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protection relay 2 Discussion

– During one phase PT failure, will overflux relay work? Has anyone seen this kind of voltage transformer connection?
– Why b phase winding is grounded on the secondary side?
– Can u share nameplate details of the PT
– yes, in an oil company, usually they only use 2 PT inputs and make it as delta connection in the relay
– That’s an open delta voltage transformer or potential transformer.
– It’s mainly used as an input to detect earth faults using neutral voltage displacement.
– Typically the sum of the voltage across D7 and D9 is zero. however should there be an earth fault and one of the phases hit the ground … you will get voltage across the open point
– Such schemes are used in ungrounded systems or on generator – transformer sets. there is no path for earth fault
– Sorry open wye but the scheme is the same.
– Open delta connection, Yellow phase normally will ground. But as per the drawing seen some conflict.
Normally 2 VT Winding we can see.

– This is a star connection with y phase grounded Not an open delta. I was reading on the internet it’s some old practice followed in the UK.

– Anyone has any experience with diesel Genset paralleling on the common neutral resistor? How many generators can work connected to the resistor and how many can work isolated in parallel mode? That’s a very big open question.
– Yes, it is really problematic to solve its protection system
– Yes we typically run the neutrals to a common neutral bar. Install at least 3 the neutral earthing resistors and contactors
– Are you talking about medium voltage generators?
– Yeah.
– How did you calculate the size of resistors
– Please, can you share some calculations?
– I need a setting guide for directional protection
– If any example for Double feed SubStation with the tiebreaker normally closed
– What is the Apts scheme?

– For this system, with the two Transformers secondary breakers and the tiebreaker are normally closed, and installing directional on the two secondaries, I need some guidance on how to make the setting for the directional, And if anyone has a similar case I will be glad if he shares his settings and how to Make them?
– the intention of the Directional on the secondary side is for backup protection? I ever encounter an application that uses the secondary side 67 as a backup by looking up into the transformer and if it operates it will trip both HV and LV. – Can anybody share about the zig-zag transformer? Principle operation of it.

– Anyone has SR 469, SR 650, and SR 750 test formats? Which is the software used for these relays? Anyone pls help.

– what could be the cause of the SF alarm?
– PLC is communicating with another PLC over Profibus
– Well, it can be a lot of stuff, but the first thing I always have for this alarm. SISTEM FAULT means that you may have some unit programmed inside your PLC that is not connected in the field.
– So if it still works let it be
– with that alarm all parameters of slave address become red
– This is not something to concern, just be sure you have a good backup of the PLC program. but if it remains, it will not let startup of Engine
– Yes, but if it is already working, maybe is only a module programmed in the PLC but not connected in the field, but I say, I saw processes going on for Years with this SF, and nothing ever happened.

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– we have a problem in the Genetaror Micom P343 that does not boot, please help us how to fix it, thanks
– Check the ribbon resistance of HMI to relay. We have faced the same and ask Alstom then after they checked and replace the ribbon, and fix the issue.
– Where is the ribbon?
– Open the front side of the relay then there is a connecting ribbon cable u can find
– This, not Bad contact Ribbon the message is clear (Micom Booting) with Led Alarm lightning in red Fast…
It’s like PC booting, I think it’s a microprocessor issue
– We have faced the same problem in our reliance industries Jamnagar plant and Alstom itself give us a solution and change all the ribbons. Micom rebooting issue may be from the HMI problem/relay power card problem but if it comes even after replacing HMI look forward with manufacturers. It’s not just like pc booting issues. There is no chance of error in relay or bugs like a microprocessor.
– I might be wrong but I share what I experienced with the same problem.
– Any vacancy for Facilities Manager
– How do I determine distance characteristics in the L90 GE relay? do someone has a commissioning manual for L90 relays?

– I want to know what you guys as an Electrical Department are doing to fight COVID 19 in their workplace.
– 132kv circuit tripped showing R Y B phase and zone 1. And the same circuit is energized from another end at no load. Also, no fault was found on the circuit during patrolling. What will be the fault? Distance Relay type Micom P 441. It could be transient or pic up fault
– Does it show any distance in zone 1?
– Grid staff is not too efficient to check the fault recorder. I will go to check it tomorrow and will discuss it again
– What is the status now does the line charged from both ends?
– Only from another end at no load
– Sir but usually these transients will be blocked by numerical relays rights
– I think it may be DC grounding
– Check the fault recorded to see the fault current and voltage
– Lighting
– Depending on the magnitude and relay Makes. We have had similar invent without any trace to a physical cause
-can you share with us the Comtrade file

– What is the standard setting of the characteristic angle for directional overcurrent phase and ground (67/67N)?
– does somebody has this relay technical manual ABB PCD for recloser?

