05 Configuration diagram C REL 51172 3 Power System Protection Chalmers University of Technology Laboratory exercise 1 2 3 4 5 6 1O03 805 6 I O module 517 POSITION ERROR 1004 806 6 T O module POSITION ERROR BLKOUT BC 1003 BI1 BI2 BO2 BO3 BO4 H CLR LEDS BINAME01 BI1 CLR_LEDS 1004 BI1 1004 BI2 j BINAMEO2 BI2 1004 BI3 j BINAMEO3 1004 BI4 BINAME04 EF BLOCK IOO3 BI6 1004 BIS BINAMEOS 1004 BI6 j BINAME06 1004 BI7 j BINAMEO7 1004 BI8 j BINAMEOS 1004 BI9 BINAMEO9 04 10 BINAME10 1004 BI11 1 1004 BI12 BINAME12 TRIP TRIP GFC STFWL1 GFC STFWL2 GFC STFWL3 3HOO04 BI13 BINAME13 1004 BI14 BINAME14 1004 BI15 BINAME15 3HOO04 BI16 BINAME16 WE ETE GFC STFWPE 1003 B06 1003 BO7 1003 BO8 sHO03 BO9 1003 BO10 1003 BO11 4HO03 BO12 3HO03 BI1 3HO03 BI2 3HO03 BI3 1003 BI4 1003 BIS 1003 BI6 1003 BI7 _ 1003 BI8 Prepared H Akyea 20 09 05 we Approved Daniel Karl
7. ee ee Jaen c b Pon I tet Poe 6 di RES ilius E pete dieen MAM LINE B WANN RA UN I Row OE NE sue AES amp 8 3 44543 13339 gt 1 Es 5 s lt s 5 5 2 2 el m m P re f el mi 1 1 m i 1 1 1 i i lt EV E ES ap p s 1 i vu 1 BL ES o 1 i 1 1 l i i H C i EN xp I ss we e Figure 3 9 Terminal diagram for CTs and V Ts connection PC relay connection The optical wire is used to make the connection between PC and the relay Figure 3 10 shows the human machine interface HMI module in which the optical wire is connected to 2 z _ 5 amp E a O 8 Figure 3 10 Photo of the HMI module 25 3 4 2 Configuration and tools used The terminal REL 511 2 3 is configured using the configuration and programming tool CAP 531 This tool enables configuration management programming and error detection and correction for the REL 5xx terminals CAP 531 is started from within the CAP 540 10 CAP 531 comprise these views e Project tree Organize terminal and work sheets e Work sheet Create the configurati
8. Sheet 13 14 EV03 1148 6 EVENT DLD START INPUT1 EV04 1149 6 EVENT TOV TRIP INPUT2 INPUT1 TOV STN INPUT3 INPUT2 TOV STPE INPUT4 INPUT3 TUV TRIP INPUTS INPUT4 TUV START INPUT6 INPUTS INPUT7 INPUT6 INPUTS INPUT7 INPUT9 INPUTS INPUT10 INPUT9 INPUT11 INPUT10 INPUT12 INPUT11 INPUT13 INPUT12 INPUT14 INPUT13 INPUTIS INPUT14 INPUT16 INPUTIS 0 000 T_SUPRO1 INPUT16 0 000 T_SUPRO3 0 000 T_SUPRO1 0 000 T_SUPROS 0 000 T_SUPRO3 0 000 T SUPRO7 0 000 T SUPROS 4 0 000 T SUPRO9 4 0 000 T SUPRO7 4 0 000 T SUPR11 0 000 T SUPRO9 0 000 T SUPR13 0 000 T_SUPR11 0 000 T 5 5 0 000 T SUPR13 LINE NAMEO 0 000 T SUPRIS TOV TRIP NAMEO2 GENERAL TRIP 1 TOV START N EV04 INPUT2 j NAMEO2 TOV START P NAMEO4 EV04 INPUT3 TUV TRIP NAMEOS sEVO4 INPUT4 NAMEO4 TUV START 6 EV04 INPUTS NAMEOS sEVO3 INPUTO7 NAMEO7 sEVO4 INPUT6 6 sEVO3 INPUTOS NAMEOS sEVO4 INPUT7 NAMEO7 sEVO3 INPUTO9 NAMEO9 EV04 INPUT8 j sEVO3 INPUT10 NAME10 EV04 INPUT9 NAMEO9 sEVO3 INPUT11 11 sEVO4 INPUT10 NAME10 sEVO3 INPUT12 NAME12 sEVO4 INPUT11 11 sEVO3 INPUT13 NAME13 sEVO4 INPUT12 NAME12 sEVO3 INPUT14 NAME14 sEVO4 INPUT13
9. 4141141111 GFC STCND STILI STIL2 STIL3 STUL1 STUL2 STUL3 STPH DLD START DLD STPH Prepared T M Hung Akyea 20 09 05 Approved Daniel Karlsson 28 09 05 i vid Power System Protection Pd Configuration diagram REL 511 2 3 4 Respdep Rehd Chalmers University of Technology Laboratory exercise 5 6 IOC 390 6 IOC BLOCK TRIP TRP TRLI TRL2 TRL3 TRN TOC 340 6 TOC BLOCK TRIP BLKTR TRP TRN STP STL1 STL2 STL3 STN TEF 230 6 TEF EF BLOCK IOO03 BI6 BLOCK TRIP BLKTR TRSOTF 1003 1 BC START STFW STRV THOL 358 6 THOL BLOCK ALARM TRIP START Prepared T M Hung Akyea 20 09 05 nm DR 26 0905 Configuration diagram CUR PROT REL 511 23 pee Lr Power System Protection Chalmers University of Technology Laboratory exercise 1 2 3 4 5 6 TOV 350 6 TOV BLOCK TRIP BLKTR TRPE TRN STPE STL1 STL2 STL3 STN CB_OPEN I002 BI1 Prepared T M Hung Akyea 20 09 05 Configuration diagram NENNEN VOL PROT Approved Daniel Karlsson 28 09 05 QE SALA Fesp dep p Based on Power System Protection Chalmers University of Technology Laboratory exercise 1 2 3 4 5 6 0001 155 6 INPUT1 OUT INPUT2 NOUT INPUT3
10. NAME13 sEVO3 INPUT15 NAME15 sEVO4 INPUT14 NAME14 sEVO3 INPUT16 NAME16 sEVO4 INPUT15 NAME15 0 PrCol03 sEVO4 INPUT16 NAME16 0 FuncTEV3 0 PrCol04 0 InfoNo01 40 FuncTEV4 0 InfoNo02 0 InfoNo01 InfoNo03 InfoNo02 InfoNo04 InfoNo03 InfoNo05 InfoNo04 InfoNo06 InfoNo05 InfoNo07 InfoNo06 InfoNo08 InfoNo07 InfoNo09 InfoNo08 InfoNo10 InfoNo09 InfoNo11 InfoNo10 InfoNo12 InfoNo11 InfoNo13 InfoNo12 InfoNo14 InfoNo13 InfoNo15 InfoNo14 InfoNo16 InfoNo15 InfoNo16 honor Darl iun guration d Approved Daniel Karlsson 28 09 05 Configuration diagram EV REL 5112 3 Power System Protection Chalmers University of Technology Laboratory exercise Sheet 14 14 BC IO03 BI1 I OV O ZMI START IMP PROT2 O CB 1002 VOL 5 ZMI TRIP EV 13 I CLR LEDS IO04 BI1 I 09 0 HMI 10 DLD START 14 1_ DLD STPH DRP 12 I 1 _ 2 HMI 6 BLOCK IO03 BI6 109 0 ZM2 START EWI3 I IMP PROTV I HMI LED 10 I 121 IMP ZM2 TRIP EW3 I HMI LED 10 I 1 081 IMP TRIP 6 I 2 ZM3 START EV 13 I HMI LED 10 I IMP PROTQ O ZM3 TRIP EWI3 I HMI LED 10 I LOI IMP TRIP 6 I 2 IOC TRN 515 517 PSD START SELECTIVE TRIP 0034 OUT TEF START TEF TRIP VOL 5 VOL 5 4 1 TRIP 6 I VOL
11. L3 and L2 L3 are applied in zone 1 respectively The faults occur between phase to phase so only the corresponding general fault criteria forward operation in phase is activated i e double phase 21 12 GFC STFWLI GFC STFWL2 LI L3 GFC STFWLI GFC STFW L3 12 13 GFC STFWL2 GFC STFWL3 The Figures 3 45 3 46 and 3 47 show the operation of the relay in zone 2 with the presence of a fault double phase L L2 14 13 L2 L3 respectively The Figures 3 48 3 49 and 3 50 illustrate the cases of a fault in zone 3 where the corresponding general fault criteria reverse operation in double phase L L2 GFC STRVLI GFC STRVL2 or 14 13 GFC STRVLI GFC STRVL3 12 13 GFC STRVL2 GFC STRVL3 is operated 3 6 41 Zone 1 e Phase 11 12 Figure 3 42 Double phase L1 L2 fault in zone 1 50 Phase L1 L3 Phase L2 L3 Figure 3 43 Double phase L1 L3 fault in zone 1 0 05410 RM 0 2338A Figure 3 44 Double phase L2 L3 fault in zone 1 51 3 6 4 2 7 2 e Phase 11 12 Figure 3 45 Double ph
12. In this section the operation of the relay in the case of single phase to ground faults is shown Figures 3 24 3 25 and 3 26 show the presence of a single phase to ground fault within the first zone of protection in forward direction The application of a ground fault results in not only the activation of the general fault criteria forward operation of Ph E loop GFC STFWPE but also the corresponding general fault criteria forward operation in phase L GFC STFWLI or L2 GFC STFWL2 or L3 GFC STFWL3 is operated as well The Figures 3 27 3 28 and 3 29 show the operation of relay in zone 2 with the presence of fault in phase Ll L2 L3 to ground respectively The Figures 3 30 3 31 and 3 32 illustrate the cases of a fault in zone 3 where the corresponding general fault criteria reverse operation in phase L GFC STRVLI or L2 GFC STRVL2 or L3 GFC STRVL3 is operated 3 6 2 4 2 1 e Phase Ll to ground Figure 3 24 Phase L1 to ground fault in zone 1 40 e Phase L2 to ground 0 04767 5 0 2347 A A A A A Ac A Ac A Figure 3 25 Phase L2 to ground fault in zone 1 e Phase L3 to ground
13. shows a block scheme of a typical numerical relay Input signal Relay Output Analog Input System Digital Output System Surge filter Independent Power Supply Digital Output Anti aliasing Filter lt Power Supply j 34 A D Sample Hold Pre set Threshold Ht Relay Algorithm Digital Filter Processor Figure 2 9 Block diagram of a numerical relay Numerical relays operate on sampled signals and adopt digital computations Sampling is the process of converting analog input signals such as current and voltage into digital input signals These analog input signals in case of electromechanical and static relays are directly fed into the electromagnetic winding or electronic circuits In order to protect the relay from large transients of the input signals a surge filter is used An anti aliasing filter is used to avoid possible errors in reconstructing the input signal carried out after A D Sample Hold section Any signal having harmonic components of order N 1 2N 1 x N 1 where is the number of samples per cycle can exhibit aliasing Perfectly an anti aliasing filter has to cut off all signal components above the Nyquist rate of N 2 In practical however such a filter can not cut off all out of band frequencies so the anti aliasing filter cut off frequency is set at about N 3 The A D converts the sample values that represent th
14. a variable fault resistance by closing a contactor controlled by a timer The timer and the contactor is also used to clear the fault Figure 3 1 is a picture of the real setup in the laboratory Figure 3 1 Photo of laboratory setup 20 Timer Fault resistor Contactor Line model STRONG GRID REL 511 2 3 Optical wire 3 2 Line model Load Figure 3 2 Single line diagram of the laboratory setup The power line model is a three phase model of a 400 kV transmission system The entire model operates at 400 V consequently the voltage scale is 1 1000 8 As can be seen in Figure 3 3 the line model can be fed using the local distribution line denoted as strong grid or a synchronous generator STRONG GRID Line model Lm ZONEN 2 Synchronous generator Y Figure 3 3 Single line diagram of the line model The line model consists of six identical T sections each corresponding to 150 km of a 400 kV line Each section includes series reactors denoted by and and shunt capacitors denoted by The sections can be connected arbitrarily in series or in parallel In these experiments the 7 sections have been connected in series and the line model has been supplied by a strong grid 21 data for th
15. done by opening the CAP 540 project Test lab highlight the Stn1 then set it at Settings Communication settings Communication parameters e Set the slave number and the baud rate to 30 and 9600 respectively in the terminal The slave number and the baud rate settings in the terminal can be done on the local HMI at Configuration TerminalCom SPA Com Front e Set the slave number and the baud rate in the by opening the CAP 540 project Test lab Highlight the Stn1 then set it at Settings Communication settings Communication parameters The slave number and the baud rate must be the same for both the PC and the relay Describe and explain the results v Switch on the Dead line detection DLD remove one of the three phase lines that used to connect the relay to the voltage transformers and observe the LED Then switch off the DLD Operating mode for DLD can be changed on the local HMI under the menu Setting Functions Group 1 DeadlineDet vl Increase the load to 18 kW and observe the LED The following manuals provide complementary information 1 Cap 540 Navigator User s Manual 2 Cap 531 Configuration and Programming Tool User s Manual 3 PST Parameter setting tool User s Manual 4 Technical reference manual of the manuals are available online http www abb com substationautomation 68 Setting parameters zone 1 3 Parameter Description Posit
