Protection Engrs Grp (3)
– What is the difference between phase IDMT and earth IDMT can anyone explain? Please
– IDMT clears itself, whatever your fault is o/c or E/f. it will take tripping time according to your curve.
– Earth Idmt will check & operate based on neutral current. Whereas phase Idmt will check phase current but it’s IDMT that’s why it operates according to curve
– How can I set or calculate tripping time? How can calculate fault current & distance Inline?
– one query related to VT usage with Ups as per micron P127 manual, advise VT to use connect with relay(pic attached above) but our customer needs to use UPS (110 vacs) what are the issues if we use with UPS? Any ideas or advice on this?
– Did you ensure may they mean is UPS for Aux Power Supply?
– VT terminal is for measuring sensing Voltage For measuring and protection
– Shall I clear when ClientWant use UPS Power? I mean on VT terminal or Aux Power Supply?
– You can check the function of that terminal on manual Aux supply you can use ups supply but vt connection is 3 phase supply only
– Yup. If we use Aux Power Supply by UPS in that case, You can But In the VT connection, we must use by 3 Phase Supply only. P127 is usable for voltage protection also. So, the VT terminal should be direct to the Source+VT connection But without Aux supply. this terminal VT function is for power supply also.
– You don’t need to clear.
– They mean for PT supply
– Yes they want to use Ups instead of VT supply. what is the issue that will be there or what is the thing that needs to check before use (like phase angle needs to check etc..) UPS SUPPLY?
– In your diagram, there is no VT ckt used. 33,34 Is for aux voltage. All other in ckt is Ct connection. U can use aux voltage as DC or AC. Check the manual for more.
– There is no VT. UPS supply might be for Auxiliary. Yes, I answered them they use VT 110VAc to 110vdc Ups. I discussed with Rio in this group
– Asked them to double-check angle and magnitude are the same before connecting. Just to ensure Make your list of active protection & control logic list. Then test control & test protection with secondary inject current.
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– what are resistive reach and residual compensation in distance protection? How to test I need step by step guide and have any links or documents.
– Residual compensation factor used for calculations of ground impedance when we have earth fault on the line. For earth fault, we have conductor imp+ground impedance. The relay must factor out the ground impedance out of the total impedance that it is seeing
– How do we know the residual compensation factor? Do we have to calculate?
– (Zo x Z1)/3Z1. Relay uses this formula to calculate it
– 1. pick up each phase and three-phase on HV and LV winding Slope 1 & 2 Characteristics Internal and External Fault Test 2nd & 5th Harmonic Test Zero Filter Sequence Test
– https://www.youtube.com/watch?v=HgxL0GPPZ_A&t=1374s. Exactly what u need
– But we have to put the values in settings. Relay does not calculate itself.
– Resistive test is used to simulate the resistive fault (Fault angle=0°) that happened to the conductor. Each Zone of protection has a different Resistive Reach (Phase – Ground & Phase- Phase)
– That’s why we need to make sure that the resistive fault test still belongs to each coverance protection area
– Can we check the o/c pick-up in idmt curve?
-Yes we can
– How to do that? Can u say
– Do you have a calculation relay protection test in the checklist sheet?
– How much offset we can allow for big transformer differential protection? Is it 10 percent of the differential current?
– Please find it in your organization, you can check in the FAT report or Protection Checklist.
– Please tell me. IS code for BDV TESTING and how much value according to IS or IES?
– 20 percentage. It’s safe.
– Serial number 2 was mentioned in the wrong place. How to connect solid earthing in Transformer?
– You need to connect star side neutral to the ground (without adding any additional resistance). Thus you allow more earth fault current to flow in the system (through the neutral during earth fault ) so that earth fault protection relays can operate. TNCS and TNS can be an option. LV systems (415 volts) normally have this type of solid earthing (excepting offshore -FPSO & offshore Drilling ships ). Neutral earthing (System earthing itself is a big subject.
Please try to read Protection Relay Books (like PRAG – Alstom). https://www.se.com/ww/en/download/document/EIGED306001EN/. This may be helpful for you
– This Schneider one is the most lucid one to understand the different system grounding methods and the respective protection systems.
– Why do we use DEF protection in line protection?
In ABB line protection relays why do we have additional graphs like phase sequence?
Which parameters are important and affect our calculation for the length of the line? For example, what is the ground impedance for small lines, and what is its effect when compared with big lines?
– In the case of 3 CTs how do we connect in relays let say if we have one half breaker scheme on one side and a double bus on another side then we have 3 CTs. For small lines and ug cable feeders differential protection required
– Please send me how to calculate protection setting calculations. Kindly refer to manual respective relay manufacture.
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– who can assist why I have this error trying to write to the IED?
– I think graphical displays are not matching
– I think downloading the latest connectivity package
– Agree, please try to change from HW configurator
– Restarting your pc, or using 64-bit versions and vice versa might help
– Try to Enter the default password “ChangeMe1#
– Av changed the display type, and it’s working. however, I have another error of Rolling back Transaction while trying to write to the IED. no coming to its sowing the wrong password
– great, any description of why?
– I think someone maybe has changed the password already
– now only I installed that software
– use “ChangeMe1# without “, just ChangeMe1#
– you can try access bypass password with supervisory level also when the password cannot be accessed.
– I can’t able to open the software to change
– Did you try to enable supervisory level without software in the IED screen?
– How can I calculate the distance relay apparent z for 1ph to ground fault using the PSSE file?
– I never found this standard. Did used standard of balance RST to determine condition.
– Does anyone have an excel sheet to calculate the distance settings?
R phase 90 a
Y phase 60 a
B phase 90 a
N = ? a
– What about angles?
– You Can Calculate the symmetrical component formula. 30 <150°. 27 AM X4
– shares me document for bus bar calculation 50ka per one-second copper bus bar? It will be based on I^2t, where I am the RMS breaking current (not Making current capacity, which is higher). 1) What will be the current setting and how you will set it? 2) And how will you set the dial for current.
– For instance, you will set according to (locked rotor current)1.1-1.5 (depends on the type of relay).
– It’s multifunction digital MICOM relays.
