Protection Engineer - Testing of 66by11.5kV GIS Instrument

Testing of 66/11.5kV GIS

I)Testing:In Testing protection engineer need to test the relay functionality with the help of two things:

a)Relay Setting File given by client.

b)omicron /testing kit arranged by third party contractor.

As per client’s need site includes different types Relay and so different types of  protection scheme, although Relay list generally used:

a)Siemens Relay( SIPROTEC  4 device).



d)Bay control unit(BCU SIPROTEC 5 Device).

a)SiemensRelay Details:

Each relay is represented by universal codes called ANSI codes according to its application. Relays are of different types and of different company make. Each company possess its own relay code, whereas the ANSI code for the particular relay remains the same.In Siemens Relay MLFB no. is known as relay code for identify its function.

Working Principle:All the functions mentioned in relay works properly by sensing the current and voltage value from CT &PT secondary as per requirement.. The deflecting torque is produced by secondary current of  CT and restoring torque is produced by voltage of potential transformer. In normal operating condition, restoring torque is more than deflecting torque. Hence relay will not operate. But in faulty condition, the current becomes quite large whereas voltage becomes less. Consequently, deflecting torque becomes more than restoring torque and dynamic parts of the relay starts moving which ultimately close the No contact of relay.

Now, this is a concept of general EM Relay but in field we use numerical relay which acts by these following process:

Sensed secondary value of CT and PT as in mili amps and in volt (equivalent to original KV or KA  rating from field side)        some filter for this this analog signal input and amplification for avoiding losses      analog to digital converter for the input to microprocessor    operational amplifier to get a constant error less signal to various Relay output ,LED and the items mentioned in fig1(mentioned below).

Through this front port and rear port PC can be connected for configuration and setting can be given for Testing  Purpose. All DC power source and MCB should be checked before powering for testing the Relay.

1)Distance Protection Relay

ANSI(American National Standard Institute) CODE: 21


Relay which functions depending upon the distance of fault in the line. More specifically, the relay operates depending upon the impedance between the point of fault and the point where relay is installed. These relays are known as distance relay or impedance relay.


In Distance protection there are four to five  zones used to protect via two distance relay end to end(local to remote) having different impedance value, nearest relay from one substation to any side will be considered as local Relay and another as remote. like this if four  substationD,B,C(practical sequence) are connected via transmission line one local end relay from substation B  need to put in PUTT(permissive Under Reach Transfer Trip) in its setting to protect zone1(80% of full line length),zone2(remaining 20% of zone1(zone1B) and 100% of next line length ),zone3(150% of next to zone2 line length) and zone 4 is considered as Reverse zone( in the reverse direction from substation B to Substation D).

So, any minor fault will pick up the Relay and if it is not cleared less than its tripping time  local end relay will send a direct trip command via teleprotection system under PUTT Mode to remote end Relay of zone1.Fault in any bus at substation will give adirect trip command to main 21 relay. There are  many types of protection SCHEME exists in 21 relay in which as per client’s need which can be used as example:



So according to client data sheet all these testing should be done by injecting current and voltage at CT & PT terminal of Relay as per requirement.Two types of AUXULARY Relay is used DMT(definite minimum time) and IDMT(inverse definite minimum time) in Control Relay Panelin order to clear the fault although IDMT (IEC Time Overcurrent as mentioned inside settings) fault clearing time is  lesser than DMT(In case of this type trip time is fixed).Whereas this functions block comes under EARTH FAULT PROTECTION, for E/F happened in zone1 direct trip will be send from nearest relay to fault position to remote end via teleprotection.





The relay whose operation depends on the phase difference of two or more electrical quantities is known as the differential protection relay. It works on the principle of comparison between the phase angle and the magnitude of the same electrical quantities.

Application:These type of Relay can be used in various field where requirement is to monitor parameters of two sides of an equipment like transformer LV/HV side, Motor stator and rotor, generator and feeder transformer of GAS INSULATED substation.

Working principle: Two CT is used(As per mentioned in above Fig2) for both side of equipment for monitoring the magnitude and direction of two current that is leaving or entering. Any fault occurred in CT primary side equivalent changes noticed in secondary side of CT also ,so at healthy condition the differential value of two CT secondary per unit value will be null(or extended to some approximation of two decimal is acceptable like 0.02) and in faulty condition after some extend of differential value(preferred by client 0.2-0.3) trip occurs.