16. of U Operative range 0 001 1 5 U Permissive overload 1 5 U continuous 2 5 0 for 1s DC supply for relay 48 250 V Figure A1 shows the line model used for the laboratory 61 c9 STRONG GRID Timer v Line model Fault resistor Contactor Figure A1 Power system model of the laboratory exercise Load 4 Distance zones Zone 2 Zone 1 1 T 1 STRONG RID B Relay F B C D Load i Zone 3 Figure A2 Grade distance zones Zone 1 85 AB time delayed 0 forward direction Zone 2 AB 30 BC time delayed 0 25 s forward direction Zone 3 AB BC 25 CD time delayed 0 35 s reverse direction Load 9 kW AB 3 T sections CD 1 z section Faults locations in Zone 1 and Zone 2 respectively Fault resistor Rr 50 Timer is set to be 0 5 s Setting for zone parameters can be done on the local human machine interface HMI unit under the menu Setting Functions Group 1 Impedance ZM n n 1 2 3 H Calculate the setting values for the impedance fault detection of the three zones according to Figure 2 and the given data Note of the setting values are calculated for the secondary side based on the following expression I U where 7 7 and n are the trans
17. of the shortest adjacent line BC and operates with time delay t Zone 3 this is set to protect 100 of the two lines AB BC plus about 25 of the third line CD and operates with time delay ts Zone 3 t Zone 1 Relay A B C D Figure 2 6 Distance relay protection zones 2 3 3 Relay characteristics The shape of the operation zones has developed throughout the years Figure 2 7 4 gives an overview of relay characteristic Originally the operating characteristic was a circle located in the origin of the co ordinates in the R X plane of the impedance relay This type of relay however is non directional and sensitive to power swings and load encroachment due to the large impedance circle Therefore the circle 14 diameter was reduced and its origin passed through the origin of the co ordinates resulting in the mho relay Relays with combined characteristics are obtained by added a mho circle with lines parallel to the resistive and reactive axes which cross each other at the setting point Z Modern distance relays especially the numerical types offer quadrilateral characteristic whose resistive and reactive reach can be set independently EL mE R gt R Impedance Mho Zk Zone 3 Zone 2 Zone 1 R R Combined characteristic Quadrilateral characteristic Figure 2 7 Relay characteristics 2 3 4 Distance rela
18. parallel lines is taken out of service or faulted only one power directional relay will operate the contacts of the second directional relay remaining open 2 2 4 Applications Differential Protection for Bus bars Short circuit on bus bars can have very serious consequences for the operation of the power system The most widely used and acceptable type of protection for 35 220kV bus bars is high speed differential protection It is based on Kirchhoff s current law that requires the sum of all currents entering the bus to sum to zero Should an internal fault occur however the sum currents measured at current transformer locations will not be zero and tripping should occur This type of bus protection for one phase is shown in Figure 2 4 3 The current transformer secondaries are added together to give the sum of the currents in all four lines and the sum is sent to the differential relay In case a fault occurs that is external to the CT connections say at the point 1 in the Figure 2 4 the total current flowing to that fault will be exactly equal to the total current entering the bus on lines 2 3 4 and no current will flow to the differential relay However if a fault occurs on the bus between phases or from phase to ground the sum of the line currents will equal the total bus fault current and the relay will correctly measure this quantity Le C Differential relay re De De De 1 2 3
19. relay is approximately equal to the load impedance that is much larger than the line impedance If the fault is within the fraction k then the measured impedance at the relay is Z lt Z 2 3 The impedance to the fault point is now within the impedance protection characteristic and the relay will operate Obviously the relay will not trip for the fault beyond the fraction k The impedance characteristic of the relay can be chosen so that the reach is different for different phase angles of the apparent impedance 2 3 2 Setting of the distance zones Line impedances are proportional to the line lengths and this property is used to calculate the distance from the relay location to the fault The relay however is fed with the current and voltage measured signals from the primary system via instrument transformers CT and VT Therefore the secondary value used for the setting is obtained as the following expression 13 2 4 p U 2 where the transformation ratios of the current and voltage sec sec transformers respectively In order to cover a section of the line and to provide back up protection to remote sections three main protection zones see Figure 2 6 are set up with the following criteria e Zone 1 this is set to protect between 80 and 85 of the line length AB and operates without any time delay e Zone 2 this is set to protect 100 of the line length AB plus at least 20
20. sister brother in law and his girlfriend Tran Huong Lien for all their supports throughout the years Henry Akyea would like to extend my appreciation to my twin sister Henrietta Akyea for her financial support Acknowledgement Contents 1 Introduction 2 Line Protection 2 Overcurtent protection uu a apus aarden den tented sis and bean 2 1 1 Definite current relays u sa a mener 2 1 2 Definite time relays ee ern Re E Sede ERR e tede 2 1 3 Inverse time relays trier pene sene dele een 2 1 4 Setting for overcurrent protection 2 2 Differential 2 1 1 Longitudinal differential eee 2 1 2 Transverse balanced differentialen een venen 2 1 3 Transverse differential directional protection 2 14 Applications dirus s ert toa vernemen cU eee ERU Cute Bak ates 2 3 Distance protection uu eese de enn idee 2 2 1 Basic principles E 2 2 2 Setting of the distance 7 2 2 2 3 R elay characteristics nternet weerden Rp eer 2 2 4 Distance relay types csse Ie m eene ene 2 25 Nuimericalrel y uu d ense ee mr ER nde Ro 2 2 5 1 Structure of numerical relays 2 2 5 2 Relay algorithm 3 Results using L
21. that at the substation furthest away from the source the relay will operate for a low current value and the relay operating currents are progressively increased at each substation moving towards the source Thus the relay with the lower setting operates first and disconnects load at the point nearest to the fault This type of protection has the drawback of having little selectivity at high values of short circuit current Another disadvantage is the difficulty of distinguishing between the fault current at one point and another when the impedance between these points is small in comparison to the impedance back to the source leading to the possibility of poor discrimination Definite current relays are not used as the only overcurrent protection but their use as an instantaneous unit is common where other types of protection are in use 1 2 1 2 Definite time relays This type of relay enables the setting to be varied to cope with different levels of current by using different operating times The settings can be adjusted in such a way that the breaker nearest to the fault is tripped in the shortest time and then the remaining breakers are tripped in succession using longer time delays moving back towards the source The difference between the tripping times for the same current is called the discrimination time Since the operating time for definite time relays can be adjusted in fixed steps the protection is more selective T
22. the fault resistor was not connected to the ground This problem was rectified when we connected the fault resistor to ground Then also the relay did not calculate the distance to fault on the disturbance report We realised that the setting parameters of the Fault locator function block FLOC were wrong because we had omitted to multiply the reactance and resistance values of the line model by a factor of six The factor of six should be multiplied to the reactance and the resistance values of the line model because the line model is divided into six equal m sections After we had done the multiplication the relay recorded the distance to fault in the disturbance report 4 2 Further work The following problems should be implemented as the further woks e Use the output signals sent out by the functional blocks to control the circuit breaker or fault clearing equipment e Study evolving faults e g faults starting as phase to ground fault but developing to double phase to ground fault e Study power system oscillations e Test relay with source impedance variations 56 References 1 J M Gers E J Holmes Protection of Electricity Distribution Networks The Institution of Electrical Engineers London U K 1998 2 G I Atabekov The Relay Protection of High Voltage Networks Pergamon Press Ltd London 1960 3 P M Anderson Power System Protection The Institute of Electrical and Electronics Engineers
23. then select Terminal Emulator in the Tools menu 75 Terminal Emulator File View Elapsed Time Send Receive ms RF 2004 Clear Send Receive RespondTime ms 30RF 13cr Repeat gt 13 TimeQut n Prepared SPA Message RF Repeat Ful SPA Message gt 1RF Xx TimeOut C Other AT Time 11 48 18 Close If Repeat and TimeOut appear in the Respond Time field after clicking Send as shown in the above figure the communication set up is incorrect and it should be checked again 5 Upload configuration The entire configuration is stored in the terminal and it can be upload to the PC For back up purposes and off line engineering a copy of the terminal configuration should be kept on the PC system Start the Upload Configuration by selecting the terminal in the project tree and then select Upload Configuration in the On line menu 6 Download the configuration To download the configuration to the terminal e Select the terminal that you want to download in the Project Tree e Select Download Configuration in the On line menu and the Download configuration dialog appears e Select Download PST configuration if relevant click Yes and downloading starts by uploading the list of available functions The Compare Configuration function starts automatically If the downloading has been successful and there are no differences between th