– Overcurrent setting is 110% that means 330A setting how to check relay communication or not. Then Keep Isc current is 3full load current that means 900A. Locker Rotor or blocked rotor setting is 6*full load current that means 1800A with a minimum trip setting like in 150mSec
– E/F keeps 30A with IDMT curve base. Time should be very very minimum
– It’s a common value, lrc can be different, you have to clarify, if it’s without any resistors it can be more than 6. If you are moving to below 6 times Of current you will receive a frequent trip from the motor..also we need to study what kind of load on the motor, fluid or hard load. need to be considered. You need to see what kind of starting method is used. Accordingly, you can set the highest for the motor. But we need to deeper with time. Time we need to keep a little bit higher than the locked rotor
– For blowers starting time will be more
– My opinion, Isc calculated differently, and based on the power source, I see calculations like this the first time. That’s why I mentioned we need to concentrate on time and upstream settings
– What are the two modes of Generator AVR operation?
a) Voltage control. This setting field is used to enter the desired generator output terminal voltage. The AVR setpoint value range depends on the regulator sensing voltage and band setting. b) Power Factor Control. The PF Setpoint determines the level of generator power factor maintained.
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– How to test an anti-pumping relay of HV CB?
– If you push the CB ON button(CB should close) and then while the ON button is still pressed push the CB OFF button (or give protection trip) simultaneously then even after spring charge CB will not close. Also when the CB is closed u can see that when CB ON button is pressed, the anti-pumping relay will pickup.
– the differential alarm will not come at this condition (during saturation) if it is REB500. If it was an internal fault it will trip, if external not. Although without drawing/specific picture it could not be answered, to me it looks like matching CT(Interposing CT). Check if the ratio of bus CT and tie CT matches or not. The ratio is the same, 2000/1
– 60kv AIS operating manual and commissioning. We have and a half breaker scheme in our substation. I think installing these ct core in the middle Q3 CB panel so that it can share its core with both Q1 and Q2.
– Check furrell and schematics. If schematics are available then do share, Then we may find their purpose.
– The same I was told without having scheme it’s not possible
– What’s the main function of Pole Discrepancy Relays?
– Pole discrepancy is the difference in operating times among the 3 phases or poles and these pdrs give protection the logic to relay for operating if there is any mismatch in any of the three-phase.
– How does Brushless Generator operate without brushes?
– Brushless generators make less noise than brushed generators and present a smooth operation. Without electric brushes, there is much less friction when the generator is running. These are easier to maintain than brushed generators with fewer moving parts to clean, repair, or replace. Fewer moving parts also mean less wear and tear on the alternator. The absence of brushes eliminates overheating issues and breakdowns as well. While brushless generators may pose a higher cost upfront, they have an extended lifecycle of as much as three to five times longer than traditional brush models.
– In Transformer Gas Analysis, if H2 is more then what’s the type of transformer fault you can think of?
– For transformer H2 test DGA test is performed. A DGA test will indicate high thermal gases (Methane, Ethane, and Ethylene) as a result of overheating of the liquid. These gases are formed from a breakdown of the liquid caused by heat. Heating may be caused by poor contacts on a tap changer or loose connections on a bushing or a grounding strap.
– How do u detect CT saturation in Low Impedance Busbar Differential Relays?
– Adaptive trip logic is adapted for the detection of CT saturation in Low Impedance Busbar Differential Relays. One of the types is here will be a small permanent magnet generator also known as a pilot exciter coupled to the main generator shaft and generates a substantial voltage which is fed to AVR. The avr in turn generates dc voltage after taking feedback and supplies dc to the main exciter winding inside which a part of the main rotor will be rotating. This induces a voltage inside the rotor which is rectified into dc voltage with the help of rotating diodes and fed to the main rotor winding thus generating the main supply in the stator.
– Can anyone share notes or reading material on AC and DC hipot testing? Specifically for CT, and PT
– Which excitation system is better for power system stability?
– DC hipot is a destructive test. Hence, not recommended. U may do it as it’s the time during FAT, not anymore.
For cable, Switchgears- we always do VLF tests.
– Brushed Systems having series compounding transformers will practically take care of around 60% of load changes inherently even if avr fails. Brushless is also having PSS
– My question is which excitation system better and fast response for power system point of view
-That using permanent magnet
– Because the power supply for AVR is isolated, excitation confident
– Brushless time constant very high bez PMG output used for avr regulation and avr output used for the main exciter and then generator rotor field But static excitation system avr output directly connected with generator rotor field…Static excitation is a very fast response than a brushless excitation system. Maintenance point of view brushless system better than static excitation system.
– What we have to check is if the transformer tripped in 1. HV REF 2. LV REF 3. Differential Protection
Total Tx test, dga oil test, bdv test
– Kindly be noted that the above tripping along with what are the other protection optd?
– O/C & E/F WTI,OTI,PRV. HV REF means an earth fault between your HV CTs, through HV winding to the neutral CT. Do physical inspection for any obvious fault. If not found, reset and energize. If it trips again, it could be maybe a failed surge arrestor or transformer winding. Test the surge arrested. If ok, test HV winding. For LV REF, repeat the above but on the LV side of the transformer. For differential protection, it could be any fault between the HV and LV CTs.
– Check your protection scheme, it could be swapping of CT polarity
– Very good fault finding techniques.
Keep it up.
1). CT polarity shall be the ist check for differential.
2). For HV REF & LV REF, please check the connection integrity as explained above (relay shall be connected between 3 line CTs & one Neutral CT). There may be the wrong connection and wrong CT polarity.
– Have you checked Stability and Sensitivity for Differential and HV & KV REF?
– Please let us know what are your findings based on the above?
– to create a fault within the CT regions, if it trips – then differential & REF Protections are fine. Not only in the zone, but the scheme shall also be stable enough for out zone fault. Stability of scheme is also important
– TR differential could be connected by post-CT (Overall diff) or Bushing CT. Please check the scheme, if both operated, It’s an internal fault. I’m not a big fan of the IR tests, but simply this IR test sometimes can confirm it. Tan-delta could also be done.
– Yes, there is a Brushless system, where supply is given from the battery bank.
– Any self-protection operated?! If not, >90%chance of being external/false triggering. Can anyone explain that in one and a half breaker scheme each circuit of a double circuit transmission line is terminated in different diameters? Why?
– Please check REF for through fault (as it should not trip on external fault). REF should trip only during Faults only within the 3 Line CTs and one Neutral CT. It should not trip in external faults. Please check the relay settings.
It is surprising that transmission lines of different diameters. No clue. Please check. Since 2002, I am working overseas.
– Correct sir but back up trip to upstream bkr only
– But why Transformer Neutral Earth Fault (64 N) not as a backup for downstream incomers?
– Yes, I agree with you that always upstream HV breaker will trip ist to prevent the fault back up. Yes, you are correct
– Sir ref only protects the defined zone of both CT phase side and neutral. Back earth fault does not define any zone. It’s a percentage zone Earth fault protection of the transformer windings only.