– Hi anyone has a static VAR compensator (SVC) protection scheme that can share?
– What is the standard setting of the characteristic angle for directional overcurrent phase and ground (67/67N)?
– For typical distribution networks (up to 33 kV), I set it to 30 degrees. For sub-transmission/transmission, I set it to 45 degrees, between the current phase and voltage polarizing quantity.
– However different scenarios may require different angles and have to be worked out.
– This angle for directional phase overcurrent? What about the angle for directional ground overcurrent 67N?
– Are there any references for how to Make the setting for directional phase and ground overcurrent 67/67N?
– I would typically read the relay manual, And use the default recommended value. The actual math behind setting them can be very tricky.
– Which relay are you using?
– Sepam s40
– The application is two parallel Transformers
– What’s the voltage level and how far is the relay from the supply transformer?
– From experience, RCA is 20~40
– For 67N, the value is dependent on the type of grounding. Please refer to NPAG, it was clearly explained there
– Anyone has a digsi4 Activation Key? And for 67, if I am not mistaken, RCA is set based on the impedance angle of the system

– Anyone tested Transformer DIFFERENTIAL 7SR242 DUOBIAS. I have some doubt on bias characteristics!
– This is the complete manual, but the bias equation is not clear on it!
– Does anyone here got any information about ct accuracy class 0.1 PL 270 R6
– I want to know knee point voltage and resistance


– Install Studio Enterprise this is a combination of all SCADA & it will work as per your licensing

-Does anybody here has experience with Toshiba relay GRL 200?
– I want to ask about the IO config
– Why don’t you Let the admin look into it? Please send me any study material regarding AVR
– For a substation
– Little emergency for my undergraduate project
– I can send you the datasheet of Engine AVR
– ABB Unitrol 1000

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– I have to change CT/VT ratio in an Elster A1800 energy meter. Already got established communication with the meter via Metercat 3.5 software. I believe CT/VT ratios can be changed via function “Program” but I am not able to proceed as everything at the “Program” popup window is grey (not editable), I request you to support me in changing the CT/VT ratios.
– You have to enable changing xt ratio on parameters function

– There is no Parameter menu in Functions? please clarify in detail or send some snapshot
– Hi Guys, I have a question for the 220KV level, which is suitable for either CVT or IVT(PT)? And why Usually we are adopting IVT(PT) in Andhra Pradesh India
– CVT always
– Sir can you please support your statement As we have observed the drift in secondary voltages are more in CVT compared to IVT over a time span
– Mainly installation reasons. they are lighter, cheaper, Safer (transfer of emf when a fault occurs)as there is no direct connection to the primary voltage source.
– Can you explain how does the voltage drift?
– Deterioration in the capacitance levels over a period of operations results in variations in secondary voltages Can’t that be fixed during maintenance? (Note: I don’t have any experience in maintenance and operation Even I don’t have any experience in Maintenance. But I am not sure we can improve this ineffective manner)
– CVT for transmission circuits or High Voltage i.e greater than 66kV and IVT for distribution circuits 33kV and below
– Moreover, we are mostly using IVT in 220KV levels also so, I am not aware of fixing methods. I believe it’s a cost trade-off. In India IVTs in 220kV class are more affordable than CVT. And yet you may see them actively used in 220kV stations where the transmission system is at 220kV level. This is because the same CVT would be used as a coupling capacitor for PLCC communications as well.
– That’s my understanding
– Why when we calculate short circuits at transformer secondary we should consider no-load ph to phase voltage not rated voltage?!
– Yes.CVT is more affordable to be used since the consideration of its(equipments) isolation to H.V.
– Yes, we can track and analyze its dissipation factor( Tan Delta measurement)
– Which position?
– This is an AVR relay from ZIV bringing.
-anyone has the pin configuration of this relay?
– If you mean bias setting, then I would say it has to be calculated based on the transformer parameters
– Hello everybody, good morning. Do any of you run the digsilent program?
– What /which are the switching operations and commissioning procedures of HV / EHV equipment considering the safety rules of power system operation?
-P94V Undervoltage relay showing continuous trip, but no alarm present and all functions disabled, need technical support .can anybody please help.
– Go to view record and reset led Did, but still not going
– To increase the contact Resistance with Ground!

-To minimize step potential?
-yes

Our completed Courses:

– Why stone and whether it’s the only solution?
– Cheapest
– Another reason stones are used is ‘cause it helps in the fire. mitigation, especially where oil traps/ sump pumps are not available.

– The leaked oil will have less surface area exposed to air that can burn, thereby reducing the fire hazard.
– Weather dry sunny temp 35c approximately Fault 132kv lighting arrestr and HV bush of power transformer 20/26MVA damaged
– 132kv CT side clamp
-Counter of lighting arrestr
– Lighting arrestr
– Structure damaged After fault jamper
– Analysis as per our senior-most retired chief Engineer such type of fault occurs due to delay of lighting arrestr counter delay. This type of fault occurred in Pakistan time by a time where lightning arrestr having counter are installed. Due to delay HV bush of power transformer also damaged
– Did the Hv bushing passed the lighting impulse test?
– At the time of manufacturing or now
– Bushing may be damaged due to pressure of conductor available 132kv surge arrester if required plz context 03214484444
– I wonder if you have the fault recorder of this lighting surge impulse on your relay
– Are there any lightning arresters at the top of the transformers firewall/ other location?
– What’s the fault in the protection relay or fault recorder?
– Ds agile documentation please, guys how can I get cooling oil for a 1000 volt transformer
– What is the relay saturation of the IDMT curve in sepam T80 and S82?

-Any have experience In Reyroll Relays.! I need help with how to change the “Out of service mode”.

– We need to do an 87L test, as you can see in secondary current to relay is very low 0.044A. We did a secondory injection for GE L90 relay and found it doesn’t read 0.044A. Value is fluctuating and getting stable at 0.1A.

– Any idea why the 51N protection of the REF615A relay operates in an almost constant time of 0.06 seconds
– reviewing the operation curve the minimum operation time is 0.02 seconds at least the first 3 tests would have given me the correct value
– check the other seating. Check the type of curve selected in the relay, Whether it is definitely time or IDMT
-1 group setting might b clashing with another one, check all stage settings group-wise.
– Work Is for Automation Visit in Kolkata. Just visit the site at Kolkata only people from Kolkata plz contact me.