24. 0 6 HLOS 1408 6 AND HMI LEDs OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN 0005 171 6 OR OUT INPUT2 NOUT INPUT3 INPUT4 INPUTS INPUT6 o o guration d 00 HMLEED Daniel Karlsson 28 09 05 Configuration diagram HMI LED REL 51172 3 Respdep pee Lr Power System Protection Chalmers University of Technology Laboratory exercise heet 1 2 3 4 5 6 DRP1 1129 6 DisturbReport DRP2 1130 6 CLRLEDS OFF DisturbReport INPUT1 RECSTART INPUTIT INPUT2 RECMADE FALSE INEOTIS INPUT3 MEMUSED DRP1 MEMUSED INET INPUT20 INPUT4 CLEARED INPUT21 INPUT22 CUR PROT3 O GFC STFWL1 INPUTS CUR_PROT3 O 8 2 INPUT6 _ GFC STFWL3 INPUT7 CUR_PROT 3 O0 GFC STFWPE INPUTS CUR PROTM O IOC TRIP INPUT9 CUR PROTM O IOC TRN INPUT10 IMP PROTO O ZMI TRIP INPUT11 IMP ZM2 START INPUT12 IMP ZM2 TRIP INPUT13 ZM3 START INPUT14 M3 TRIP INPUT15 IMP PSD START INPUT16 INPUT23 INPUT24 INPUT25 INPUT26 INPUT27 INPUT28 FALSE INPUT29 FALSE INPUT30 FALSE INPUT31 FALSE INPUT32 TEF TRIP 17 TRIP TRIP NAMEO1 f nputi8 NA
25. 01 BI5 BINAMEOS BIS B08 1001 B19 BINAMEOS BIS Bos 1001 B110 BINAME10 BIO BO10 1001 111 11 BI11 BO11 1001 Bl12 BINAME12 BI12 BO12 1001 113 BINAME13 BO13 1001 114 14 1001 115 15 115 015 BO16 BO17 1001 BI16 BINAME16 BI16 Figure 3 12 Compare the I O module as BIM left or as a BOM right The library is updated with a new function block when you select a module in the Function Selector tool and only that selected module can be used in the configuration The Function Selector can be started as follows e Select the terminal in the Project Tree e Select the Function Selector in the Edit menu Function Selector Tool File Edit Help Set Value Function Group 1 0 01 Selector Type 101 Clear Value Description 170 module 1 Type of 1 0 board Selected Values Function group Selectors 1 0 module 61 Type I01 IO0PSM 1 0 module 62 Type 102 IOPSH 1 0 module 63 Type I03 3 I0H 1 0 module 64 NUM Figure 3 13 Function Selector 27 The Function Selector contains the Set Value which you use to change the function values and the Selected Values which give you an overview of all function The configuration is done in the work sheets as shown in Figure 3 14 The normal mode used when you work
26. 2596CD reverse direction Zone 2 Zone 1 STRONG H h GRID Relay Load Zone 3 Figure 3 19 Grading chart of setting zones for testing 31 32 The data of the line model AB BC CD for positive sequence is given in Table 3 1 Line Reactance X O phase Resistance Ri O phase AB 2 84 0 23 BC 0 95 0 08 CD 0 95 0 08 Table 3 1 Data for lines AB BC CD Zero sequence impedance Zo is three times larger than that of the positive sequence Z4 The setting values are calculated by using the expression 2 4 Et souoz 101 80195 T E ALL Parameter Zone 1 Zone 2 Zone 3 Primary Secondary Primary Secondary Primary Secondary Unit Description 2 42 73 52 3 12 95 15 4 03 122 54 Q ph Positive sequence reactive reach of distance protection zone n for Ph Ph faults 0 20 6 08 0 26 7 87 0 33 10 14 Q ph Positive sequence line resistance reach of distance protection zone n for Ph Ph faults RFPP 5 00 152 17 5 00 152 17 5 00 152 17 Resistive reach of distance protection zone for Ph Ph faults XIPE 2 42 73 52 3 12 95 15 4 03 122 54 Q ph Positive sequence reactive reach of distance protection zone for Ph E faults 0 20 6 08 0 26 7 87 0 33 10 14 O ph Positive sequence line reac
27. 4 Figure 2 4 Bus differential protection 10 Differential Protection for Transformer A transformer suffers from different types of stresses overheating and short circuit Short circuit protection includes internal short circuit such as turn to turn faults and turn to ground faults It also includes external short circuits for example bushing flashovers that are also within the protection zone of the relays The most common form of transformer protection is differential relaying which treats the transformer as a unit making measurements at all of the transformer terminals In applying the principles of differential protection to three phase transformers the CT connections should be such that the relay does not operate for normal load or for external faults and the relay must operate for internal faults of a given severity A rule of thumb often applied to the connection of CTs for power transformer protection is as follows e CTs wye connected winding should be connected delta e CTs on a delta connected winding should be connected in Making the connection in this way ensures that for external faults the CT secondary currents are equal and the differential protection will not trip the transformer 3 Differential Protection for Generators Differential protection for generators is similar to that for transformers in many ways Internal generator winding faults include phase to phase short circuits short circui
28. 5 41 HMI 10 HMI LEDV1 I I 18 I O9 I TRIP 6 O VOL 5 EW4 I TRIP 6 I VOL 5 Prepared T M Hung Akyea 20 09 05 GUNT 1 E Danial Karson 28 09 05 Configuration diagram EV REL 5112 3 epdp Power System Protection Chalmers University of Technology Laboratory exercise pee 1 2 3 4 5 6
29. I GFC STFWL2 GFC STFWL3 are activated instantaneously Then at t 15 ms the general trip signal zone 2 start signal ZM2 START and trip signal from zone 1 ZMI TRIP are activated At t 2 165 ms time delayed trip operation of zone 2 is reached thus trip signal by distance protection zone 2 ZM2 TRIP is activated These signals have normally different reset times They however reset approximately at the time of fault clearance att 400 ms Figure 3 22 shows the case of a fault applied in zone 2 In the figure the only difference is that ZM1 TRIP is not activated 37 Figure 3 23 shows another result where the fault is applied in reverse direction As seen the fault is applied at t 2 0 ms and the general fault criteria reverse operation signals GFC STRVLI GFC STRVL2 GFC STRVL3 are activated instead of the activation of the general fault criteria forward direction After 250 ms activation of ZM3 START signal trip signal by distance protection zone 3 ZM3 TRIP is sent out 3 6 1 1 Zonet Figure 3 21 Three phase fault in zone 1 38 3 6 1 2 7 2 1 1 1 1 Figure 3 22 Three phase fault in zone 2 3 6 1 3 Zone Figure 3 23 Three phase fault in zone 3 39 3 6 2 Single phase to ground faults
30. Inc New York U S A 1999 4 M Jonsson Line Protection and Power System Collapse Licentiate thesis Chalmers University of Technology Department of Electric Power Engineering G teborg Sweden 2001 5 J Daalder Power System Analysis Unpublished lecture material Chalmers University of Technology Department of Electric Power Engineering G teborg Sweden Spring 2005 6 S H Horowitz Phadke Power System Relaying De edition Reaserch Studies Press Ltd 1996 7 M P Ransick Numeric protective relay basics Proceedings of the 33rd IAS Annual Meeting The IEEE 1998 Industry Applications Conference 1998 Vol 3 12 15 Oct 1998 pp s 2342 2347 8 M Gustafson N Krantz Voltage Collapse in Power Systems Licentiate thesis Chalmers University of Technology Department of Electric Power Engineering G teborg Sweden 1995 9 Technical reference manual Online Available http www abb com substationautomation 10 Cap 540 Navigator User s Manual 11 Cap 531 Configuration and Programming Tool User s Manual 12 PST Parameter setting tool User s Manual 13 Disturbance Evaluation REVAL User s Manual 14 SVT Setting Visualisation Tool User s Manual 15 Line Protection Practical Panorama Training Course LP5p 57 Appendix A Laboratory for undergraduate student 58 TESTING A NUMERICAL DISTANCE PROTECTION RELAY by Tran Manh Hung Henry Akyea All questions marked
31. MAL TRIP 1 ZM2 START NAMEO2 STHERMAL ALARM NAMEO2 ZM2 TRIP NAMEO3 TEF TRIP NAMEO3 SZM3 START NAME04 TEF START NAME04 ZM3 TRIP 5 TOC TRIP NAMEOS GFC STFWL1 6 5 6 GFC STFWL2 NAMEO7 S OC TRIP NAMEO7 GFC STFWL3 EV02 INPUT8 NAMEO8 NAMEO9 2 9 NAMEO9 SPSD START NAME10 EV02 INPUT1O NAME10 EVOI CINPUT11 11 sEVO2 INPUT11 11 EVOI INPUTI2 NAME12 sEVO2 INPUT12 NAME12 EVOI INPUTI3 NAME13 sEVO2 INPUT13 NAME13 EV01 INPUT14 NAME14 EV02 INPUT14 NAME14 EV01 INPUT15 NAME15 EV02 INPUT15 NAME15 EV01 INPUT16 NAME16 sEVO2 INPUT16 NAME16 0 PrCol01 0 PrCol02 0 FuncTEV1 40 FuncTEV2 InfoNoO1 0 InfoNo01 0 InfoNo02 0 InfoNo02 0 InfoNo03 0 InfoNo03 0 InfoNo04 0 InfoNo04 InfoNo05 InfoNo05 InfoNo06 InfoNo06 InfoNo07 InfoNo07 InfoNo08 InfoNo08 InfoNo09 InfoNo09 InfoNo10 InfoNo10 InfoNoll InfoNoll InfoNo12 InfoNo12 InfoNo13 InfoNo13 InfoNo14 InfoNo14 InfoNo15 InfoNo15 InfoNo16 InfoNo16 V cm DT guration d Approved Daniel Karlsson 28 09 05 Configuration diagram EV REL 5112 3 Power System Protection Chalmers University of Technology Laboratory exercise
32. ME18 f nputi9 19 Input20 NAME20 GFC TRIP NAME21 Input0o2 _ NAME02 Input03 11 04 4 GFC STFWL1 5 GFC STFWL2 STHOL TRIP NAME22 f nput23 NAME23 TOC TRIP NAME24 GFC STFWL3 NAMEO7 GFC STFWPE NAMEOS8 TOC STN NAME25 fHOC TRIP NAMEO9 TUV TRIP NAME26 fHOC TRN NAME10 ZM1 TRIP NAMEI1 TOV TRIP NAME27 ZM2 START NAME12 DLD STPH NAME28 f nput29 NAME29 Input30 NAME30 f nput31 NAME31 Input32 NAME32 0 FuncT17 ZM2 TRIP NAME13 ZM3 START NAME14 ZM3 TRIP NAMEIS 5 5 NAME16 FuncTO1 FuncTo2 0 FuncT18 FuncTo3 0 FuncT19 FuncT04 FuncTos FuncT21 FuncTO6 FuncT22 FuncTO7 FuncTo8 FuncT24 FuncT09 poner FuncT10 FuncT26 FuncT11 FuncT27 FuncT12 FuncT28 FuncT13 FuncT29 FuncT14 Euncrsp FuncT15 FuncT31 FuncT16 FuncT32 InfoNo01 InfoNo17 InfoNo02 InfoNo18 InfoNo03 InfoNo19 InfoNo04 151073020 InfoNo05 InfoNo21 InfoNo06 InfoNo22 InfoNo07 1205623 InfoNo08 InfoNo24 InfoNoO9 InfoNo25 InfoNolO InfoNo26 InfoNo11 InfoNo27 InfoNo12 InfoNo28 InfoNo13 InfoNo29 InfoNo14 12105930 InfoNo15 InfoNo31 InfoNo16 InfoNo32 co Power System Protection Chalmers University of Technology Laboratory exercise pee
33. Numerical Distance Protection Relay Commissioning and Testing Hung Manh Tran Henry Akyea CHALMERS Thesis for the Degree of Master of Science October 2005 Department of Energy and Environment Division of Electric Power Engineering Chalmers University of Technology G teborg Sweden Titel Drift s ttning och provning av ett numeriskt distansskydd Title in English Numerical Distance Protection Relay Commissioning and Testing F rfattare Author Hung Manh Tran Henry Akyea Utgivare Publisher Chalmers tekniska h gskola Institutionen f r Energi och Milj Avdelningen f r elteknik 412 96 G teborg Sverige mne Subject Power Systems Examinator Examiner Prof Jaap Daalder Datum Date 2005 10 06 Tryckt av Printed by Chalmers tekniska h gskola 412 96 G TEBORG ii iii Acknowledgements This work has been carried out at the Division of Electric Power Engineering Department of Energy and Environment Chalmers University of Technology G teborg Sweden We would like to thank our examiner Prof Jaap Daalder our supervisors Dr Daniel Karlsson at Chalmers and Lars G ran Andersson at ABB Company for their support during the work Many thanks to Massimo Bongiorno at the Division of Electric Power Engineering for all his help in running the line model We also wish to thank Jan Olof Lantto for his network and computer support Hung Manh Tran would like to thank his parents especially his