– Yes backup fault does not define any zone.
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– How many limiters are used in the AVR system? Which first operated Avr limiters or protection system? Erath fault relay is always connected on the LV side of the Transformer?
– Yes, correct.
– Also REF is connected to the HV side?
– No star side of tx
– Yes We have an autotransformer whose HV side is Y type and a REF relay is installed on it
– REF is used to compare the Io current from HV Phase CT with REF CT on HV CT Neutral Transformer.
– Yes my friends, in DY Transformer, 50 N in Transformer LV side Neutral while Neutral is solidly earthed / Resistance Earthed. If it is Unearthed System like in FPSO and Drilling Vessel, then Benders Earth Fault detection is used.
If Earth Fault current is limited to a very low value, then CBCT operates Sensitive Protection is implemented.
– Is the above scheme of ct cck implements for tertiary Erath fault relay is correct For 600MVA autotransformer with tertiary busbar
– Wrong diagram. Double earthing is not allowed
– Can we use 3 CT for tertiary earth fault relay
– I have heard only two CTs are needed: RED AND YELLOW
– we call that protection as standby earth fault 51SBEF. A separate neutral earth fault relay will give back up to the entire downstream network. Whereas REF will operate only for in-zone fault. That is why it is known as “restricted earth fault” protection.
– There is no double earthing bro
– Right. your current must flow through the relay coil. you’re right.
– CTs are being summed in the MCC panel i.e star point
– Why do we use resistor and mitrosil in ref?
– Resistors are used so that REF does not trip during though fault current. Metrosils are used as Surge Suppression to add high impedance in Circuit to the proper operation of REF
– We are using Low Impedance Busbar Protection Relays. *How to detect the CT saturation in case of these low impedance relays*?
– My humble suggestion is: You may find the solution in that particular low impedance relay’s manual in the application or operation section, it is possible that they would have mentioned it in that section.
– I faced one issue on my site when I switch on the MCB’s Trip coil suddenly melted. I need to route the cause. can anyone tell me what are all the possibilities of trip coil damage?
– There is permanent DC to the coil either the wiring is not passed through normally open contact of the CB pilot switch or it’s from a wrong wiring
– How to find out these issues? May I share the scheme can you please assist me how to verify these conditions?
till not energized.
– I guess the wiring is wrong. U have connected CB NC to trip coil, it should be NO contact. So when the breaker is open, you Switched the MCB on, there was a (maybe) trip signal from anywhere, trip coil energized, but the CB is already open. It was energized until burned
– Yes you’re right. And what is the function of U1/205?
– Okay my suggestion is to swap the wire on the CB NO with the one on the CB NC?
– I believe it will solve the problem
– U1/205 is a TCS relay
– Yes sir but I verified no trip signal and there was no loop. So how trip signal go to the trip coil?
– Which means u1 – 18 should be in c5 and 23 should be in A3 am I right?
– saturation of current transformers (CTs) can lead to maloperation of protective relays. Using the waveshape differences between the distorted and undistorted sections of fault current, this paper introduces a novel method to quickly detect CT saturation. First, an asymmetrical variable-length window is defined for the current waveform. The least error squares technique is employed to process the current inside this window and make two estimations for the current samples exactly before and after the window. CT saturation can be identified based on the difference between these two estimations. The accurate performance of this method is independent of the CT parameters, such as CT remanence and its magnetization curve. Moreover, the proposed method is not influenced by the fault current characteristics, noise, etc., since it is based on the significant differences between the distorted and undistorted fault currents. Extensive simulation studies were performed using PSCAD/EMTDC software and the fast and reliable response of the proposed method for various conditions, including very fast and mild saturation events, was demonstrated.
– In the case of the 4 CT methods (1 No 5 Core CT in line, 2 Nos of 5 Core CT in tie, and 1 No of 5 Core CT in AT feeder). Now if I do not use the 4 CT method then a fault between CB and CT (End fault) may still then be fed from one side even when CB has been opened. Consequently, final fault clearing by cascaded tripping has to be accepted in this case. In this situation, LBB/BFR operates and the time taken to clear the fault is 300 mSec. This is a blind zone area.
When the fault takes place between the main CB, Tie CB & line isolator in-service condition distance scheme takes care, in addition, this TEED protection is not available. Now my doubt is about the blind zone area. I think the 4 CT method should cover all the line, tie, and AT CB blind zone areas but actually, it’s not. It covers only the tie CB blind zone area. Why? If presently I am constructing only a line and tie bay with AT bay in future. 4 CT method is adopted. Considering that AT bay is in the future so can I consider the 4th CT of tie bay in the future?
– End fault zone will be there if u don’t have a Tee zone(Whether it is local end/remote end). If u enable end fault protection, it’ll take less time(concerning BFP). Considering AT as a future bay, only two bus CTs could be used/enough to me.
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– in LINE DIFF There is an option for test mode or internal in the relay as I remember just see the line differential settings and you can find it there in
– Go to the testing Tab and then test mode. Below input-output, there is a testing tab
– I’m in the offline window. Maybe that is the reason. Later I will try to go online and see if I will have the test tab.
– Yes that might be the reason and you can make it Elesrwise take fiber with u just make loopback on the backside of the relay and you can test your diff with external mode on as per actual
– Fibre connects on the backside of the relay as a loop just like a wire jumper. One end of fiber on Rx and another end on Tx
– what is IPCT and what is the purpose of this IPCT?
– The IPCT is a High Sensitivity Current sensor operating as a “closed-loop” Direct Current Transducer (DCCT) operating with a flux-gate zero-flux detector.
– Actually on our site they installed IPCT to Main CT primary and they have given IPCT secondary to relay input. how will you test the Stability and Sensitivity Test for Line Differential relay at the Site? Is it the same way we test Transformer Differential?
– Are u talking about interposing CT? But it’s used in the secondary circuit of CT change/match CT ratio with references. we have these CT cores in the middle CB panel for metering purposes, can anyone explain the reason behind it?
– this is the schematic of installed CTs. Don’t we use interposing CTs for relays? I have never heard them used for metering purpose
– In the schematic given, these CTs are used for metering purpose
– We used to use Interposing CTs in earlier non-digital Relays for Transformer- Differential. Application- *It is used in the secondary circuit of CT connection in Star / Delta matching with other CT with references in case of various applications like transformer differential. * This interposing CTs is the very popular connection for Transformer differential.
– In motor feeders also sometimes they are using ICT. Can you explain why ICT is being used for motor feeders?