– A Power distribution full project including design of LV and MV component
– 40mva x-mer tripped on differential during charging of 33kv feeder with Idr= 0.49pu, Idy= 0.50pu and Idb,= 0.53pu.
Both sides LA has physically verified and found ok.
– Did you check the %of Harmonics during charging from the DR?
– please do a stability test and after that examine the results.

– might anyone have the design book of transformers with CRGO steel core and amorphous metal core
– Please guide how to reset DR full alarm in DPR Micom p442 Schneider electric
-Maybe you can right-click on the device and select supervise device

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– Anyone has a VALANCE book on “How to Test Breaker Failure Element Logic”?

– I have a problem with Micom P443 for Distance Protection. I have a problem with System Checks for Autoreclose, anyone can tell me what is the difference between CS1 Close Enable dan C/S AR Immediate?
– Cs1 close enable is the setting of sync check on which you want to recloser the circuit breaker like on Live Line Live Bus or Live bus Dead Line or Dead Bus.
– If you enable c/s AR immediate then it means that if during the dead time system check conditions are met then it will reclose the breaker without waiting for the remaining dead time period,
– Like for example if dead time is 1 sec
– And system check conditions are met during 0.6 seconds of dead time, then the relay will give reclose command without waiting for the remaining 0.4seconds of dead time. But you have disables the system check conditions on shot1 which means it will reclose the breaker without looking into any system check conditions,
– Sys check on shot 1 should be enabled too.

– Hi Guys I have a question: what is the problem with a 3phases motor run by A frequency driver, if I want to run it very slowly for instance at 4HZ normally it runs at a modulated Frequency variable between 50Hz and 0 but what happens to a very low frequency?
– I know that it will run slow, but it will warm up a lot right? but more than that what will it happen? somebody, some documentation to explain this phenomenon?
– It depends on the loading. The higher its loading, the more power is needed to turn the output torque. If you don’t have a load, just make sure your lower frequency setting has a minimal current to move the rotor otherwise, it will overheat.
– I even reinstalled my windows not going, I checked internet settings also

– how we can develop an HMI screen of operator name tag id selection in Schneider Vijeo Designer Basic HMI software
– Can Anyone suggest or provide a link for low-cost alternatives for moxa U port 1150 type connectors with similar capabilities?
– USB to Serial converter


– Does anyone have sft sav diagnostic software for Sepam relay?
– Does Anyone know about selec Twix-2 PLC communication with Schneider HMI
– Please have someone ever configured SEL 487B busbar protection?
– The SEL Technical Support Line is available at +1.509.338.3838

– does anybody here has the SUE3000 configuration tool
– Some examples of End Fault Protection with SEL 487B?

– Anybody can please share with ME Schneider Software SFT SAV?
– what does this number means by 6000 of this RCD?
– It can open currents up to 6000A. 6kA
– Note it’s RCBO not RCD
– What s the difference? Because some tell me it is the max number of trips. RCBO stands for residual current circuit breaker. It can open faults up to 6000A. It can be used for short circuit protection as well as sensitive faults of 30ma. RCD is a residual current device. It’s used only to pick up sensitive 30ma faults. They can’t open full short circuit currents. -Think of RCBO as RCD+MCB
– No it’s the rated fault level.

– We have the following problem with ER make DUOBIAS relay for Transformer differential protection
– Can anyone guide what to be done with this?
– Hi anyone has testing commissioning motor differential protection relay procedure please Sharing
– Short circuit level for this device
– This kind of error shows in sverker 900 Megger relay test kit anyone has an idea what is this?


– Maybe you could try to restart the device. And try to jumper each phase RST to neutral phase.
– Jumper are arranged like this is it ok?
– I have restarted the kit but it not working
– Jumper I1to neutral, then I2 to neutral, and so on. Simultaneously inject small current to monitor the device voltage ports are also not working
– How about the current ports?
-They are also not working
– Make sure when you start the device the knob selector is in an off position.
– Check the fuses too

– Does anyone know if you can force or simulate voltage on an ABB relay? That is, without using a device like Omicron
– someone helps, how can I test the GE L90 diff relay as a stand-alone without connecting with another one. You can only force digital outputs and simulate inputs. You can’t force analog signals such as voltage and currents. You need an external source
– I’ve never dealt with this relay but If it is for line differential, chances are that you’ll need two relays. the receiver and transmitter
– But you can still use the primary injection method to do the testing
– Do you have to test line differential?
– You can go to setting, testing, channel test, and loopback. Inject currents, the relay will consider one current as local and one as remote

– Hello guys, I’d like to ask maybe some of you ever test this type of relay?
– Where we can find the tms
– I think tms is 2
– TMS is nothing but a round dial
– Yes it is 2
– In this case, it’s 2

– for ref relay input problem. Ref620
– From the drawing, check the terminal point associated with this input. Isolate it then troubleshoot that circuit to find out where the “high/positive” signal is coming from
– why inside relay see this message drawing as not a problem?


– I am working with a 2X300 MW thermal power plant in India and our 400 kv switchyard is having Alstom MICOM P 441, REL 670 for protection also for the generator we are having siemens make 7UM622 and MICOM p345.
Is there any standard that speaks of about frequency of relay testing?
– Normally frequency of Numerical Relay testing depends on the utility practices.