For some high value fault like if it is exceeded the predefined differential value there are 2nd and 3rd   pickup and trip happen. This value also can be given during setting and before testing. Example of setting:

This Relay will only consider the differential value between the rated perunit value for CT secondary both side. So it needs a back up protection of overcurrent and earth fault relay , so BAY CONTROL PROTECTION UNIT(7SJ663  Relay is used as O/C &E/F Relay) is used as backup and having all interlock logic resides in this.

Testing: Before testing same precaution method should to be followed like:

  • DC fuse connection and continuity to relay.
  • Continuity from CT terminal to relay via link.
  • BI and BO(from master trip hardware) can be checked at the time of commissioning via CFC.

Types of test: 

  • Measurement Test: Injecting the per unit value of secondary CT current in Relay via omicron will showthe rated primary side value. This Testing is done to check the monitoring value matched with the rated value or not.
  • Stability & instability: injecting the per unit value one with 0 degree and another with 180 degree of CT secondary current will not trip as the condition of one side current entering and leaving of Relay is satisfied. Whereas both side putting on 0 degree will trip Relay in some millisecond. This testing is done to check the direction of CT current. In faulty condition this direction could be same soin that condition relay should trip.
  • Slope test: During this test relay can have two or three pick up differential value injecting above that relay should trip. Slope value is considered axis between bias current /restrain current vs. differential per unit value of CT secondary’s current. The pick up value occurred at some percentage amount of this slope, examined result should be a nearer value of this percentage during this test.
  • Harmonic blocking test: At the time of charging HV side of transformer generates flux abruptly due to transients currents in primary and secondary differs more than of its set value of differential (1st and 2ndtrip value). At that time relay should not trip the line otherwise charging will never be done with relay protection. More specifically this abrupt current is present in the sinusoidal signal for one cycle and 15-20% and 30-40% of its fundamental value. So this type of dangerous harmonics is two types EVEN & ODD. Considering Higher order harmonics is not necessary as we are considering only 1stcycle of charging signal, now 2nd, 3rd ,5th and 7th need tobe cleared. At the time of charging these feature will block the relay from tripping if value of 2nd and nth  harmonics is having the set value (given during testing as per client’s need) in percentage of its fundamental value. Typically it is 15-20% for 2nd harmonics and 30% for nth harmonic.

In Transformer charging basically two types harmonic is matter of consideration one is 2nd harmonic due to inrush current and another is 5th harmonic due to overflux.

During test injecting HV side with rated CT secondary current with 50Hz and LV side with 100Hz and setting value(15-20% of its fundamental value) of CT secondary rated current. So the Relay will monitor this value of secondary abnormality lies for (T=1/50<20MS) the 15-20% value of its fundamental component for 2nd harmonics and 30% of its fundamental component for nth order harmonics. For any transformer protection having this harmonic blocking feature will block the tripping more than its set value and less the set value will trip the Relay as it will consider that value as another abnormality rather not harmonics. These point is applicable for both 2nd& 5th harmonics set value in Relay settings.

  • RESTRICTED EARTH FAULT TEST: During faulty condition the fault current could be 2-5 times more than its rated value so this heavy current will also be sensed by relay that time relay should trip the line and should protect itself from this fault. Restricted earth fault ensures the protection of Relay as well as this heavy earth fault of lineduring this faulty condition. Some METROSIL  resistors are used to protect  relay from this earth fault. These special resistors are having the value of its resistance by a factory calculated settings as per client’s need. To check this feature CT injection should be at REF terminal and on LV terminal for this feature another REF CT is used. For testing this feature another all protection should be switched to off mode. Injection should be at REF terminal with a value of CT secondary per unit multiplied with differential value for pick up.85%of this pick up value relay should trip if this feature is working properly.
  • SENSATIVE EARTH FAULT TEST: This type of test is done protecting the relay from any sensitive (small or heavy) earth fault. During this type of test like all other test rests all other protection block will be switched off. Injection will be done at SEF CT terminal with the set value mentioned in settings menu prescribed by client. Tripping time should be matched for both two stage(minor and major) of trip for declaring this protection as ok.