– Mostly used in Transformer differential, but also used for other purposes. I’ve seen it in busbar differential (static type), even in meter circuit, converting protection core to metering.
– but all our relays are digital. I think if you tell us the ICT’s spec and meter’s ampere rating, it will be easy to answer.
– Primary 1A, Secondary 1A, VA burden 0.4VA. These CTs are used for isolation purposes and are installed between CT secondary and Energy meter to protect our energy meter from any misshape in secondary cct, just like an optocoupler. Then maybe the CT VA was too high then a connected burden. Normally only for isolating purposes this type of scheme I’ve not seen. Rare than.
– Main CT burden is 30VA and isolating CT burden is 0.4VA. quite a difference
– No, I think it’s not like that. The ICT’s burden is 0.4VA.
– Yeah ICT burdeis 0.4VA. You have to measure the knee point voltage of that ICT. It should be lower.
– Lower than 0.4VA?
– Actually, the reason (to me) to use ICT is that the CT VA is too high than the connected VA(Maybe >10 times). So, although the FS <6, the meter may take up to 60times current. So ICT is used which has low knee point voltage. IEC
– Is it a bad thing if the connected energy meter burden is less than the main CT burden?
– To me, it’s not a big matter of concern. Nowadays meter can take 100A current for a while. And we have protection redundancy to trip quickly. It mean ICT is used to lower the VA burden so that the energy meter does not draw a high current?
– We have a 400kV bus reactor that has primary protection as differential, REF, O/C, and backup impedance protection. During switching the instantaneous backup impedance protection operates and causes trips. Can we add some intentional time delay in backup impedance protection? If yes how much?
– How much percentage does the backup impedance protection cover and how many stages?
– What is your earth-fault highest setting?
– Yes you can increase but may I know what is the previous setting?
– Back up impedance setting should not be beyond LBB tripping time delay. That should ensure kindly update here back up impedance which method adopted in protection relay?
– Voltage-controlled overcurrent?
– Why you are related to LBB?
– Reduce feeding fault cycle
– What about the LBB setting? it’s a little bit higher than the normal setting. But both protections are different
– Agree but you can not feed fault too long. Current setting is backup impedance is zone -1 50% instantaneous and zone -2 66% time delay 0.5 seconds. Its voltage-based OC.
– My question was can we give delay and how much? How many zones percentage backup impedance should cover and how many stages, But you here mentioned zone setting. Which one is correct?
– Current setting I meant present setting
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– How to test power swing manually.?
– What relay test device do you use?
– My relay is blocking on both 2nd and 5th harmonics simultaneously. Megger smrt46d. Setting for 5th harmonics is 35%
– In EMCO AVR relay at the parallel of PT supply component used which is burnt is capacitor or resistor
– How to do hipot test for HT cable?
– Please adopt the VLF test, which is a non-destructive test. hipot is not approved, as it is a destructive test.
– IEEE 400.2 FOR VLF at of 0.1 Hz frequency. Deff b/w hipot and VLF test. Hipot pure Dc test and VLF ac test with 0.1Hz frequency
– But we use also hipot for ac cable
– I said hipot is Dc supply. the cable can be ac or dc
– How much voltage percentage was applied for ac cable test?
– Why do we use two phases short in hipot test?
– For hipot 2 x rated voltage. For VLF 1.1 x rated voltage
– As per normal HV test
– when hipot & VLF tests are conducted?
– For manufacturing hipot and for diagnostic purposes VLF test was conducted.
– numerical relay also have blocking future when if relay detect 2nd harmonics & 5th harmonics current
– Normally set 20% 2nd & 5th harmonics. It may be set depending on tx When you energize a transformer there is current in the primary winding and No current in the secondary winding
Hence there is always a differential current present. But relay has to differentiate between inrush & internal fault. i.e done by so many methods. But the generally accepted method is the I2/I1 Ratio of second harmonic & fundamental current. If greater than 20 percent. then it’s an inrush. Also, active power consumed during inrush is very very small as compared during internal fault.
– Yes, more precisely if I2/I1 (I.e . ratio of second harmonic and fundamental current) is more than some percentage, then it’s a magnetic inrush. The limit of magnetic inrush depends on the transformer core design and it’s another big subject. Offsets for magnetic inrush, Tap-changing, CT error – it’s experimented that if we make an offset with 20 percent, then it’s quite pragmatic.
– Transformer flux density and physical design of the core & windings determine the limit of magnetic inrush. Apart from that On what value of voltage wave the breaker is closed is more predominant towards magnetic inrush.
At zero it’s high & at the peak it’s low.
-It also depends upon the instant of switching/energization transformer. If transformer switching is done on a negative or positive maximum voltage wave then inrush will be minimum. If the transformer is switched when the voltage wave crosses zero then the inrush will be maximum. A controlled switching device can be used to ensure this.
– But how you will help with control switching in the 33 kV system since all breaker pole close in tandem? is not possible?
– At the site, even trained operation guys shall never bother to carry out the control switching. Hence, this is more theoretical rather than being pragmatic, I may be wrong.
– It’s practical on 400 kV I personally worked on it. It’s also called point on wave switching.
– Yes we have used PoW or CSD (you can call both names) for 765 & 400 kV.
– See above L1, L2, L3 these are the transformer phases R, Y, B coming for the phase measurement for LCC. So these are used to measure the current of these L1, L2, L3. B061+S01 breaker and LCC combined
– These highlighted CTs are for isolation purposes. To protect the energy meters from any mishap in CT secondary ckt. Figure out first X611.1 have any connection further update the drawing check this point. If there is not any joint it means these Cats are just for measurement of L1L2L3
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– I am testing the 5th harmonic restraint feature of the differential relay But my relay is also picking on the 2nd harmonics restraint and 5th harmonics restraints simultaneously. What could be the reason? My 5th harmonic is 35%
– Is there any standard for modeling LV motors of the least size? Or up to what minimum rating of the motor do we need to consider for modeling in power system software?
– Micom P34x or sepam G87 or P3GXX From p343 you have differential
IEC 61850, 1:09 XX: http://www.ucaiug.org/Meetings/CIGRE_2014/USB%20Promo%20Content/TOSHIBA/Brochures/GR200_Series_IED/GRZ200%20brochure_12032-0.B.pdf
– Z1X shall be a zone-1 extension.
– It control zone accelerated this particular zone we have set POTT or PUTT to be set. Depending upon line length we set POTT or PUTT. This is an accelerated control zone depending on line length.