– In our utility, we do annually. But in my opinion, it is not required annually.
– Numerical relay can be tested 5 years once. Scheme testing can be done annually.
– anyone has a crack version of IED smart or IED scout for IEC 61850 simulation?
– How to do scaling of this pressure sensor
– these transmitters are of a fixed range
– 615 series?
-RET620
– try to use a new project. if still like that try to factory reset the IED but if it is still operating

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– How to connect GPS to this siemens relay 7VE632
-synchronization via IRIG-B
– someone assists me with CPC 100 software.
– You either need IRIG B port on GPS receiver or you need NTP to IRIG B convertor

– Please find below the parameters you are expected to use as discussed with RTM;
Reactance = 0.2215 ohm/km
Inductance = 0.20808 ohm/km
Suseptance = 0.07573 ohm/km
Distance = 313km
– Please how can I find the positive and zero sequence impedances from the above parameters thanks
– 400 KVAR 90 UNITS. 132KV CAPACITOR BANK. neutral CT 5/5. 132kv CT 400/5. Capacitor protection or unbalance relay current setting? Relay type SPAJ 160 C
– Normally Unbalance protection has one special other CT different from CT 132kv phase or CT neutral but if This CT 5/5A is just for SPAJ protection we adjust setting unbalance between 10 (..)20% In for nominal current this CT 5/5A

– Please explain the working of reverse power relay at consumer end for the small hydropower plant of declared capacity 24.75 MWWhat is recommended Characteristic angle for Directional Earth Fault protection (67N) on SEPAM

-Sepam relay is on the closed-loop network.
-System grounding: resistance grounded (Two NGR Prallelled: 2x800A: 1600A).
The type used for 67N on Sepam: Type-02 (the protection function uses I0 vector magnitude).
Residual Current input on Sepam: Calculation of Summation three-phase current (not residual CT).

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– I want to know if my raw data for the sensor is 0 to 32767 and I wanted it to show in HMI in the format of 0 to 100 bcoz if in system sensor mistakenly get faulty or I have to replace the sensor and the sensor of any other company in my system, so due to this I can change from HMI raw data in the format of 0 to 100 is it is possible?

– Hello, Micom p-243 protects compressor after start 15 minutes then trip. The indication in local HMI (motor fault alarm )but in the protection relay no indication but became an open position. When I go to the record I see this in the pic
– I do isolation resistance for motor by using 5kv meggar the result was 4Gohm

– In HMI how to create operator name error
-It’s over Current, what’s your starter motor current start pick and protection Micom configuration?
– Respected members, Please guide me on how to carry out the Hi-Pot Test/Dielectric strength test for 22kV 3ph Breakers/Bus bar.
-If the available source is DC for testing, how much voltage is to be applied, and any references of the standard for the same.
– How to write scripting language for 0 to 50 Low and 50 to 100 high value in C programming for HMI?

– on Nari pcs9611 relay, when powered on it displayed sub supervision Alarms? Alm-device, Alm -time sync.
How can I cancel?
– set the time synchronization to off instead of sntp
– Under settings?
– under device config or communication.

– Does anybody has ZX0 ABB switchgear O&M.manual
– Especially Gas handling procedures
– HB 600-05 en
– HB 605 Gas handling Manual for ZX0
– I have tested my lightning arrestor for 11KV after removing it from the line and the IR value was 400 meg.
– A few minutes later I have tested it again the value was raised to 15 Gig.

– Please I need the manual of Siprotec 7SA87
– Hello everyone, could you help me with the function of the TC1 on the delta winding?
– It’s a current transformer for the winding temperature gauge

– someone knows what is the difference between I> and I>>?
– I> is the short time protection setting and I>> is the instantaneous protection settings of the overcurrent relay
– Can somebody tell me what happened if the tripping coil resistance and a closing coil resistance of vcb are the same? then there is any impact on the performance of vcb?
– You can return to the datasheet of the circuit breaker and closing and tripping coil, you can find the standard values of the resistance of the trip and closing coil and compare it to the measurement
– I just want to know the theoretical answer Behind this.
– From an electrical engineering point of view
– closing coil resistance is designed much less than tripping coil resistance to having a stronger magnetic field
– Yes I know it is designed, but my question is if they are the same then, what happened?

– does somebody here have some “how to configure Modbus protocol in SEL relays” document or some kind like that?
– Someone has a method statement of Testing CVT Tan Delta

-Does anybody have a project for the RED670 relay?
– Anything, in particular, you are after !’vv?
– Current line differential relays are fairly straightforward?

– Anyone knows what is the problem when a source (power plant) transmits power to a substation, then the neutral current monitored in the power meter is a bit higher normally?
– I know that It means that there is an unbalance current on each phase. But what else can be that causes the phenomenon?
– The P.F on phase R and S are lagging 0.9, but phase T shows a leading P.F.