34. aracteristic for one distance protection zone in the forward direction Figure A4 Schematic presentation of the operating characteristics for one distance protection zone in the forward direction Where Xph e reactive reach for Ph E faults Xph ph reactive reach for Ph Ph faults 70 Rph e resistive reach for Ph E faults Rph ph resistive reach for Ph Ph faults Zline line impedance Setting parameters GFC Parameter Description ARGLd Load angle determining the load impedance area RLd Limitation of resistive reach within the load impedance area XIRvPP Positive sequence reactive reach in reverse direction for Ph Ph faults XIFwPP Positive sequence reactive reach in forward direction for Ph Ph faults RFPP Resistive reach forward and reverse for Ph Ph measurement Positive sequence reactive reach in reverse direction for Ph E faults XIFwPE Positive sequence reactive reach in forward direction for Ph E faults XORvPE Zero sequence reactance of reach in reverse direction for Ph E faults XOFwPE Zero sequence reactance reach in forward direction for Ph E faults RFPE Resistive reach forward and reverse for Ph E measurement IP Set operate value for measured phase currents IN Set operate value for measured residual currents INReleasePE 310 limit for releasing Ph E measuring loops INBIockPP 310 limit for blocking Ph Ph measuring loops tPP Time delay
35. ase L1 L2 fault in zone 2 e Phase L1 L3 Figure 3 46 Double phase L1 L3 fault in zone 2 52 e Phase L2 L3 TUV TRIP 50 0 50 100 150 200 250 300 350 400 450 Figure 3 47 Double phase L2 L3 fault in zone 2 3 6 4 3 Zone3 e Phase L1 L2 Figure 3 48 Double phase L1 L2 fault in zone 3 53 e Phase L1 L3 Figure 3 49 Double phase L1 L3 fault in zone 3 e Phase L2 L3 TUVTRIP sn 50 0 50 100 150 200 250 300 350 400 450 Figure 3 50 Double phase L2 L3 fault in zone 3 54 Chapter 4 Conclusions and further work 4 1 Conclusions In this thesis the calculation of the setting values has been included and all types of faults that may occur in the power system have been tested The proper operation of the numerical distance relay has also been demonstrated In presence of a fault within the zone protection the measured impedance of the GFC function block is within the set boundaries of the characteristic This results in the operation of t
36. ave to be set in order to make the terminal behave as intended The setting file can be prepared using the parameter setting PST which is available in the CAP 540 AII settings can be entered manually through the local HMI or downloaded from a PC Front port communication has to be established before the settings can be downloaded The configuration can only be downloaded through the front connector on the local HMI 4 Communication settings Click on Settings menu or right click on a station node and select Communication Settings The dialog can only be opened if a station node is selected Communication Settings Stn1 Communication Parameters Serial Port ow Protocol SPA Baud Rate Data Bits Parity EVEN Stop Bits jn wH Echo aon Handshake sig TimeQut s M Retries The Serial Port number depends on the configuration of the PC The Baud Rate must be 9600 so that it corresponds to the setting of the front port of the terminal The Slave Number and the Baud Rate settings must be equal in the PC program and the terminal The Slave Number and the Baud Rate settings in the terminal are done on the local HMI at Configuration TerminalCom SPACom Front Before start communicating to a terminal make sure the communication setup in CAP 540 is correct Terminal Emulator is used for fault tracing Start the Terminal Emulator by selecting a terminal in the project structure and
37. be configured to suit with the line model Chapter 2 Line protection 2 1 protection It is common to use current magnitude to detect faults in distribution networks Faults on the system bring about very high current levels It is possible to use these currents to determine the presence of faults and trigger protective devices which can vary in design in relation to the complexity and accuracy required Overcurrent relays are the most common form of protection used to deal with excessive currents on power systems They should not be installed purely as a means of protecting systems against overloads which are associated with the thermal capacity of machines or lines since overcurrent protection is primarily intended to operate only under fault conditions However the relay settings selected are often a compromise in order to cope with both overload and overcurrent conditions Based on the relay operating characteristics overcurrent relays can be classified into three groups definite current definite time and inverse time The characteristic curves of these three types are shown in Figure 2 1 1 Definite current Definite time tA A Inverse definite minimum time Figure 2 1 Time current operating characteristics of overcurrent relays 2 1 1 Definite current relays This type of relays operates instantaneously when the current reaches a predetermined value The setting is chosen so
38. e L L2 L1 L3 and L2 L3 to ground faults respectively Again the general fault criteria forward operation of Ph E loop GFC STFWPE is activated Due to the double phase fault occurrence the corresponding general fault criteria forward operation in double phase LI L2 GFC STFWLI GFC STFWL2 LI L3 GFC STFWLI GFC STFW L3 or L2 L3 GFC STFWL2 GFC STFWL3 is fulfilled and activated simultaneously The Figures 3 36 3 37 and 3 38 show the operation of relay in zone 2 with the presence of a fault in double phase 11 12 11 13 12 13 to ground respectively Figures 3 39 3 40 and 3 41 illustrate the cases of a fault in zone 3 Instead of the operation of general fault criteria forward operation outputs the corresponding general fault criteria reverse operation in double phase L L2 GFC STRVLI GFC STRVL2 11 13 GFC STRVLI GFC STRVL3 or 12 13 GFC STRVL2 GFC STRVL3 is operated 3 6 3 4 Zone 1 e Phase L1 L2 to ground Figure 3 33 Double phase L1 L2 to ground in zone 1 45 46 Phase L1 L3 to ground Figure 3 34 Double phase L1 L3 to ground in zone 1 Phase L2 L3 to ground Figure 3 35 Double phase L2 L3 to
39. e analog input signals into the digital input signals However the conversion is not instantaneous and for this reason the A D system typically includes a sample and hold circuit The sample and hold circuit provides ideal sampling and holds the sample values for quantization by the A D converter 17 The microprocessor containing the relay algorithm is the controller of the numerical relay The microprocessor most often performs all control computation self test and communication functions The algorithm functions as a digital filter to extract the fundamental component of the input signal based on which the relay operation is carried out The signal from the digital filter is compared with the pre set threshold in the digital output system The relay operation is decided based on this comparison 2 3 5 2 Relay algorithm The algorithm is designed to remove as much as possible all of unwanted components from the input signals such as harmonic DC etc Two common algorithms will be discussed here the Discrete Fourier Transform DFT and the Root Mean Square RMS algorithm 7 Discrete Fourier Transform DFT The Discrete Fourier Transform is a discrete time version of the Fourier Transform and shown as follow y 2 5 where n is the harmonic number k is the sample N is the number of samples per cycle and j means it is imaginary number In Equation 2 5 the exponential term is j2 ga
40. e function libraries in the terminal and in the configuration no differences will be detected in the comparison process If differences appear in the comparison list then start the downloading procedure again 76 7 Disturbance handling The disturbance report stored in the terminal provides the network operator with proper information about disturbance in the primary network To upload the disturbance report to the PC e Select the Terminal level and right click e Continue with Disturbance Handling and with Terminal Disturbance List 540 Client pgeven Add Remove Disturbance Files Dial EE e Upload File Transfer Disturbance Handling C Terminal Disturbance Lis Terminal Disturbance DECOMprESsS Communication Settings s 77 Appendix C Relay configuration 78 ased on Work sheet name OVERVIEW IMP PROT CUR PRO VOL PROT TRIP INT 10 LED DRP EV Configuration for laboratory exercise using numerical relay REL511 2 3 Description List of content Distance protection functions Current functions Voltage functions Trip logic Internal signals Binary inputs and outputs Indications on local HMI LED Disturbance report Events for SCS Prepared _ T M Hung Akyea 20 09 05 Approved Daniel Karlsson 28 09 05 Power System Protection 3 Configuration diagram REL 5112 3 Chalmers University
41. e real 150 km section of the 400 KV line are 5040 4179 C 0 065767 uF An impedance scale of 1 53 2 gives the corresponding values of the line model 3 3 Numerical relay REL 511 2 3 Numerical relay REL 511 2 3 shown in Figure 3 4 is based on a full scheme distance protection function REL 511 2 3 detects both phase to phase and phase to earth faults and it has quadrilateral operating characteristics A separate general fault criterion with advanced characteristics is used for phase selection and as an overall measuring function which increases the total operating security and facilitates remote backup applications The numerical REL 5xx line distance protection terminals are designed for the main and backup protection monitoring and control of power lines cables and other primary objects They can be used in systems with simple or complex network configurations regardless of the type of system grounding Figure 3 4 Photo of REL 511 2 3 22 3 4 Installation and set up for REL 511 2 3 3 4 1 Relay installation DC supply The relay uses 48V 250VDC supply Therefore a converter having input of 200V AC 240VAC and output of OVDC 120VDC is used to energize the relay The connection is shown in Figure 3 5 As shown in the figure the converter output is connected to the relay through the terminals 11 and 13 SPA 1 870 5 103 OPTION des te x18 INTERNAL 16 4 FAL X1 amp
42. e the breakers at the ends of the line are more widely separated and a single relay should not be used to operate two tripping circuits For this method of protection both ends of the line should open instantaneously for faults wherever they occur on the line In addition the system should not operate for faults outside the section and is therefore inherently selective 1 2 3 Distance protection 2 3 1 Basis principles The distance protection relay measures the line voltage and line current at the relay location and evaluates the ratio between these quantities We consider the relay at the station A in Figure 2 5 Relay A fault B Vy C Figure 2 5 Fault occurs in a power system When fault occurs on the protected line the fault current T and voltageU is fed into the relay The relay should trip for faults within a fractional distance k which is called reach setting of the distance relay of the total distance between buses A and B The reach given in distance unit thus is a tripping threshold 12 Considering a solid fault at the threshold point C we calculate the voltage drop along the line U kZ I 2 1 where Z total line impedance from A to B The impedance Z seen by the relay is computed as follow C Z L kZ 2 2 I Equation 2 2 expresses the threshold or the impedance characteristic of the relay During normal system operation the impedance seen by the