ANSI CODE:50/50G/50N & 51/51G/51N


This Relay also works on the basis of current sensed by CT secondary terminal which may have  its primary in line or any equipment supply.This Relay is used to monitor overcurrent fault directional or non-directional(50-for DMT relay/51-for IDMT relay) & earth fault  directional or non directional(51G/51N). In case of Non-directional setting this Relay will sense only magnitude value for 1st& 2nd pickup and trip. And angle will also be checked for directional setting. Fault occurred  In opposite direction towards star line in protected zone will be sensed by Directional setting whereas only magnitude will be considered in case of non directional setting .

Settings need to be given as per client’s permission. One of the client’s preferred O/C OR E/F Relay setting example:

During testing one protection needs to be switched off rest all to check the relay behaviour in every possible condition of fault.

Both DMT &IDMT Relay is used for different types of faults. Generally this type of relay is used for back up protection with some another relay protecting protected zone or some time as BAY CONTROL PROTECTION UNIT(BCPU). All the logic performed by relay will be mentioned here. Inputs and outputs will be taken as different signals. These signal could come by hardware or by goosing from another relay.





Bus bar is having incomer and feeder over its arm so as per KCL total summation of current (entering and leaving BUS BAR) will be zero.So same magnitude of current entering bus bar should leave with same magnitude of current with 180 degree. If these magnitude and angle varies this will trip the bus bar differential relay to trip a bus zone. Maximum industry are using double bus bar for maintaining redundancy as bus zone A and B. Any fault happen in zone A it will trip the bus from feeder and incomer as well as both the zone’s checkzone will trip also (announce the fault type in their LED also). Check zone is introduced for more accuracy and redundancy, if in case bus bar protection relay fail to trip or DC gone at that time tripping will also be done with the check zone relay. Same procedure is applicable for zone B . Now any abnormality sensed by zone A (in any zone A feeders CT terminal) relay will send a signal to trip the master trip relay of bus coupler and this master trip will send a command to all the feeders and incomers master trip(86.1 And 86.2). Some times this communication done by pure hardware or sometime transferring the signals via FIBRE OPTIC CABLE(PATCH CORD) and for 2nd option goosing is need to be done by software.

Stability Test: Actually in bus bar differential relay all the feeders CT secondary is looped at the back panel of BUS BAR DIFFERENTIAL RELAY  by hardwearing. So Each and every feeder is having bus zone CT as well as check zone CT reference. One channel’s Rphase (from omicron kit) will be connected any of the feeders ZONE  CT TB and Y phase   will be connected with other feeders zone CT TB in Rphase CT reference and neutral will be common for both . Same method to be followed for check zone also. Now connecting in this manner will give the injection set up for R phase shifting in both feeders CT reference will give other phases both the pair of phase fault can also be checked by connecting two phases at a time. Giving both the channels full load CT secondary rated current one with 0 degree and another with 180 degree at this time relay should not trip as this is the ideal or more specifically stable condition. So injecting both the channel with full load CT secondary rated current at an angle 0 degree will trip.


MLFB NO:6MD63/6MD83/6MD85

Bay control unit have all authority of breaker protectionbasically it is the Brain of all relay attached to this. As far its having full breaker control authority it needs some signal from other relay or sometime from other bay or some time from the relay attached nearby whatever it needs some communication channel , this is done by FIBRE OPTIC  cable or by hardware. Once these signal came it will be performed in its CFC for further client authenticated logic. It has one power supply module along with BI BO MODULE (compact and expanded both) and communication ports at rear side. These BI’s are coming from anywhere of field operative instruments and with the help of local or remote switch it can be controlled from field or from CRP or sometime from CONTROL ROOM. As per the CFC it will PERFORM  a logic inside it and as a result BO will be operated. Basically control part of relay is monitored by BCU(or sometime as BCPU) only.It is the interconnection between various logics needed from various side of the field for accurate breaker operation, breaker failure protection and some different and to get a quick unique response in some particular bay for fault happened in another bay or relay.