– If the line length is the very shortest line we can not get 80 % zone -1 in this case POTT scheme to be adopted. Permissible overreach transfer trip. this is an MHO characteristic. Nowadays using quadrilateral characteristics used in distance protection
– what are the interpretations of six zones ( included accelerated tripping )?
– Normally used 4 independent zones and one control used. it may be varying different country In the 4 zones, 3 zones set forward, One zone is the reverse zone. Zone -1 and zone -1X you can enable auto reclosure.
– Z1XS extended depends on teleprotection
– Anyone knows about the difference between cid, iid, icd, file type? Why we are using this type of file format?
– Icd is a much common form of sharing communication details of any IED, i.e you can use them for any product IEDs for any SCADA integration. Whereas CID, iid is relatively specific
– what are the major protection of alternators from a generation point of view?
– Reverse power, Under frequency, Over frequency
– 1). 51 V (voltage restraint over current).
2). 81 U & 81 O ( under frequency & over frequency)
3). 78 ( pole slipping ) – depending on the ratings.
4). 32 – Reverse Power.
5). Inadvertent Energisation
6). 51 O/C
7). Under-voltage and over-voltage
8). Rotor Diode failure relay
9). 💯 percent Stator Earth Fault relay
10). Restricted Earth fault
11). Generator differential. All are from my memory.
Might have missed some of the elements. Note – some of the protection elements are applicable only depending on the generator rating.
– 100% stator earth fault normally used two methods 1) smaller machine 3rd harmonics under-voltage method used 2) Larger machine 20hz injection principle used
– on which what things should I focus in generating station? as I am working in the sugar industry?
– I think 51 V voltage restraint over current Generator directly synchronous with grid-like captive plant 51V is used Where the generator connected through power transformer backup impedance protection will be selected.
– Big machines nowadays use low forward power protection methods used.
– You should focus on the following point in the generator regularly 1) Generator shaft voltage measurement Monthly 2) Regularly check carbon brush 3) Rotor earth fault value show in relay 4) If brushless exciter you should check diode fuse healthiness 5)weather AVR all channel in follow up mode or not. and firing control voltage should be equal 6) AVR thyristor monitoring system 7) generator should be operated in as per capability curve.
– where is generator neutral solid earthing 100% stator earth fault not required? If generator neutral connected through resistance or NGT 100% stator earth fault is required. In Avr all limiter in service or not it is very important to point. The generator shall have high impedance grounding to protect stator lamination. If generator neutral earthing through high impedance fault current will limit. such case from the generator neutral 5% unprotected zone bez fault current limited by high impedance earthing. In this case, we should adopt the 20HZ injection principle used. In this case, the differential will not respond.
– normally before over fluxing Protection Operated In generator, V/HZ limiter will operate and keep the V/HZ ratio within limited. Ensure that PSS should be in service it is most important in AVR.
– Power system stabilizer
– Normally even a 30 -50 MW sized Generator was recommended for high impedance grounding to save the potential damage on stator lamination. This was as advised by Generator manufacturers (like ABB, Siemens, Rolls Royce, etc.).
In that case, the differential will not operate on this small current. We used 67 /67N – directional elements to find the faults while the generator switchgear bus-coupler is closed. Yes, in this case, we used to use an injection of the 20 Hz principle to identify the earth fault current.
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– we have siemens 7VH60 relay and its trip setting is 240V while we are supplying CTs to the relay
– https://electrical-engineering-portal.com/busbar-protection-schemes-principles Please refer to the high impedance principle – why the set is in terms of voltage?
– Voltage across the relay matters while CTs get saturated under fault conditions. Hence, CTS knee point voltage shall be more than twice the voltage across the Relays.
– CT switching is required to know which isolator is connected to the circuit in the double bus bar system.
– CT switching is also required to ensure the correct bus bar sections are taken into account (while bus bar sectionlisers are involved).
– I have tested high impedance ABB relay, and I have applied voltages to the relays to test its tripping setting. I understand if I apply current through relay resistors and there will be a voltage drop across the series resistors and the relay will trip according to the setting but during testing, I have applied voltage directly to the relay. why?
– maybe its the same thing, whether I apply current to generate required voltage or apply directly voltage to generate circulating current
– I have seen some schemes where the generator connected with through transformer back up impedance protection relay is used. A generator connected directly with the grid without any step-up transformer voltage restraint over current given.
– Pls share IEC codes of practice while working in substations and if step down transformer is used through the bus bar then which rely on is used?
– Generator never connected with a step-down transformer?
– no I’m saying that when the transformer connected with the bus bar
– always use a stepdown transformer when connected to the bus bar. right?
– at my site generator is connected to the bus bar then a step-down transformer is used through the bus bar. now in this condition which relay is used, Your configuration is non – standard in engineering.
The generator is always connected with GSU (Generator Step Up) Transformer – as per standard practices in all power generating plants.
– It seems that the generator capacity is of few MWs, The generator is connected to the HT panel or we can call it a Generator switchboard. And then outgoing Feeder is connected to step down Transformer to cater to plant auxiliaries.
– yes our Generator capacity is 2×6MW
– Yes, this is the typical configuration in offshore oil & gas platforms and FPSO. However, even in that case, Voltage Restraint Relays must be implemented as part of multifunction generator protection relays.
– I have never seen some relay (called back up impedance) replacing Voltage Restraint Relay. I mean Voltage Restraint Over Current Relays.
– What are all the protections, do you have in that relay?
– which type of relay is used in that type of power system for transformer protection?
– Does your query related to generator protection or transformer protection?
– transformer protection
– For the transformer, we need not have 51V protection.
– Where oltc is there, we don’t need but rest we need it For 5 MVA & above, We should have followed.
1). 50/51 – Idmt oc with high set
4). Standby Earth Fault. Over fluxing for very high rated transformers
– we have up to 2.5MVA transformers Plus Mechanical protection ( Bucholtz, Oil Temperature & Winding temperature high alarm & trip, OlTC surge, etc).
– if we don’t use the Bucholtz relay, will it impact the transformer?
– Yes, Buccholtz relay is required for all oil transformers ( not for sealed transformers ).
– Can we refill the oil for sealed transformer insite
– No / only by the manufacturer.
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– can you suggest anyone for the above doubt?
– Whether J17and J18 default for Modbus.That will be for plants auxiliary load, etc
– We are getting a 64R error fault in Micom P391. any anyone has an idea about solving this and does anyone have commissioning steps and what should We pay attention to this?
– Check all 03 CTs – polarity in phase sides for 3 phases. Check CT polarity on the neutral side. This the ist step.