43. ection IP lt 10 96 of Ilb Operating phase current Table 3 5 Parameter setting for miscellaneous function 3 6 Results using numerical relay REL 511 2 3 In the following figures the upper part shows analog input signals coming from the line model whereas the lower one displays the binary output signals of numerical relay These output signals will be used to activate circuit breakers or fault clearing equipment Measured phase voltages as denoted in the figures are U7 U2 U3 and that of currents are 12 Ground current 4 appears when there is a fault between phase and ground During a fault the current in the faulted phases increases The current becomes larger when the fault is closer to the source Phase voltages are always unchanged since they are measured at the strong grid point Distance protection zone outputs such as ZM1 TRIP ZM2 TRIP ZM3 TRIP operate when the corresponding pre set times are reached 3 6 1 Three phase faults In this section the response of the relay to three phase faults is studied Figures 3 21 3 22 and 3 23 show the responses with an applied three phase fault in zone 1 zone 2 and zone 3 respectively As shown in Figures 3 21 at t 0 ms a three phase fault occurs in zone 1 the corresponding measured impedance of loops are within the set boundaries of the characteristic thus GFC TRIP signal and all of general fault criteria forward operation signals GFC STFWL
44. ed of trip for Ph Ph faults tPE Time delayed of trip for Ph E faults 71 Setting parameters FLOC Parameter Description Positive sequence line reactance X0 Zero sequence line reactance Positive sequence line resistance RO Zero sequence line resistance 15 Positive sequence source reactance near end 15 Positive sequence source resistance near end XISB Positive sequence source reactance far end RISB Positive sequence source resistance near end Xm0 Mutual reactance from parallel line Rm Mutual resistance from parallel line 72 Appendix B Relay set up manual 1 Energising the terminal After checking the connection to the external circuitry when the terminal is energised the window on the local HMI remains dark After a few seconds the green LED starts flashing and then the window lights up Then after some seconds the window displays Terminal Startup and the main menu is displayed The upper row should indicate Ready A steady green light indicates a successful start up If the upper row in the window indicates Fail instead of Ready and the green LED is flashing an internal failure in the terminal has been detected Refer to the Self supervision function in the Installation and Commissioning manual pages 40 42 to investigate the fault For a successful start up the appearance of the local HMI should be as shown in the figure be
45. ference Test lab Orgl Stn1 Bay1 REL51123 Terminal PST Value CA TERMINAL OVERVIEW SERVICE REPORT Line length 40 00 a TERMINAL REPORT Length unit km LJ SETTINGS H E 0401 16 Direct analogue i 1 12 000 ohms phase Disturbance Report amp Recc Ri 2 000 ohms phase m Input Modules O PCO1 12 Pulse counter x0 48 000 ohms phase Ei Setting Groups poo 5 Change Active Setting pu S000 Setting Group 15 12 000 ohms phase Basic functions 15 2 000 ohms phase X15B 12 000 ohms phase R15B 2 000 ohms phase m0 0 000 ohms phase 1 Logic fli kartorna xil Rm0 0 000 ohms phase E Control single ar Authority level 10 Ej 7 Parameter Name 0 8 9 5 DIFL Line differe Line Impedance TEE Figure 3 17 The main window of the parameter tool The terminal tree being on the left side of the window shows the structure in which the parameters for a terminal instance are organized When a parameter is selected in the terminal tree a list of parameters is shown For each parameter the window will display its name its value in the terminal its value in PST and its unit The parameter value can be edited directly in the PST Value field A changed value is shown in bold and in the colour blue 3 5 1 Setting for Analogue Inputs Modules The analogue signals fed into the relay should be set
46. formation ratios of the current and voltage sec sec 63 transformers with nominal values of 100 1 and 230 69 respectively 5 Setting for General Fault Criteria The general fault criteria serve as an overall fault detection and phase selection element in all kinds of networks The signals produced by the GFC measuring elements serve for different parts of the distance protection These are indication of the faulty phases phase selection for the zone measuring elements general criteria for the operation of the trip logic and time delayed trip as a backup function to the zone measuring elements As can be seen in Figure A3 the zone measuring element characteristics is within that of the GFC thus to get a trip signal the GFC must be fulfilled 64 GFC Figure A3 Operating characteristics of the GFC and zone measuring elements H Calculate and set the parameters of the GFC For definition of the parameters refer to page 71 UELUT The default values are used for the following parameters ARGLd INReleasePE INBlockPP IP IN The following values should be used 0 s 0 5 Note The setting range of GFC should cover all of the zone characteristics 65 Setting of the GFC parameters can be done on the local human machine interface HMI unit under the menu Setting Functions Group 1 Impedance GenFl
47. ground in zone 1 3 6 3 2 Zone2 e Phase L1 L2 to ground 0 50 0 50 100 150 200 250 300 350 400 450 Figure 3 36 Double phase L1 L2 to ground in zone 2 e Phase L1 L3 to ground Figure 3 37 Double phase L1 L3 to ground in zone 2 47 e Phase L2 L3 to ground 2330 RMS 0 2336 55 J3 x fh A EV A A A F3 3 ALA Figure 3 38 Double phase L2 L3 to ground in zone 2 3 6 3 3 Zone 3 e Phase L1 L2 to ground Figure 3 39 Double phase L1 L2 to ground in zone 3 48 e Phase L1 L3 to ground TUV TRIP Figure 3 40 Double phase L1 L3 to ground in zone 3 e Phase L2 L3 to ground Figure 3 41 Double phase L2 L3 to ground in zone 3 49 3 6 4 Double phase faults In this section the relay response to double phase faults is demonstrated In Figures 3 42 3 43 and 3 44 results are shown where double phase faults 11 12 L1
48. he GFC start condition STCND output that activates the selected loop of the distance protection measuring zones When the corresponding delay time is reached these zones send out the trip signal In case of a three phase fault in forward or reverse direction all the general fault criteria forward operation signals GFC STFWLI GFC STFWL2 GFC STFWLS3 or general fault criteria reverse operation signals GFC STRVLI GFC STRVL2 GFC STRVL3 in all the three phases are activated With the double phase fault both in forward and reverse direction it has been shown that only the general fault criteria forward operation signals or general fault criteria reverse operation signals of the involved phases are activated In the presence of a ground fault beside the activation of the general fault criteria operation output in phases the general fault criteria operation of PA E loop output has also been activated The operation of the numerical relay when the single phase to 55 ground fault occurs has also been investigated It has been shown that successful activation of the general fault criteria operation output of the involved phase and general fault criteria operation of Ph E loop output in both directions are achieved The same result has been obtained with the case of double phase to ground fault Problems experienced When everything was done and we started to test the relay the relay was not picking any of the earth faults because
49. he disadvantage with this method of discrimination is that faults close to the source which result in bigger currents may be cleared in a relatively long time These relays are used a great deal when the source impedance is large compared to that of the power system element being protected when fault levels at the relay position are similar to those at the end of the protected element 1 2 1 3 Inverse time relays The fundamental property of inverse time relays is that they operate in a time that is inversely proportional to the fault current Their advantage over definite time relays is that for very high currents much shorter tripping times can be obtained without risk to the protection selectivity Inverse time relays are generally classified in accordance with their characteristic curve which indicates the speed of operation based on this they are defined as being inverse very inverse or extremely inverse 1 2 1 4 Setting for overcurrent protection The principles for setting instantaneous units differ relative to the location and on the type of system component being protected Three groups of component can be defined lines between substations distribution lines and transformers 1 Lines between substations The setting of instantaneous units is carried out by taking at least 125 of the symmetrical root mean square rms current for the maximum fault level at the next substation The procedure must start from the furthe
50. in order to get the real values of the primary side of the line model These setting values are the secondary base values and nominal primary to secondary scale values of the current transformers and voltage 30 transformers In this test the base values of current and voltage are 1 and 69V respectively The nominal scale values for current transformers and voltage transformers are 100 and 3 347 respectively Et Test_lab Org1 Stn1 Bay1 REL51123 1 Parameter Setting Tool EN File Edit View On line Help ES 2 amp Setting Group 19 Test lab Drg Stni Bay1 REL51123 1 CC Contents of Analogue Inputs Modules O Test_lab Org1 Stn1 Bay1 REL51123 Parameter Name 1 TERMINAL OVERVIEW SERVICE REPORT fr 5o Hz 21 CA TERMINAL REPORT CT Earth 1 SETTINGS Terminal Value PST Value Name 1 Mb CJ Built in HMI Scale 100 000 t 2 Communication MIM slot numbers 2 5 Service Values f l U PQ I2b I 0 5 Terminal Identifiers EVENT MASKS I25cale 100 000 fin TEST Figure 3 18 Analogue Inputs Modules parameters 3 5 2 Setting for distance zones The fundamental rules have been discussed in the earlier chapter The following values see Figure 3 19 have been used for the settings e Zone 1 covers 8596 AB forward direction e Zone 2 covers 10096 AB 3096 BC forward direction e Zone 3 covers 10096 AB 100