This relay is used for short distance line protection. As protection provided by this relay measuring the differential value between sending end with receiving end of transmission HV line this is called as line differential relay protection. In this protection also one BCPU acts as  logic decider and protection function is provided with 87L differential relay(7SD61). So, this can also be used as incomer(in one bus bar) protection. For example let suppose two bus bar are there and two incomer as well, so both this incomer carrying power ,current, voltage from substation A to B(suppose) are connected through FO cable for communication and tripping purpose. So through communication cable tripping command to another side will be sent from any one of nearby faulty side Relay, If in case this communication cable is broken both side communication fail and differential block annunciation will come . At this time Relay will not trip for any fault. This is differed from distance protection as it will monitor only one zone between sending and receiving end means two substation, whereas in distance protection multiple zones and subsequent (minimum three) substation’s distance protection are considered.If any scheme two incomer is used for redundancy so in that case both the incomer is using LINE DIFFRENTIAL RELAY they should be connected with a FO cable (patch cord). This arrangements is done as any of these two incomer gets faulty then through the bus coupler two buses will be connected in one healthy incomer , that time load should be distinguish properly.





Bus coupler is used to couple multiple bus connected in parallel for redundancy. Any fault is happening in one bus another bus should be connected  to that faulty bus feeders for maintenance and redundancy. So in normal condition bus coupler CB should open means bus are not connected to each other still sharing the same load , any faults occurred in any one of these bus incomers  that will be disconnected by tripping and  that  trip will send a signal to bus coupler CB( via cfc and hardware) to close and isolators connected to both bus will be closed for closing CB. When fault will be cleared in faulty incomer relay that time if TSS and AIM mode is at bus coupler and auto mode respectively through CFC and via logic bus coupler CB will be open and though isolators. This logic could be different as per client’s need and scheme.



  • After reaching side protection engineer’s 1st duty is to maintain the safety, Helmet Safety shoes are necessary for that client cannot question him for safety issues.
  • DC test need to be done at first before powering the panels. Continuity from dc power source to MCB and MCB to different inter panel terminals and intra panel wiring need to be checked.
  • Although checking the wiring details and continuity in panel and from panel to field and  BI BO is crucial part of Testing. During Testing for some unexpected issue one need to check the  continuity from  relay input and from 86.1 or 86.2 to necessary linked binary output via CFC or via hardware.
  • After cable termination from field side wiring check for BI and BO with respect to field side is necessary to declare relay panel for final stage checking before charging.
  • Before charging testing of each and every panel’s individual relay need to be tested as per client given settings and need to save the soft copy as testing details.


Software part:

For SIPROTEC 4 and 5 Relay device DIGSI manger 4 and 5 is used(respectively).one protection engineer must

For Alstom relay MICOM’s agile is used. Sometime for mini Siemens Relay REYROLLE device is used and REYDISP  manager is used as software to configure.

For each and every device FACTORY prepared back up will be available to client.


  • Settings decided by client should be uploaded to relay at the time of testing for individual protection block.
  • CFC checking by taking relay online is necessary to track a logic is working or not.
  • For taking any signal to be controlled or displayed by SCADA or by another IED to a distance connected by Ethernet protocol or by FIBRE OPTIC cable (respectively). signals need to masked in MASKING IO CONFIGURATION(in DIGSI 4) / INFORMATION ROUTING( DIGSI 5). For taking any signal to be displayed in SCADA that signal 1st need to report as source / destination catalogue in IEC 61850 system configurator. Its an intermediate station between IED & SCADA  or IED & IED. So any changes done in software as for goosing need to be upload in IED and as well as IEC in order to make that active  If all signals are coming to IEC 61850 SYSTEM CONFIGURATOR  as per NTAMC LIST( given by Client) it would be easier for SCADA engineer to map those in ENGINEERING PC of  PAS / SAS via IEC STATION. So signal masked as configured at S(system interface) source or destination only will be coming in IEC’s  source / destination catalogue.
  • Device to device goosing: This needs a separate group created named as GOOSE in masking or information routing. All the signal need to be goosed should be mentioned here(except the BAY  in which creating goose). These need to be done to each and every Masking / in formation routing of bay(BCU).  These is actually done as some signal when cannot come by hardwaring.

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