– In case it’s an internal fault, just assume that the 87 T relay and Ref relay will trip?
– your understanding is correct. But apart from it, if primary Overcurrent (50/51P) works, it will trip the CB 150 kV, and how about the CB 20 kV?
– Is it required to trip the CB 20 kV too?
– 87T trip, REF not really, depending on the fault. PP fault or 3P internal fault won’t initiate REF
– To isolate the power from LV side too, in case of bus section in 20 kV side is closed
– Depends on the control scheme we use in most of the cases we adopt if HV side CB trips on protection LV CB also gets trip, REF is more sensitive for earth faults in the differential zone. If it is an earth fault REF trips faster than Diff.
– I think that 20 kV CB will need to trip too to prevent reverse power from the remanent voltage (power) at Bus 20 kV side. But if there is a remanent voltage on the 20 kV side, is it possible to induced voltage in the primary winding to create a current.
– Since you have NGR, earth fault close to neutral may not be detected by REF.
– Percentage of the unprotected zone can be calculated based on relay settings and CT ratio.
– Yes. due to the resistance, the sensitivity will be limited.
– Have everyone ever tried to the induced voltage on the secondary winding of step down Transformer i.e. let’s say 150/33 kV. How about the primary winding transformer, does it will generate a low current or a harmonic current?
– Actually, fault moves towards the source. In actual LV will not trip because the fault current will move towards the source side (150kv) side but if inter trip function is available then LV 20kv side will trip too
– Anyone knows about the calculation to get the value of Z1 Sensit. Iph>1 ?
– Fault current should be above this value to identify zone 1 or zone 2 faults
– I got it. But how to get this value.
– Okay. I have found it was 1.2 x CCC / CT Ratio
– CCC indicates which value? please clarify I doubt the Current Carrying Capacity Of the conductor
– In Distance Relay
– Anyone knows the CB IS( In-Service) Time function?
– Since I close my CB then the IS time starts to count to set AR Block
– If CB is manually closed then after this time CB will be considered in service and the Auto Recloser function will be enabled too.
– But why it AR block indication appear.
– After the CB IS Time starts to count. Still struggling on this distance relay
– Because during CB IS time AR Function is disabled to block the AR on SOTF fault, change to ABB REL670
– What type of relay is this one?
– P443 Micom
– does anybody here has a p14d Modbus register
– who knows the ZIV default password
– Any ZIV relays specialist
– Hello all, does anyone has a GRL 200 Toshiba Line Current Diff Manual Book?
– Four corner numbers 7931

Join 20 WhatsApp groups for protection engineers

20 WhatsApp Groups for protection engineers

  • WhatsApp Grp 01: Protection Relay – General
  • WhatsApp Grp 02: Substation Automation – General
  • WhatsApp Grp 03: Transmission line protection
  • WhatsApp Grp 04: Transformer protection
  • WhatsApp Grp 05: Motor protection
  • WhatsApp Grp 06: Generator protection
  • WhatsApp Grp 07: Overcurrent and Earth Fault Protection
  • WhatsApp Grp 08: Busbar protection and Bay controller
  • WhatsApp Grp 09: Breaker protection and control
  • WhatsApp Grp 10: Protection Relay Testing and commissioning
  • WhatsApp Grp 11: DIgSILENT
  • WhatsApp Grp 12: ETAP
  • WhatsApp Grp 13: PSCAD
  • WhatsApp Grp 14: IEC 61850 configuration
  • WhatsApp Grp 15: Switchgear GIS & AIS
  • WhatsApp Grp 16: GE Relay Configuration
  • WhatsApp Grp 17: SIEMENS Relay configuration
  • WhatsApp Grp 18: Schnider Relay configuration
  • WhatsApp Grp 19: SEL Relay Configuration
  • WhatsApp Grp 20: ABB Relion configuration or more services

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Sample discussion:

– I have a Zivercom relay for the Tap changer. everything looks fine but it’s not Tapping who can assist tanks
– is anyone familiar with Siemens Siprotec 4 7SD Line Current Differential Relay? For example, one end of the relay is select in Commissioning mode(test mode), will the remote end relay differential protection be in commissioning mode or test mode also?
– Commissioning mode at one line end will not turn on commissioning mode automatically to another side. Plus commissions mode is completely different from test differential mode.
– Can you explain a bit more about the test differential mode?
Does turning the test differential mode at one end also activate the remote end’s test differential mode?
– Anyone REM620 relay this message what problem
– Anyone has the actual standard IEEE 485 or an excel sheet? I need to size the substation battery charger, please!
-IEEE 485-2020?

– Does anyone know what these signals are used for?
– Apparently, they are permissive of Switches
– RECEPTION RRR, RRA, RRX, and RRY
– the arrangement of the substation is as follows
– Have anyone tested Cap bank differential protection in Siprotec 5 7SJ85 relay?

– constantly getting this error while writing to the IED
– delete the HMI page first
– do the license update tool
– Does anyone have software for this relay micom2.1?
– I have found Micom software if anyone can give Ziv software as well plz
Our substation incomer feeder is tripping downstream and upstream without any fault when switching on outgoing feeders.
– Please suggest any idea to solve the above-mentioned issues
– What fault was recorded by the relay?
– There is no fault on the relay but upstream and downstream are tripping when switching on any outgoing feeders.

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– Any circular regarding the fair service life of various testing equipment in the power sector.
– Hi, has anyone ever replace these manual annunciator window tiles with a 3rd party tiles? or other alternatives?
– We are facing this kind of rebooting issue with the AREVA Micom P742 peripheral Unit for busbar protection. Anyone has any idea regarding this issue. How to overcome this?

Protection Relay Discussion Group in Telegram: https://t.me/joinchat/Cmyg2FiXX-qlTYqyXQ_pjg


– Can we use a 10 ac drive on a 15 hp motor?
– 12.5 hp drive on 15 hp motor
– Hi All, do you guys ground the shield of control cables at both ends or only a single end?
– Single-end
– How about for CT VT Cable?