51. in the reactive and the resistive direction for each zone separately makes it possible to create fast and selective short circuit protection in power systems Phase to earth distance protection serves as basic earth fault protection in networks with directly or low impedance earthed networks Together with independent phase preference logic it also serves as selective protection function at cross country faults in isolated or resonantly earthed networks 69 Independent reactive reach setting for phase to phase and for phase to earth measurement secures high selectivity in networks with different protective relays used for short circuit and earth fault protection The distance protection zones can operate independently of each other in directional forward or reverse or non directional mode This makes it suitable together with different communication schemes for the protection of power lines and cables in complex network configurations such as double circuit parallel lines and multiterminal lines Zone 1 2 and 3 can issue phase selective signals such as start and trip Basic distance protection function is generally suitable for use in non compensated networks A special addition to the basic functions is available optionally for use on series compensated and adjacent lines where voltage reversals might disturb the correct directional discrimination of a basic distance protection The figure below shows the operating ch
52. ine distance protection REL 511 2 3 3 1 Laboratory Set Up Em 3 2 Line iodel ERR ree ERR 3 3 Numerical relay REL 511 2 3 0 0022 3 4 Installation and set up for REL 511 2 3 0 22 3 4 1 Relay installation cesses meme mem emen 3 4 2 Configuration and tools used 3 4 3 The initial set of the 2 3 5 Parameter setting e RR DEREN e EC EU QN tA A 9 oo 10 12 12 13 14 15 16 16 18 20 20 21 22 23 23 26 29 29 vi 3 5 1 Setting for analogue inputs 30 3 5 2 Setting for distance 70 2 0 0 31 3 5 3 Setting for the general fault criteria function block 35 3 5 4 Setting for the fault locator FLOC function 35 3 5 5 Setting for the miscellaneous function blocks 36 3 6 Results using numerical relay REL 511 2 3 7 7 2 4 37 3 6 1 Three phase 37 3 6 1 1 Zone vcs 38 ERO AE 39 3 0 1 3 ZONE q a pasas 39 3 6 2 Single phase to ground fault cesses 40 3 6 2 1 Zone 40 ER AIAT A V UP 42 3 023 ZONE m 43 3 6 3 Double
53. ive sequence reactive reach of distance protection zone n for Ph Ph faults RIPP Positive sequence line resistance reach of distance protection zone n for Ph Ph faults Positive sequence reactive reach of distance protection zone n for Ph XIPE E faults Positive sequence line reactance included in distance protection zone RIPE for Ph E faults Zero sequence line reactance included in distance protection zone n for Ph E faults Zero sequence line resistance included in distance protection zone n ROPE for Ph E faults RFPP Resistive reach of distance protection zone for Ph Ph faults RFPE Resistive reach of distance protection zone n for Ph E faults Time delayed trip operation of the distance protection zone n for Ph tnPP Ph faults nPE Time delayed trip operation of the distance protection zone n for Ph E faults The ZM distance protection function provides fast and reliable protection for overhead lines and power cables in all kinds of power networks For each independent distance protection zone full scheme design provides continuous measurement of impedance separately in three independent phase to phase measuring loops as well as in three independent phase to earth measuring loops Phase to phase distance protection is suitable as a basic protection function against two and three phase faults in all kinds of networks regardless of the treatment of the neutral point Independent setting of the reach
54. line resistance Table 3 4 Parameter setting for FLOC 35 3 5 5 Setting for the miscellaneous function blocks 36 Function block Parameter Set value Unit Description IOC IP gt gt 65 of Ilb Operating phase current Instantaneous IN gt gt 50 of Ilb Operating residual current protection IP gt 30 of Ilb Operating phase overcurrent TOC tP 10 Time delay of phase Time delayed 5 overcurrent function overcurrent IN 100 9o of Operating residual current protection Time delay of residual tN 10 5 overcurrent function Operate value for the phase UPE lt 120 of Ulb overvoltage function TOV t 5 Time delay of the phase Time delayed overvoltage function overvoltage 3U0 30 of Uib Operate value for the neutral protection ap overvoltage function t 5 Time delay of the neutral 5 overvoltage function TUV UPE 80 of Ulb Operate phase voltage Time delayed undervoltage t 5 S Time delay protection TEF IN 5 of Ilb Start current for TEF function Definite and inverse time Imin 100 96 of IN Minimum operating current g delayed residual overcurrent 1 0 S Independent time delay protection I Base 15 of Ilb Base current T Base 50 C Temperature rise at base THOL Thermal overload tau 5 min Thermal time constant protection TAlarm 80 C Alarm level TTrip 120 C Trip level DLD U lt 50 of Ulb Operating phase voltage Dead line det
55. low Status indication LEDs Ready REx5xx Ver x x C Quit 2 E Enter menu LCD display Optical connector Cancel and Enter buttons 4 Navigation buttons 73 2 Logon and build a new project tree When starting CAP 540 the following dialog appears CAP 540 Licensed to Hung Manh User Name Password Change Password Cancel You should fill in User Name and Password and click OK as follows User Name systemadministrator Password 10 When you have logged on you can create a new project tree by selecting File New Project After typing the file name in the New Project dialog box and clicking OK a project structure down to Bay level will be created with default names Right click on the nodes and select Add to add more nodes to your project The last level is the Terminal level Right click on a Bay and select Add In the Terminal Modules dialog select REL 511 V2 3 Line Protection Terminal Modules P Select a Terminal DK REL511 v2 3 Line Protection In ion p Slave Number h Type in a vacant slave number it must be unique for each terminal that belongs to the same SPA loop and click OK In our case we use the number 30 3 Setting and configuring the terminal The specific values for each setting parameter and the configuration file have to be available before the terminal can be set and configured 74 Each function included in the terminal has several setting parameters that h
56. n the transformer magnetic in rush current when energising the transformer in order to avoid lack of coordination If the instantaneous units of the transformer secondary winding overcurrent protection and the feeder relays are subjected to the same short circuit level then the transformer instantaneous units need to be overridden to avoid loss of selectivity This applies unless there are communication links between these units which can permit the disabling of the transformer instantaneous overcurrent protection for faults detected by the feeder instantaneous overcurrent protection 2 2 Differential protection Differential protection operates when the vector difference of two or more similar electrical magnitudes exceeds a predetermined value An example of differential arrangements is shown in Figure 2 2 1 The secondaries of current transformers CTs are interconnected and the coil of an overcurrent relay is connected across these Although the currents I1 and I2 may be different provided that both sets of CTs have appropriate ratios and connection then under normal load conditions or when there is a fault outside the protection zone of the element secondary currents will circulate between the two CTs and will not flow through the overcurrent relay If a fault however occurs in the section between the two CTs the fault current would flow towards the short circuit point from both sides and the sum of the secondary currents w
57. nfiguration and default parameters The relay has been configured for three phase trip with the following function blocks distance protection five zones were set current functions scheme communication voltage and supervision functions trip logic auto reclosing and breaker failure functions internal signals binary inputs and outputs disturbance report and events for Station Control System SCS For detailed default configuration refer to 15 3 5 Parameter setting The parameters can be set using the Parameter Setting Tool PST PST is a tool for monitoring service values protection and control terminal and relays From CAP 540 29 the PST can be started from the project tree or from a function block within the configuration worksheet as follows From the project tree in CAP 540 gt In the project tree select the wanted terminal instance gt With a right click select Parameter Setting From a function block within a worksheet in CAP 531 gt Opena worksheet for the wanted terminal instance With the right or left mouse button double click the wanted function block The Function Block dialog appears Click Parameter Settings When the parameter tool starts the main window according to Figure 3 17 appears E Test lab Org1 Stn1 Bay1 REL51123 1 Parameter Setting Tool E ni xj File Edit View On line Help ES EX Setting Group fi 71159 Test lab Orgl Stn1 Bay1 REL51123 1 SETT Contents of Line Re
58. of Technology 4 i Sheet 114 Laboratory exercise 114 5 6 PSD 370 6 GFC STPE BLOCK START PSD START BLKIO1 ZIN BLKIO2 ZOUT BLKIPH RELIPH BLK2PH REL2PH IOCHECK TRSP EXTERNAL ZM1 470 6 ZMI BLOCK TRIP BLKTR VTSZ TRL2 GFC STCND STCND TRL3 START STL1 STL2 STL3 STND ZM2 471 6 ZM2 BLOCK TRIP BLKTR VTSZ TRL2 STCND TRL3 START ZM2 START STL1 STL2 STL3 STND zm3 472 0 _ SET IN REVERSE DIRECTION BLOCK TRIP ZM3 TRIP BLKTR VTSZ TRL2 STCND TRL3 START STL1 STL2 STL3 STND Prepared T M Hung Akyea 20 09 05 nm Acsi arie Kanon 28 09 05 Configuration diagram IMP PROT HH REL51123 Resp TRerii Power System Protection Chalmers University of Technology Laboratory exercise 1 2 3 4 5 6 460 6 BLOCK TRIP STFWLI STFWL2 STFWL3 STFWPE STRVL1 STRVL2 STRVL3 STRVPE STNDL1 STNDL2 STNDL3 STNDPE STFWIPH STFW2PH 1411111111 STFW3PH STPE GFC STPE STPP i SELECTIVE TRIP 0034 OUT FLOC 1125 6 DLD 210 6 DLD BLOCK START FLOC PSL1 PSL2 PSL3 RELEASE DISTHS DISTH4 DISTH2 DISTH1 DISTLS DISTLA DISTL2 DISTL1 DISTOK
59. on e Page layout Create drawing forms for printed pages A new project tree can be created from within the CAP 540 10 A project tree in CAP 53 shown in Figure 3 11 can only have the terminal and work sheets The graphical configuration is made in the work sheets NE ER Project ler REL51123 1 gt a Content gt Ef 0 ap Figure 3 11 Project tree It is important that you use the correct set of functions to work with the configuration of a terminal from the beginning These functions are selected in the Function Selector in the Edit menu There are many available function blocks for the same function and the Function Selector is used to choose them For example I O module01 in the CAP REL511 program module can be configured to be either as Binary Input Module BOM Binary Output Module OM Input Output Module JOPSM Input Output Position System Module DCM Differential Communication Module 26 A choice of these modules gives different shape of the function block for the I O module01 For instance the logical I O module01 1001 BIM can be compared to BOM as shown in Figure 3 12 O module IFO module POSITION ERROR POSITION ERROR BLKOUT 1001 11 BINAMEO B01 1001 BI2 BINAMEO2 BI2 B02 1001 13 BIS 1001 14 BINAMEO4 Boa IO01 BIS BINAMEOS BIS B05 1001 BI6 BINAMEOS BIS B06 1001 BI7 BINAMEO7 BI 10