3). Then check relay healthiness status.
4). Carry CT primary injection to verify the CT ratios
5). Carry out CT secondary injections.
6). Carry out stability check
7). Carry out sensitivity check
– But when u change parameters, reactive compensation devices, etc will crash. Secondly, it’ll also have some missing modules like Nova for eigenvalue analysis, etc. We are getting this 64R error in P391
– Sorry, I thought that 64R you are asking for Restricted Earth Fault fior Transformers
– No this will go with P34x
– 25 V, 0.25HZ or 0.5 HZ, or 1Hz injection module. We need to solve this and what may be the issue for this and do you have a commissioning procedure for this, and what should we pay attention to to avoid this?
– Square waveform
– What type of excitation you are using this relay?
– As I understood that relay HMI Shows only this error. I am coordinating remotely
– this is under-voltage protection Not rotor earth fault
– Are you talking error or relay?
– If it is a relay, I am sure that P391 used here for rotor EF
– As understood that this is due to rotor primary resistance from CLIO connected to P391
– What is backup protection to rotor earth fault in the generator?
– Current loop input
– It depends upon fault when rotor winding gets open. The machine will be tripped Filed failure protection normally in the rotor first earth fault allowable. if a second earth fault occurred the machine will get high vibration due to Equal EMF in the rotor winding result turbine tripped high vibration and following GCB open low forward power or reverse power. Rotor earth fault and vibration both occurred simultaneously
– xc = 1/2πfc. Frequency reduced increase XC value
– Yes, low frequency gives higher impedance, hence low current and low loss in this system. For relay measure better resistance value we go for subharmonics injection method used for 100% stator earth fault relay
– 20HZ used for 100% stator earth fault 25V (0.25HZ , 0.5HZ,1 HZ) square wave form used for rotor earth fault protection
– what is the 20hz principle pls define
– For generator 100% stator earth fault protection 20HZ injection method used.
-But 20Hz. Is there any specific reason to apply a 20Hz frequency?
– Better relay measures high impedance value. in this condition, capacitive reactance increased
– Relay can not measure capacitance?
– This is a simple formula for why the 20hz injection method used for the protection
– If the angle between two voltage sources of the same amplitude says 50V, are connected. How will phase angles of 0,180, or 90 degrees between them affect the resultant voltage?
– To put it simply, I want to generate 300V ph-ph from my test set using two voltage channels, for relay testing. When I put the angle of 1 voltage channel 0 degrees and another channel angle 180 degrees, then I get the addition of two voltage channels
– use the surge cycle test or RSO graph method to find the actual rotor earth faults. This will not give the correct location but will be confirmed that there is an earth fault
– RSO offline test when Generator running condition RSO test could not be applied, Rotor earth fault protection relay when generator running condition any rotor earth fault occurred it will shut down the unit.
– What are the avg load of 1bhk and 2 bhk flats?
– RSO is a testing part, 64R is relay protection, Both are different.
– Which Method finds locations of fault?
– How to calculate Earthing conductor size for a particular Switchgear?
– If the fault is in the retaining ring area near the Current carrying Bolt we can identify it with help of a boroscope inspection
– Recently one of the 600MW machine rotor winding opened in j star area near C. C Bolt.
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– why differential relay does not work properly in high impedance grounding?
– Reason – Earth fault Current is limited by high impedance resistance to a very low value, for which differential relay does not have enough sensitivity to operate.
– we use phase-phase VTs for Line overvoltage relays or phase-ground VT?
– Phase to ground VTs.
– and what is 59N – Neutral overvoltage protection also Negative seq Over-voltage 47 and Positive seq Under-voltage 27D protection? where they are used? I have never seen these two relays in the HV Transmission line
– I know OR is for Enabling a feature but in the setting we have OR, AND, NOT.
– In the high resistance power system, the detection of fault current becomes very difficult due to the low magnitude of the current. Hence a 59N is used to identify earth fault. During normal conditions, the Vector sum of phase voltages is zero. During a fault, these voltages across NGR is not zero and this voltage shows an earth fault in the network
– can you tell me where this type of relay is mostly used?
– I have never seen our HV transmission line protection system Used in a distribution system Not in EHV.
Also in generator protection & Motor protection. It was DGR Relay ( Directional Ground Fault Relay). It uses voltage pick up and (current pick up with appropriate swap angle) Also for Switchgear while the bus coupler is closed, then the incomer connected to the faulty cable is isolated rather than the other healthy incomer. This is based on the current direction towards fault feeding.
– All these are perfect examples of directional earth fault relays.
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– Anyone suggest which type of Paint needs to do inside the 11, KV HT panel wall?
– It is a Varistor
– What is the Single-phase pickup factor for the ABB RET670 Differential relay?
– 1.5 for start winding.
– can u tell me what’s the use of it? I have tested my relay using 1.5 PU factor on both HV and LV sides and the results were okay but I don’t know why we use it?
– I think single phase pickup value 1.5 will be multiplied
– what’s meant by PU?
– If it is in relay then it’s pick up the value
– Why do we have a timer in transformer overflux protection? And how its works? And how it affects the trip time?
– I have seen testing of overflux relay today. Every time the overflux relay was tripped during testing, we have to manually reset the timer. It works based on the V/f ratio. As we know the flux in the core is proportional to that ratio but we need some time to avoid mal-operation in cases of temporary over volts or under freqs.
– which soft signal need to use for THD inside Cid file in the Micom P142 relay? And which signal needs to use for setting group change? I can see this control output and where I can find virtual signal?
– Yes, v/ f is proportional to flux for any magnetic cores. If frequency declines beyond a certain value, or voltage increase beyond a certain value, the flux will be saturated And as well Saturating the transformer cores, while the magnetic core will follow the BH curve beyond knee point values.
– Transformer manufacturers can tell you how much time you can allow this saturation.
– due to my cerebral insufficiency, I am not being able to recall a lot of things.
– I think when the transformer overexcites then its core gets heated due to eddy losses And the overflux relay acts as a thermal overload relay. The timer is something related to cooling time after overexcitation But the Buchholz relay is not. operate.
– No… Bucholz relay operates on winding short circuits and severe internal faults. The transformer core does get too hot instantaneously floating firm ground or harmonicas. That’s why we install an overflux relay to protect the transformer core From getting saturated and heated.
– How to protect the overflux relay of the cubical box?
– for this type of occurrence you need to enable 59G. Transformer rating we use 2MVA
– Its fault comes to when we start to reconnect the line from the grid side.