– May I know would there be an issue if we use a CT with a high Burden (15VA for example) for a protection relay (microprocessor type). For the old mechanical type, I understand that the CT need a higher burden to drive the armature
– when I turn on the generator in this panel my generator has an unstable frequency but when I operate it manually the frequency stabilizes. what may be the cause of this?
– Is your gen-set in synch with other gen?
– no sir.
What is voltage?
– plz check the gain & another setting for your operator panel
– 460v
– there is no problem with the engine & gen-set itself it is the only problem with the operator panel feedback signal which will be generated as per setting
– Cause freq regulation is in generator itself not in Woodward
– we try to bleed fuel on the generator. but nothing happened
– I thought Woodward only does parallel synchronization and some protection functions but is only using small loads that’s why we don’t sync our generators.
– I looked at the manual for easygen. Actually, there is a function of frequency control. I have the same system
– But never got time to check every function in Woodward.
– I do check some functions but the configuration has a password. the management told me that the supplier has the access to its unit.

– does anyone knows about arc resistance and tower footing resistance value for the 765KV transmission line?

– I need to disable goose controls in the REF 615 ABB relay. Is it possible from HMI?
– who can assist me with an IED scout that’s licensed REG630 how to testing method DOPPDPR function Power Angle setting anyone to have a formula
– Could anyone be having transformer test guides preferably based on megger make test equipment?
– Paci’s configurator from Schneider, can anybody have this software if yes kindly send me the link, it’s urgent please help me
– Somebody has REX640 TERMINAL DIAGRAM?
– Does anyone know how to choose a zero-sequence transformer?
– In the VAMP300 relay display LED continues to glow without assign, without mapping with DI points. what is the issue please kindly suggest!

– Need help in ABB RVC APFC Relay programming.
– If anyone has a license for REB500. Can help me, please.
– ABB normally do not release that license which allows you to configure
31etap 12:00 – abb pcm600: The user license there isn’t much you can do with it.

– Kindly someone tells me that in C264 Relay, how to change synchro-check parameters and find the passwords?
– Connect to Cat tool to these devices n check network parameters. Trying to read the setting but the reading takes a few hours. Are there any solutions?
– I assume some delays in the network..try connecting them one-to-one if possible.
– Try to reboot the relay
– what could be the problem if Generator Shuts Down on High or Over Frequency, Over Frequency Runaway
– If you are connected to the grid Burn the rotor due to induced currents. If you are in islanders mode: damage the connected equipment.

– is it ok to run a generator that varies 59.9-60.1 frequency?
– Trying to read ABB RET 670, but the messages show up like this
– Any insights into this problem
– Does anyone knows how to add delay time in VT Fail ABB RED 670
– Not very sure but….Inconsistent state means the current values in PCM are not reflecting the ied values. If a reader does not resolve this try to see if there is a new version of PCM.
– 132kV transformer HV breaker was closed on NO load and the LV breaker was open, but suddenly differential relay operates and gives a differential trip. In the fault study, the HV side current was 860 Amp. Somebody tell me that what could be the reason?
– For how much time the transformer was on no load? 132/11.5kV?
-Approximately 10 to 15 minutes
– MVA?
-132/22 kV (wind power plant)
– There must b some issue,
– So this is not inrush
– Do TTR and winding resistance,
– If it is the newly commissioned plant then the issue will be in the relay setting otherwise check transformer winding…do the IR.
– I did an excitation test @ 10 kV and the results were OK.
– Plant is in operation for the last 4 years. You will have to do TTR and winding resistance to diagnose the matter, Hope you will get the problem by doing these tests,

– Any mechanical protection PRD, BUCH has operated. Did u retrieve the fault records from the relay?
– TTR?
– turns ratio test
– No trip from mechanical protection.
– In fault record HV current was 860Amp and LV current was 0 amp.
– Check the CT ratio adopted in the differential relay and what was the differential current setting adopted and actual current during relay operated?
– Transformer turns ratio

– 860AMP WAS SINGLE PHASE OR TWO PHASES OR IN 3 PHASES?
– In 3 phase
– Did you check the lighting arrester AT 132 KV SIDE?
– Yes surge arrestor can also be damaged or weakened, as you are using Yard CT for Differential protection
– do also check your HV arrestors

– Can anyone help me with the PACiS configurator?
– Physically that was OK, for counter I will check
– Do hipot test of arrestors, which might be differential tripped because of arrestors, If u have a secondary injection kit like Omron or Freja plz do the secondary injection to know that there is no problem from the relay side.
– can I ask why my plc doesn’t read flow?
– Check that the analog signal is reaching from your flow meter to plc?
– Check 4 to 20 amp signal

– Hello guys, does anyone know how to avoid distance trips when VT Fail occurred on 3 phases in REL 670?
– Anyone has any material for Artificial intelligence application in Protection?

– Pls help me how to install PCM 2.10
– Strongly recommend installing on virtual machines
– After 3~4 different versions, they always conflict and give errors.
– I run different virtual machines on the ESXi hypervisor.

– I need help to analyze this Disturbance Fault Record whether it is due to Lighting or Flash.
– It was a fault on Line Diff and Reclose on Phase R.
– Anyone Plz tell me, what is relay coordination and what its functions are?
– Line auto-reclosed successfully?