60. ould flow through the differential relay In all cases the current in the differential relay would be proportional to the vector difference between the currents that enter and leave the protected element if the current through the differential relay exceeds the threshold value then the relay will operate l gt LE y Protected Element A Pale Nn lt Na Restraint coil Nop Operating coil Noe Figure 2 2 Differential relay with variable percentage characteristics The differential protection has the following advantages 2 e Differential current protection does not react in principle to external short circuits and therefore does not require the time lags to be coordinated with the protection of the adjacent sections of the line e Differential current protection does not react to peak currents caused by overload or swings and therefore it has high sensitivity The main types of differential current protection are 2 e Longitudinal differential current protection of lines comparing the currents at the beginning and end of the protected section e Transverse differential protection of parallel lines balanced or directional comparing the currents in the parallel circuits e Differential current protection of bus bars 2 2 1 Longitudinal differential This is used on sections of small length up to 5km in 35kV networks and up to 10km in 110 networks in those cases where the cu
61. phase to ground faults nonnen eneen 45 3 6 3 1 Zone aaa 45 3 0 3 2 Z 0116 2 vaneen ERR UU Ed tre Du 47 3 0 3 3 ZONE eee CU et GR du ertt o E VAR PERSE 48 3 6 4 Double phase e meme 50 3 041 Zone 50 364 22 ZONE2 aeter data 52 36 43 ZONE 3 eet sh dd poo enu rodado einen Rel Axa e o rate es 53 4 Conclusions and further work 55 zo oe t UIDI So eren en y oa beeren daw Stone ays ah Sd Meg gunt was 55 WOK ER ET AE EERTE E EEE E E 56 References 57 Appendix A Laboratory for undergraduate student 58 Appendix B Relay set up manual 73 Appendix C Relay configuration 78 vii Chapter 1 Introduction The diploma work proposal is entitled Numerical Distance Protection Relay Commission and Testing with the aims to calculate appropriate settings for the protection relay configure the relay install commission and testing the entire protection The numerical distance protection relay used is REL 511 2 3 of ABB Company which detects both phase to phase and phase to earth faults and it has a quadrilateral operating characteristics The REL 511 2 3 has been connected to a network model through three single phase voltage transformers and three current transformers A three phase resistive load of 9 kW has been connected to the line model The power line model operates at 400 V tha
62. rrents cut offs or distance protection does not conform to requirements in speed selectivity and sensitivity The pilot conductors along the track of the transmission line carry out current comparison at the end of the protected section Phase currents are not usually compared but rather the currents at the output terminals of summators or combined filters at the end of the protected section which transform the three phase system of currents into a single phase system Types of longitudinal differential current protection for transmission lines are e Circulating currents In a scheme with circulating currents under normal conditions and with an external short circuit a current circulates in the pilot conductors The differential relays at both ends of the protected section are so connected that when there is no fault in the protected zone braking torques arise there which prevent the relay from tripping In the presence of short circuit in the protected zone the equality of the ampere turns of the primary winding of the differential current transformer is disturbed and the relay working winding becomes energised e Balanced voltages In a scheme with balanced voltages under normal conditions and in the presence of an external short circuit there is no current in the pilot conductors In the presence of a short circuit within the zone of protection the equilibrium of the secondary winding voltages of the isolating transformer is dis
63. ssion and two loads two 9 kW three phase resistive loads The entire model operates at 400 V The line model consists of six identical 7t sections each corresponds to 150 km of a 400 line The sections can be connected arbitrarily in series or parallel The data for a real 150 km section are X 50 40 phase 4 17Q phase 60 Zero sequence impedance Zo 371 The impedance scale of the line model is given as 1 53 2 The numerical relay used in this laboratory is the Line distance protection relay REL 511 2 3 from ABB The REL 511 2 3 is based on a full scheme distance protection function that detects both phase to phase and phase to earth faults and has a quadrilateral operating characteristics A separate general fault criterion with advanced characteristics is used for phase selection and as an overall measuring function which increases the total operating security and facilitates remote backup applications The numerical relay REL 511 2 3 line distance protection terminal is designed for main and backup protection monitoring and control of power lines cables and other primary objects It be used in systems with simple or complex network configurations regardless of the type of system grounding Relay parameters Current Rated I 1A Nominal range 0 2 30 I Operative range 0 004 100 I Permissive overload 4 I continuous 10071 for 1 s Voltage Rated U 110V Nominal range 80 120
64. sson 28 09 05 Configuration diagram REL 511723 Repdp J i Power System Protection Chalmers University of Technology exercise heet 914 4 CLR LEDS IOO04 BII ACK RST NEWIND BLOCK FAIL LEDTEST HLO1 1401 6 HMI_LEDs RED YELLOW GREEN A001 165 6 HLO02 1402 6 AND HMI LEDs INPUT1 OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN ZMI START A002 166 6 HL03 1403 6 AND HMI LEDs OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN ZM2 START A003 167 6 HLO4 1404 6 AND HMI LEDs INPUT1 OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN ZM3 START Acsi arie Kanon 28 09 05 Configuration diagram HMI LED REL 5112 3 T ed Chalmers University of Technology Laboratory exercise CELNE 1 2 3 4 5 6 Ri Power System Protection Pd A004 185 6 05 1405 6 AND HMI LEDs INPUT1 OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN A005 186 6 06 1406 6 AND HMI LEDs INPUTI OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN 006 187 6 HLO7 1407 6 AND HMI LEDs OUT RED INPUT2 NOUT YELLOW INPUT3 GREEN INPUTAN A007 51
65. st substation then continued by moving back towards the source When the characteristics of two relays cross at a particular system fault level thus making it difficult to obtain correct coordination it is necessary to set the instantaneous unit of the relay at the substation which is furthest away from the source to such a value that the relay operates for a slightly lower level of current thus avoiding loss of coordination The 25 margin avoids overlapping the down stream instantaneous unit if a considerable DC component is present In high voltage systems operating at 220 kV or above a higher value should be used since the X R ratio becomes larger as does the DC component Distribution lines The setting of the instantaneous elements of relays on distribution lines which supply only pole mounted MV LV transformers is dealt with differently to the previous case since these lines are at the end of the MV system They therefore do not have to fulfil the coordination conditions that have to be met by the lines between substations Therefore the setting for these units is 5096 of the maximum short circuit current at the relay location or between six and ten times the rated current Transformer units The instantaneous units of the overcurrent relays installed on the primary side of the transformer should be set at a value between 125 and 150 per cent of the fault current existing on the low voltage side This value is set higher tha
66. t is a three phase model of a 400 kV transmission system thus the voltage scale of the model is 1 1000 The line model consists of six identical x sections each corresponding to 150 km of 400 kV line The T sections are made of series reactors and shunt capacitors which be connected arbitrarily in series or in parallel In this experiment the 5 5 have been connected in series The line impedances are proportional to the line lengths and this property has been used to calculate the distance from the relay location to the fault The relay has been fed with the measured current and voltage signals from the primary side through the current and voltage transformers thus the secondary values have been used for the settings of all parameters The following function blocks have been configured into the relay with their appropriate parameter settings distance protection function overcurrent function voltage and supervision function trip logic internal signals binary input and output human machine interface HMI LED disturbance report and events for station control system The test faults performed in zones 1 2 and 3 are three phase fault single phase to ground fault double phase to ground fault and double phase fault After each test the disturbance report has been uploaded into a PC for evaluation using the REVAL tool made by ABB The relay has responded positively to all types of faults mentioned above and can
67. tCriteria 6 Setting of line reference for the Fault Locator FLOC The FLOC provides the distance to the fault together with information about the measuring loop that has been used in the calculation H Calculate the setting values for the FLOC For definition of the parameters refer to page 72 The following values should be used XISA 0 001 RISA 0 001 XISB 1500 RISB 1500 Xm0 00 Rm0 0 Q Setting of the FLOC parameters can be done on the local human machine interface HMI unit under the menu Setting Functions Group 1 Line Reference 7 Exercise in the Laboratory Carry out the following tests i Three phase fault ii Double phase fault iii Double phase ground fault iv Single phase ground fault Faults are applied by closing the contactor according to Figure 1 66 Observe the LED on the relay during the tests and upload disturbance reports from the relay to the PC after each type of fault by using CAP 540 under the menu Programs Disturbance Handling Terminal list Note To upload the disturbance report from the terminal to the PC the procedure below must be followed Plug the cable to the optical contact under the local HMI of the terminal Plug the other end of the cable to the COM port of the PC The COM port of the PC are two therefore if you plug the cable to COM port 1 or COM port 2 it must be then set on the PC as COM 1 or COM 2 respectively This can be