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– Can you please see if directional overcurrent is operating during this event in the fault recorder?
– Can you share SLD, and spec’s? three-wire diagram and protection also.
– I’ve heard of this type of overvoltage. This may be the problem. But need detailed analysis to confirm.
– To resolve share SLD & transformer details & VT specs. I have resolved many such issues in the 33kV system.
– how to calculate impedance voltage % of 2500kv transformer?
– Today CT blast in the cubical box Before two days or blast. Please suggest to me can we use any protection equipment?
– Check the possibility of secondary open
– Percentage Impedance = (Transformer Rated MVA / Fault MVA). Find out the system fault MVA from the drawings/documents. Consider infinite bus only.
– Overvoltage protection is required. The voltage appearing across the CT during the fault condition needs to be calculated.
– Have you checked CT secondary is always shorted through some gravity-type shorting mechanisms.
CT blasting shows 1). Either CT secondary got open circuited
2). Or, Dangerous overvoltage has arisen across CT secondary during a fault condition. You need to calculate this voltage across CT through Knee point voltage.
– Have you taken out any relays/meters from CT secondary?
– if fault MVA is not found. Any thumb rule for Considering Tendering and estimation purposes.
– How can we check time synchronization has been done through SNTP in reyrolle siemens (7SR11) relay?
Is there any specific signal for confirming time synchronization done?
– Consider LV fault Current as 50 kA and then calculate Fault MVA. Time synchronization is through GSM antenna and then protection system & event recorder time stamping. Time synchronization has been done like Siprotec devices” clock synchronization”
– Rio file is possible in Kocos Arts 440?
– Then it should be fine. The Thumb rule for LV system fault level is to be considered as 50 kA. From there you can calculate the percentage of Impedance. It will be approximately around 6% for a 2.5 / 2 MVA transformer. If I am wrong, please correct me. That’s enough for tendering purposes. Or for the worst-case LV system fault level can be assumed as 65kA.
– I think you are asking to calculate fault level impedance when the rated voltage applied in TX such conditions 3 phase short circuit occurred we find fault impedance.
– Normally At the site, the level confirms the % impedance test like this way
– How to upgrade the firmware version of Siemens 7SA522 from V4. 2 to V4. 3?
– plz install the firmware loader of Siemens and then download the firmware file from Siemens website for version 4.3 and loader upload as per instruction but also note in some Siemens relay when u upload firmware the relay gives u error so u need to initialize the relay and have to create the relay file as per project-specific but some Siemens relay does not need that.
– Can anyone help me with the password of REBCON? Thanks in advance.
– Please try: System
– pls guide that on how to identify the type of NGR?
– It’s good to tell them when there are such issues. It helps them to improve and give us better products. It’s relay malfunction or settings error
– During testing this distance showing?
– Phase to phase fault dist is ok, Problem is with phase to earth fault. Did you trace the fault? The reason behind this issue
– Maybe not properly configure mutual compensation
– Can you share the PCM config picture as well as the fault locator setting?
– Fault locator settings shall be the prime criterion to find out the line to group fault, which is more frequent faults than any other type of fault. I think the issue is with logic signals. setting parameters are ok
– I’m going to initialize 7SJ85 but its firmware version is different. how to update Relay’s firmware so I can initiate with the newer configuration
– Which firmware was your relay?
– My relay has 8.03 and my software configuration have 8.30
– What is p2cc gsm module communications?
– In the relay, they give def setting and its Operation time is 0-30 Now if I select 30 as an operation time
And for over current, my setting is 78A at 5 sec.
– So when the relay will the trip be?
– Relay shall trip while motor load current arrives at 78 Amps for 5 seconds. (0-30 sec is the range).
– Because I have selected 5 sec TMS and also in a def setting I select 30 for operation time of DFT
– What is the difference between these 2?
– TMS – 5 sec is the relay operation time for the maximum load current, Then also select 30 in def operation time. What was that?
– That’s the maximum range available
– What’s the rating of the motor?
– Flc 82 Oc setting is 78A
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– Can we make custom virtual inputs and outputs signal in Micom PSL? Let’s say I want to configure a signal on LED which is not available in the virtual outputs directory. I want to configure the binary input signal of Auto recloser initiation from Distance Relay to a LED
– Just to know if dist relay has sent initiation signal to auto recloser or not
– I think I can map binary input signal directly to the led
– What’s the good reason behind the setting of 78 Amps?
– Overload setting shall be set into a minimum of 110 percent to 125 percent over motor full load current.
PSM & TSM need to be calculated separately properly to evaluate the correct setting of Current and Time.
– Actually, I want to change the CT ratio. I tried through HMI. I can install software but I can’t communicate from setup and extra. What I have to do. I tried but it shows cant be changed. From SIOS only
– but you need to change at two places which are only possible through software
– Go to setting menu >>setup and extra>>MLFB version There you can find firmware and p set version. This could be found on relay display only for in your PC plz open DIGSI create a folder>>right click anywhere on window>> the first option is device catalog, select it then go to open popup here u can able to see all relay modal select the corresponding model and check whether the required p set version installs or not.
– Relay is not showing the fault in HMI for that what I have to do
– have to configure the LEDs in the matrix
– Anyone knows how to configure no start for hot and cold in the Easergy P3M30 Schneider relay?
– Yes I know the site to reach to get the manual. As per the above setting, direct hot or cold assignment is not available same as Micom
– Can anyone suggest it is possible to set these cold and hot numbers in P3M30?
– Cold star 2, Hot star 1 is allowable its thumb rule. Kindly refer motor manufacture datasheet.
– Please help me what is DLMs means
– Dlms used in Special energy Meter one-type file system. Device language message specification
– How does the TCS relay monitor the healthiness of the Trip circuit? is it monitor the negative supply by using NO and NC contacts when CB is open or closed?
– Yes, through circuit breaker both contacts (NO and NC contacts). TCS – trio coil supervision is a very important feature of monitoring trip coil healthiness.
– Can we operate the breaker mechanism if its coupler is not attached to the CB ploe plunger?
– Our 600MVA transformer tripped on energization on tertiary earth fault relay… There is a 2000A current in neutral
– There is no fault with the transformer. Everything is ok. Soon after performing various transformer tests when we try to energize it trips
– Tertiary is delta? Primary 400 kV? 400/220/33 kV xmer?
– 500/220/23kV. Yes tertiary is delta
– We don’t have a switch synch relay for our transformer
– I think it’s due to core Magnetization because of applying dc voltages to the tx winding during the winding resistance test. Need to be grounded on each phase to make sure that there is no high remanence DC current.