– We have 50/1 5p15 CT installed on a 33 kv feeder whose fault current initially was very less but now the Power supplier has installed a 50MVA transformer with 11% impedance
29etap08:55 – abb pcm600: And fault current is almost 8000Amps, I believe I need to upgrade protection CT to meet high fault current
– Can anyone suggest What’s the 33kv fault level?
– Now it is 8000 amps. Fault current level 50 MVA transformer installed at state electricity board substation and we are consumers with 33 kv feeder voltage
– 50MVA 220/33 KV star/ star connected transformer 11% impedance
– Is the ct used only for over current and earth fault?
– Yes 50,51, 50G, 51G
– Strictly speaking, I would put 200/1 5P40 2.5 VA. However, if the relays have CT saturation detection, you could go lower.
– What’s the relay being used?
– P127
– Do you have the CT test results. In particular the DC resistance of the CT.
-Can you give your consideration or calculations for this selection
– So you need an accuracy limit factor of 40, with a low burden.

– you won’t need much burden as the relay is numerical and installed inside the switchgear
– Your existing 50/1, 15 VA may actually work if you knew the DC resistance.
– Do I have to check with the CT testing kit??
– I believe CT supplier should have this information
– Yeah if you have test equipment (Omicron CR analyzer or similar) that should be easily possible
– That’s possible, however normally the manufacturer will not specify the DC resistance for 5P/10P class acts. No harm in asking them though
– CT’s Analyser
– Ok I will check with him today, as I don’t have an omicron kit available nearby That is the only option I have

– How you coordinate DC resistance with fault current?
– So if Rct<= 1.75 ohm, you can use it For a 50/1 A ct this may be achievable.
need to Replace 33 kv side CT with, 1000/1A, 5P10,15 VA With this approach, I’d reckoned to check the pickup values.

– Ynynd1 And tertiary (delta winding) is unloaded?
– Then no issue transformer will follow system phase sequence,

– What is the difference between IN-HV Deriv Angle and IN-HV Measd Angle on monitoring online?
– Derived means the neutral current has been calculated by summation of IA, IB, and IC whereas measured means neutral wire of ct secondary is connected to the neutral element of the relay, and it is actually being measured,
– What is a dead zone in protection??
– Dead zone is the Zone between CT & Open CB. It’s the point not seen in the zone of protection that of a relay. If a fault occurs at this point, the relay will not issue a trip. Usually between CT and breaker
– IN HV derive is neutral vector calculation, meanwhile In HV measured is a neutral REF winding
– We cannot say it is neutral ref winding until we see the setting of the relay,
– setting of the wiring diagram right. The relay and schematic drawing setting depict the connection of the ct secondary wires with the differential relay.

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DIGSI 4 training will be taking you through all the key stages of working with DIGSI 4 using practical examples. This online course is suitable for electrical engineers with a desire to understand the fundamentals of configuring SIPROTECT 4 with DIGSI 4.

DIGSI 4 Online Training

Covered Items

Demo Video

Overview:

Part 1: How to install DIGSI 4 (Length: 01:57)

Part 2: Introduction to SIPROTEC Relay Families (Length: 06:50)

Part 3: Wiring Connection (Length: 03:02)

Part 4: Start with DIGSI (Length: 19:12)

Part 5: Archive, Export, Import (Length: 12:36)

Part 6: Masking I/O (Length: 11:00)

Part 7: Masking I/O (Length: 04:51)

Part 8: Masking I/O (Length: 13:08)

Part 9: Default and Control Display (Length: 16:21)

Part 10: CFC (Length: 11:57)

Part 11: CFC and Implementation of experimental example (Length: 07:59)

Part 12: CFC Interlocking Example (Length: 04:26)

Part 13: CFC Protection Example (Length: 04:13)

Part 14: CFC Explanation of all blocks (Length: 11:01)

Part 15: Power system data 1 (Length: 08:34)

Part 16: Setting Group (Length: 19:13)

Part 17: Oscillographic Fault Recorders (Length: 03:06)

Part 18: General Device Settings (Length: 04:39)

Part 19: Time Synchronization and Interfaces (Length: 03:40)

Part 20: Device Driver and Firmware Update (Length: 09:04)

Part 21: Config SIPROTEC relay in a Practical Project (Length: 14:36)

Certificate of completion for the enrolled members:

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DIGSI 4.93 is the user interface to configure SIPROTEC 4, SIPROTEC Compact, and SIPROTEC 3 devices. It is designed with a modern, intuitive user interface. With DIGSI 4.93, from the numerous protection functions, it is possible to easily select only those which are really required. The settings can be entered and displayed as primary or secondary values.

The DIGSI 4 matrix shows the user the complete configuration of the device at a glance. For example, the assignment of the LEDs, the binary inputs, and the binary output relays are displayed in one image. With one click, the assignment can be changed. 

DIGSI 4 and DIGSI 5 online Training course, contact us

With the CFC (continuous function chart), it is possible to link and derive information without software knowledge by simply drawing technical processes, interlocks and operating sequences.

DIGSI 4 Full package

You can assign passwords in order to protect your SIPROTEC devices against unintended changes to the device or unauthorized operations from the device. The default password of DIGSI 4 and DIGSI 5 as well as password management in SIPROTEC devices are discussed in this article. 

SIPROTEC 4 and DIGSI 4

SIPROTEC 4 passwords can only be changed by means of DIGSI 4. Proceed as follows in order to change an existing password. Select the password function and click on the Change command button. The Change Password dialog box is opened. Enter the old and the new password. An asterisk is displayed for each character you enter. As a confirmation enter the same sequence in the Confirm new password box. Confirm your entries by clicking on OK. Passwords are numbers with a length of up to 8 digits.