68. tance included in distance protection zone n for Ph E faults 7 25 220 56 9 36 285 45 12 09 367 62 Q ph Zero sequence line reactance included in distance protection zone n for Ph E faults ROPE 6 08 18 24 0 78 23 61 0 99 30 42 Q ph Zero sequence line resistance included in distance protection zone n for Ph E faults RFPE 3 152 17 5 00 152 17 5 00 152 17 O loop Resistive reach of distance protection zone n for Ph E faults tPP tPE 0 00 0 00 0 15 0 15 0 25 0 25 Time delayed trip operation of the distance protection zone n for Ph Ph Ph E faults 1000 400 500 800 200 800 L 600 400 200 0 200 400 600 800 600 400 200 0 800 34 Figure 3 20 Load and impedance zone characteristics Impedance Zone 1 ZM1 Ph E Loop Impedance Zone 1 ZM1 Ph Ph Loop Impedance Zone 2 ZM2 Ph E Loop Impedance Zone 2 ZM2 Ph Ph Loop Impedance Zone 3 ZM3 Ph E Loop Impedance Zone 3 ZM3 Ph Ph Loop General Fault Criteria Ph E Loop General Fault Criteria AFC Ph Ph Loop Directional angles Ph E Ph Ph Loop Phase Load Load Load Load 3 5 3 Setting for the general fault criteria GFC function block Parameter Setting value Unit Description ARGLd 25 degrees Load angle the load impedance Limitation of resistive reach
69. tection of parallel lines It can be established at any end of the parallel lines The principle of transverse differential directional protection is illustrated in Figure 2 3 2 The secondary windings of the current transformers are connected cross wise that is the beginning of the windings of one current transformer are connected to the end of the windings of the second current transformer As a result we have the series connection of the windings of both current transformers as a figure eight A current relay starting device and a power directional relay directional device are connected in series between the same terminals Thus the relays are connected to the current difference of the protected parallel lines Figure 2 3 Principle of transverse differrential and directional protection Under normal conditions or in the presence of an external short circuit the secondary currents along the parallel lines are the same in magnitude and direction Thus the resulting current in the relay is zero the currents only circulate in the current transformer windings When there is short circuit on one of the parallel lines the equality of the current is disturbed and a current begins to pass through the relay equal to the difference of the secondary currents If it exceeds the setting of the current relay then the latter starts the protection closing the voltage circuit of the power directional relay If one of the
70. ted turns open circuits and faults to earth and should be disconnected by opening the circuit as quickly as possible the neutral of the generator should be well earthed either solidly or via a resistor or a reactor The differential protection should satisfy the following requirements it should 1 e Be sensitive enough to detect damage in the winding of the generator stator and yet not operate for faults outside the machine e Operate quickly in such a way that the generator is disconnected before any serious damage can result Be designed so that the main breaker is opened as well as the neutral breaker and the field circuit breaker 11 Line Differential Protection The form of differential protection using only one set of relays is not suitable for long overhead lines since the ends of a line are too far apart to be able to interconnect the CT secondaries satisfactorily It is therefore necessary to install a set of relays at each end of the circuit and interconnect them by some suitable communication link Pilot protection indicates that there is an interconnecting channel between the ends of the lines through which information can be transmitted is an adaptation of the principles of differential protection that can be used on such lines The principle of operation of pilot differential protection is similar to the differential systems for protecting generators and transformers but the relays have different settings becaus
71. turbed the secondary winding carries current and the impedance between the terminals of the primary winding is reduced The working winding of the differential relay then takes the current of the summation the working torque exceeds the braking torque and the relay causes tripping 2 2 2 Transverse balanced differential Balanced current protection is a type of transverse differential protection of parallel lines It is based on a comparison of the magnitudes of the currents passing through the lines It is established at that end of the line which is constantly connected to the Source For equal impedance parallel lines under normal conditions or in the presence of an external short circuit the balanced relays will not operate due to the similar distributed currents In the presence of a short circuit on one of the parallel lines the larger part of the current from the source passes along the faulty line while the smaller part passes along the undamaged lines In this circumstance the balanced relay will trip the faulty line At the receiving end of the parallel lines without an additional feed source the currents in the presence of short circuit on one of these lines are equal in magnitude but opposite in direction A balanced relay that reacted to the ratio of the current magnitudes and not to their direction would in this case not operate 2 2 3 Transverse differential directional protection It is a type of high speed pro
72. with H should be answered before attending the laboratory exercise Participant Date 59 1 Introduction Any kind of power system shunt fault results in customers being disconnected if not cleared quickly Distance protection meets the requirements of speed and reliability needed to protect electric circuits thus distance protection is used to a large extend on power system networks It is a universal short circuit protection Its mode of operation is based on the measurement of electrical quantities current and voltage and evaluation of the impedance towards the fault which basically is proportional to the distance to the fault Numerical distance protection is utilization of microprocessor technology with analogue to digital conversion of the measured values current and voltage computed numerical distance determination and digital processing logic 2 Aim of the Exercise The objective of this exercise is to test a modern numerical relay for various faults within the distance zones under consideration Three zones are set zone one is an under reaching instantaneous tripping zone set in the forward direction zone two is an over reaching zone with single time delay also set in the forward direction and zone three is an over reaching zone with double time delay set in the reverse direction 3 Power system model description The power system model used in this exercise is a three phase model of a 400 kV transmi
73. with the configuration in the work sheet and the debug mode is used to test the work sheet configuration Work Sheet 1 test Figure 3 14 Work sheet called Test To open a work sheet e Select a work sheet in the Project Tree e Double click the left mouse button or press Enter gt Function blocks variables setting and text comments are considered as objects in a work sheet In CAP 531 function blocks represent all the available functions in a terminal The function block can be one of the following Protection function e Control function e Monitoring function e Logic function The function block includes input and output parameters a type name and function block name as shown in Figure 3 15 below 28 Execution number r Cycle time Instance name p Y Tha01 936 3 Setting I Output parameters Input parameter Figure 3 15 Function block in the CAP 531 work sheet The function blocks in the work sheet can be connected together by using the connection mode 11 Work Sheet 1 test AND INPUT1 INPUT2 INPUTS INPUTAN Figure 3 16 Two objects are connected When the configuration preparation is completed it should be compiled in order to check errors and to prepare the configuration for downloading into the terminal 111 3 4 3 The initial set up of the relay Initially the relay has its default co
74. within the load RLd 270 50 O loop impedance area Positive sequence reactive reach in reverse XIRvPP 122 54 Q Ph direction for Ph Ph faults Positive sequence reactive reach in forward XIFwPP 122 54 Q Ph direction for Ph E faults Resistive reach forward and reverse for RFPP 152 17 DEBE Positive sequence reactive reach in reverse 122 54 Q Ph direction for Ph E faults Positive sequence reactive reach in forward XIFwPE 122 54 Q Ph direction for Ph E faults Zero sequence reactance of reach in reverse XORvPE 367 62 Q Ph direction for Ph E faults Zero sequence reactance reach in forward XOFwPE 367 62 Q Ph direction for Ph Ph faults Resistive reach forward and reverse for RFPE 152 17 O loop of imi ing Ph i INReleasePE 10 310 limit for releasing Ph E measuring Ij Max loops of imi ing Ph suri INBlockPP 20 310 limit for blocking Ph Ph measuring Ij Max loops IP 20 of Ilb Set operate value for measured phase currents IN gt 10 of Ilb Set operate value for measured residual currents tPP tPE 0 0 S Time delay of trip for Ph Ph Ph E faults Table 3 3 Parameter setting for GFC 3 5 4 Setting for the fault locator FLOC function block Parameter Secondary Unit Description Line length 900 km Line length value 173 00 O Ph Positive sequence line reactance RI 14 31 O Ph Positive sequence line resistance X0 519 00 Q Ph Zero sequence line reactance RO 42 93 Q Ph Zero sequence
75. y types Distance relays are categorized in two major schemes switched scheme and full scheme The block schemes for a switched scheme and full scheme are illustrated in Figure 2 8 5 In a switched relay the start elements detect a fault These elements 15 together with logic blocks determine the correct input signals with respect to the fault type Zones of operation are decided by timer block Measuring elements and directional elements decide if the impedance is inside a certain zone and the direction to the fault respectively The full scheme relay does not have the start elements It has measuring elements for each phase each zone and both phase to phase and phase to ground faults The operation is faster than that of switched relays Start elements R S T 0 o i R 0 S 0 T 0 Y Timer zones 1 2 3 Y Y Logic Timers Y Tripping Y Y relay Measuring elements And Directional elements Full scheme Tripping relay Switched scheme Figure 2 8 Block shemes for a switched and full scheme distance relay 2 3 5 Numerical relay 2 3 5 1 Structure of numerical relays A numerical relay consists of the following main subsystems e Microprocessor e Analog input system e Digital output system e Power supply 16 Figure 2 9 6

Numerical Distance Protection Relay Commissioning and Testing

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