– CT should not be energized until and unless there is an external fault already existing.
Let us know I2/I1 ratio?
– Saturation takes place due to the DC component of the through fault current.
– This was due to inrush current at the time of energization of Transformer
– How to test rotor Earth fault protection?
– Second-harmonic restraint should minimize Magnetic inrush? Is it not?
If I am wrong, correct me?
– No it’s not like that. 2nd harmonics produced during inrush current for Magnetization of core
– When we energize TF there is a heavy inrush current to magnetize tf core
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– I want to know how to do it practically on 3 winding TF?
– We have tested 600MVA TF Blue phase, if we try to energize it after testing, the tertiary earth fault relay trips on high neutral current
– 3000 amperes current from tertiary neutral
– If we try to energize 2nd time after tripping then there is no issue
– How could the 3kA be in TF tertiary neutral?
– I know that’s due to residual magnetism (which can be minimized by proper design of the transformer core).
– Then why do we use the second harmonic restraint feature in transformer multifunction relays? What’s the good reason for using this feature?
– Inrush current flows during energization, And 2nd harmonics is also produced along with normal current
– How to calculate single phase pickup for trafo differential? Relay Manufacture and type of TX configuration required
-What is the legend of K M E?
-M- means mechanical interlock, E- means electrical interlock, K- means Key Exchange Box interlock. For example and simplify, When Q9 Opens position, there have Electric Interlock. When Q1 closed position, there have Electric Interlock.
When 57BBA Open position, there has a mechanical interlock. Have to unlock it to switch the position.
– 1). This is an interlock between the line disconnector and the line circuit breaker.
This Disconnector can be closed only while CB is open and can be opened only while CB is closed.
These disconnectors are the three-position switches.
2). Moreover, Q51, Q52, Q6 & Q8 are the earthing switches.
If these are closed, you can not close the CB.
– Can anyone explain what is the purpose of the start point other than directionality? And why mostly star point is made on the S2 core of CT
– S2 means secondary core phase sequence R-B-Y so Y is the second therefore star point made on the second core of CT. The purpose of the star is to distribute the supply to another consumer for this reason neutral is also used for grounding. for safety purposes, the neutral is grounded
– Yeah it’s the prime reason but we can’t distribute supply in the delta to the consumers
– Where do we use stars without ground?
– Guys, Please tell me about Synchro-Check (25) relay. How to synchronize two incomers & one bus coupler voltage? Please tell me the settings of the Synchro-Check relay (25).
– For HSAR, disturbance time smaller than 50 ms and distance or feeder differential, fault clearance time smaller than 100 ms. For typical HSAR dead time bw 0.3 to 0.5 sec. Caution: when a specific feeder opens after fault clearance keeps the feeder open. This is DAR; Delayed Autoreclosing. Typical 11/33 kV 1st dead time= 5-10 sec.
2nd dead time= 30 sec.3rd dead time= 60-180 secn 4th dead time = 1 to 30 mins.
– what is HSAR?
– High-speed auto reclosing of feeder for Preventing loss of synchronism is High-Speed Auto Reclosing of the feeder.
– Please tell me the Deadtime of 33/6.6kV?
The formula for dead time: T = 10.5 + kV / 34.5 cycles
– How to test cross blocking in ret670 relay? What is cross blocking concept? And how ret 670 relays calculate diff and bias current for the differential?
– Harmonic cross blocking is whereby whenever the relay detects harmonics in any of the phases differential protection is blocked for all the phases including the phases where harmonics had not been detected.
– What is a cross-trip scheme?
– As I understand that it is an inter-trip scheme (transfer trip scheme). Normally, for VFDs, where harmonics are kept within 5 percent, even then differential protections are not provided for isolation transformers and MV motors.
– It’s a No Voltage device and used for interlocking of shunt reactor. I don’t know how its work
– For closing the line earth switch h the under voltage relay is used… In interlocking circuit
– To open Or close the line earth switch the line voltage should be less than 15percent of the nominal value. This is to ensure that the line is not closed Or opened in the live condition. This is to ensure that the line earth switch is not opened Or deleted in the live condition
– You mean if line voltage or greater than 15 percent then under voltage relay will prevent the operation of earth switch. Right.?
– If it’s less than 80% rated voltage then it’s the dead bus. From Live bus to Deadline charging is also possible by bypassing Check- Sych relays.
– How to bypass breaker?
– You need to bypass the interlock, but this shall be reinstated asap. As isolator is a no-load switching-device
– BCU is built up of two-part two parts 1). Mosaic Tiles with Hardware Mimimic 2). Control (with Discrepancy Switches) and Feeder Protection Relays.
Please refer to the ABB & Siemens websites for EHV BCU details, control, and Relay details along with BCU layouts. Please study the schematic drawings of vendors thoroughly, and then you will understand.
– Anyone knows the manufacturer of split-core (Slip-over) type CBCT?
– Please arrive at the point of the BH curve where current increases by 50 percent for voltage increment of only 10 percent, that’s the knee point, And then find out CT saturation. Increase the voltage and current up to the knee point and then follow the process as above. R-Y =15 M ohms Y-B = 14 M ohms B-R = 10 M ohms R-E= 8 M ohms Y-E = 10 M ohms B-E= 10 M ohms, 11kv ABC conductor
– I need a recovery password for the p441 agile relay. Can you help me?
– I’ve tried it but not working.
– I’ve read a security code on the relay and I need a new recovery password.
– Security code is generated for 72 hours.
– Can anyone give me a recovery password from GE company based on the security code?
– If you forget the password you need to contact customer care to get the recovery password with device details with security code
– No one can generate PW outside
– Ge company has banned my location.
– You need to contact local GE
– Do u have any standards related to Power transformer winding resistance measurement or complete testing standard
– How to come on the main display.
– Enter arrow keys, select clear and enter. Not clear after these steps
– This indicates a healthy circuit.
– You have a problem in the trip circuit, not in a relay. If this led has turned off already. How to test broken conductors in abb relays?
– Setting is above
– Is it possible to access the Data of micom relays through the FTP method or IP address the same as Easergy P3 relays?
– Yes through IP address. I mean that same like web browser concept. Can you explain the procedure did before
– As per my understanding, it is not possible to access only with IP address to access the relay data
– Just go to Micom S1Agile software and connect ur relay by entering the IP address of ur relay. I.e 126.96.36.199
– Just to explain, P3 relays if you know the IP address, you can access the entire relay parameter. you can do it through the HMI facility in the relay if available and for that, u need a router at ss.