Access and change DIGSI 4 Passwords

The following access authorizations are preset at the factory in DIGSI 4:

  • Switching/tagging/updating (Password No. 1)
  • Unlocked switching (Password No. 2)
  • Test and diagnostics (Password No. 4)
  • Hardware test menus (Password No. 6)
  • Single parameters (Password No. 5)
  • Parameter set (Password No. 7)

Note: Password protection against unauthorized access is only active during on-line operation. The passwords for changing settings are not activated until the settings are downloaded to the device. They are irrelevant in the Offline mode. In order to de-activate a password, you have to know it!


At delivery, all passwords are set by default to 000000. The passwords for the Web Monitor are an exception: Here the default setting is 000002 for “Full Access”, 000001 for “Changes” and 000000 for “Read-only”.

If you have forgotten your password for changing a parameter set, a temporary password can be obtained from the SIEMENS hotline. This can be used to define a new user password for this function. Siemens hotline requires the registration number of your DIGSI 4 software package!

SIPROTEC 5 and DIGSI 5 Confirmation IDs and Connection Password

SIPROTEC 5 and DIGSI 5 Confirmation IDs and Connection Password

In SIPROTEC 5, there are no default passwords as in SIPROTEC 4. The Confirmation IDs in SIPROTEC 5 serves only as a safety measure. In terms of access control security, there’s the connection password feature as discussed in this article. Additionally, comprehensive role-based access control (RBAC) with central user management in SIPROTEC 5 firmware version V7.80 is introduced. With RBAC enabled, users can log in with their existing, centrally managed user IDs and passwords directly into the SIPROTEC 5 IED. The IED authenticates the user’s credentials using the RADIUS protocol and identifies his roles (authorization) from the central server. This RBAC feature is based on IEC62351-8, complementing it is the built-in Syslog support in SIPROTEC 5. The IEDs can also log all security-relevant user actions in a central log server, thereby also providing higher transparency and detection capabilities on IED operations.

Confirmation IDs are used for protection against unintentional and unauthorized operation. If a confirmation ID is activated, enter it before the relevant action is enabled by the SIPROTEC 5 device. For this purpose, the confirmation ID is transmitted encrypted to the SIPROTEC 5 device, where it is checked. A similar method is used for a communication connection between the DIGSI 5 and a SIPROTEC 5 device. To protect access to the SIPROTEC 5 device, there is a password for establishing the connection.
Confirmation IDs and the connection password can only be modified with DIGSI 5 but not with the SIPROTEC 5 device. You can also deactivate confirmation IDs and the connection password. However, Siemens recommends only using them for commissioning. During normal operation, confirmation IDs and the connection password are always activated.

DIGSI 5 Confirmation IDs

A confirmation ID consists of no more and no fewer than 6 digits, which you can freely select. For the following areas, you can assign different confirmation IDs:

  • Settings/operation: This confirmation ID controls access to parameter settings and process data. After installing DIGSI 5, the confirmation ID for this area has the default value 222222.
  • Switching (process): This confirmation ID controls access to the operational switching, in which the interlocking conditions are considered. After installing DIGSI 5, the confirmation ID for this area has the default value 333333.
  • Switching (unlocked):  This confirmation ID controls access to the non-interlocked switching, in which the interlocking conditions are ignored. Switching without interlocking can be a safety risk and requires precise knowledge of conditions in the substation. Before you can switch without interlocking with DIGSI 5, DIGSI 5 must-have switching authority. After installing DIGSI 5, the confirmation ID for this area has the default value 444444.
  • Switching authority:  This confirmation ID controls access for setting the switching authority. You can set the switching authority, such as on-site or remote operation, only with the key switch on the SIPROTEC 5 device. If the
  • confirmation ID for the switching authority is activated, this is queried by activating the key switch on the SIPROTEC 5 device. After installing DIGSI 5, the confirmation ID for this area has the default value 666666.

If a confirmation ID is deactivated, this is not queried before running the relevant action. This can result in unintended or unauthorized operating actions and even in material damage and personal injury!

DIGSI 5 Connection Password

A connection password ensures secure remote access to a SIPROTEC 5 device. The password must meet certain requirements. A password must be at least 8 characters long. It must include at least 1 upper-case letter, 1 lower-case letter, 1 digit, and 1 special character. No connection password is configured in a SIPROTEC 5 device when it is delivered.

If a password is activated, it must be entered correctly before DIGSI 5 can access the SIPROTEC 5 device. An activated connection password applies to all interfaces of the SIPROTEC 5 device. Access by plug & play is also protected with the password. Incorrect password entry is logged in the SIPROTEC 5 device. After 3 incorrect password entries, an alarm can be output via a binary output. The accessing DIGSI 5 is also blocked for further access for a few minutes.

If the connection password is deactivated, it will is not queried before a connection is established. This enables unauthorized persons to establish a connection between DIGSI 5 and a SIPROTEC 5 device.

This Download also contains all the released DIGSI 4 device drivers. These can be individually and independently installed.
Download and unpack the DIGSI 4 DVD installation file.
Open “Setup.exe”.
Select and install the DIGSI 4 software or the released DIGSI 4 device drivers.


New Features and Modifications in DIGSI 4 V4.92

DIGSI 4 V4.92 includes the following changes:

  •  Secure communication (Ethernet) between DIGSI 4 V4.92 and devices of the family of SIPROTEC 4 and Compact Class by using DTLS protocol. An update of the EN100 firmware is required in order to use that feature. This function can be disabled (enabled by default).
  • New password-protected connection between DIGSI 4 V4.92 and devices of the family of SIPROTEC 4 and Compact Class via Ethernet. An update of the EN100 firmware is required in order to use that feature. This function can be enabled (disabled by default).

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