Variation in Synchronization check parameters

Introduction: In earlier post, we have learnt about various parameters related to synchronization checks in electrical power syatem. 

Click here for earlier post regarding synchronization check.

Now, we will see voltage waveforms if these parameters are varied. In all waveforms, Red and Blue are two voltages to be compared for check synchronization. Black is vector difference of Red and Blue.

1. Phase angle variation: Typical setting for phase angle difference is 15-30 deg. Two cases for 30deg and 60deg are shown below. The vector difference will be Sine of angle difference between two voltages. Therefore, for 30 deg it will be 0.5 and for 60 deg it will be 0.866

2. Voltage variation: Typical setting for voltage difference is 7.5 to 15%. Two cases for 10% and 20% are shown below. The vector difference will be same as difference between two voltages. 

3. Frequency variation: Typical setting for voltage difference is +0.2 to +0.5%. Two cases for 5% and 10% are shown below. Case for higher frequency difference are choosen for proper visualization. Showing diagram for 0.5% frequency difference will require longer time scale and it would not be clear to visualize the diagram.. 

In the image below, the vector difference is gardually inreasing and decreasing at a frequency equal to frequency difference between two voltages. The CB has to be closed when voltage difference is at lower level. Therefore, if frequency difference is low, we have more time to close the CB. In the image below (for 5%), voltage is low for ~6 cycles, which would be ~120ms for 50Hz system. It will be impossible for operator to close CB in this short duration. In actual case the check sync setting will 10 times lower i.e. 0.5%, this will give operator a time of 1200ms (1.2 sec), which is sufficient for closing of CB.

Auto-Recloser in feeders

Introduction: Electricity is transferred on higher voltage for long distances. Transmission / distribution feeders pass through forests, hills, fields etc befor reaching destination. 90% of the faults in feeders are transient in nature. These are caused by lightning, birds, falling trees, Forest growth, swinging of conductor, High velocity winds etc. Transient faults disappear after a short interval of time. In this manner, If line is tripped, 90% probability is that line will charge immediatly without any rectification required. For reducing the outage time, auto-reclose is used. Which means automatic closing of circuit breaker (CB) after small gap of time, called dead time. Minimum dead time is selected such that ionized air due to arc is de-ionized within dead time. It is generally between 0.5 s to 1.0 s.

Different approaches in auto recose: Auto reclose selection has four options:

1. No Auto reclose: Auto reclose disabled, no auto reclose will be attempted.
2. 1 phase auto reclose: 1-ph auto reclose will be attempted for 1-ph faults. If the fault is 2-ph or 3-ph, 3-ph trip will be initiated and no auto reclose will be attempted. It is used without synchronism check as remaining two phases will be connected from both ends. Typical time for auto-reclose attempt (Dead time) is 1 sec.
3. 1+3ph auto reclose: 1-ph auto reclosed will be attempted for 1-ph faults and 3-ph auto reclose will be attmpted for 2-ph or 3-ph faults. 
4. 3 ph auto reclose: 3-ph auto reclose will be attmpted for 1-ph, 2-ph and 3-ph faults 

Multi-cycle 3-ph auto reclose: In some cases multiple attampt may be required for auto reclose. First cycle is fast one having dead time less than 1 minute. remaing cycles can have dead time upto 1 hour. It is mostly used on radial type of feeders.

Circuit Breaker requirements: CB is key equipment during auto-recloser. Its operating mechanism should have sufficient energy for simultaneous Open- Close -Open operation to take care of persistant fault during auto-reclose. When CB is ready for this operation, CB ready signal is provided to Auto-recloser relay. AR will happen only in case of CB ready signal.

Another requirement is arc quenching capability of interrupting chamber. In case of SF6 CBs, SF6 gas retains its dielectric properties after ~25 sec. Therefore, after autoreclose operation, next auto reclose can happen only after 25 sec. This delay is called reclaim time. Any fault during reclaim time will lead to 3-ph trip and no AR attampt will be taken.

Synchronization Check in AC systems

Introduction: In AC power system synchronization check is used when we are connecting two different systems. Two points are worth mentioning in this case:

1. The connection is always made through circuit breaker (CB)
2. We are not sure both the systems being connected through CB are different or same.

Therefore, synchronization check is used when closing circuit breaker to ensure we do not interconnect out of synchronism systems.

Implementation: There may be four cases when closing CB:

1.  Dead line Dead Bus
2.  Dead Line Live Bus
3.  Live Line Dead Bus
4.  Live Line Live Bus

In the first three cases, there is voltage only one side of CB, there no option of synchronization check. Therefore, CB is to be closed without any check. For radial feeders synchnization check is not used because we always close for Dead Line Live bus cases. In fourth case both side voltage is available. We have to check synchronization before closing the CB.

Parameters to be checked: For interconnecting two systems, we have to ensure the following three parameters are within limits: 

1. Phase angle difference - It will lead to active power flow after CB closing. If it is more (typical value  +30 deg), large current will flow depending on system impedance. This may lead to damage to equipment or grid (or infinite bus). As shown in image below phase angle difference is δ. (Blue line is Bus voltage Green is Feeder voltage, Red is difference between Bus and Feeder voltage)

2. Voltage difference - It will lead to reactive power flow after CB closing. If it is more (typical value  +10%), large current will flow depending on system impedance. This may lead to damage to equipment or grid (or infinite bus). As shown in image below voltage difference is V1 - V2 after taking r.m.s. value (Blue line is Bus voltage Green is Feeder voltage, Red is difference between Bus and Feeder voltage)

3. Frequence difference - In interconnected AC system all synchronus machines (Mostly generators) run at same frequency. All the machines have thier rotors magnetically locked with stator field which is rotating at grid frequency. If there are two different networks at different frequency, they have to run at same frequency after interconnection, otherwise interconnection will not work. Normally synchronization check is done that incoming feeder frequency is with permissible range typical value for frequency difference is +0.2% to +0.5 %. If any generator is rotating at higher or lower speed (prior to connection to grid), which means it has different frequency, is connected to grid, it will feel mechniacal shock upon CB close. Because if it is running slow (i.e. lower frequency), after CB close it has to run faster to match grid. But its prime mover input is low. It will start to run as motor, taking power from grid. In other case if it is running faster (i.e. higher frequency), after CB close it has to run slower. Due to more input to prime mover it will give more power than anticipated. As shown in image below frequency difference is f1 - f2.

Click here for detail about variation in these paramaters.

In addition when first time interconnecting two systems, phase sequence is also to be checked. Subsequently, it is not required to be checked because phase sequence can not change without physical change in connections. As shown in image below both bus and incomer voltages have sequence R - Y - B.

In the image shown below, let us assume we are connecting generator-1 to Bus bar by closing CB-1. Before closing we have to check synchronization by comparing any one phse voltage (Normally R-phase) of Bus VT to Feeder-1 VT. We do not compare voltage of all phases, becuase phase sequence for both sides have been already been matched during first time charging. 

Synchronization check is more significant at generating stations when connecting any generator to grid. During synchronization operator is also having control of generator i.e. he can control frequency / voltage of the generator. 

Synchronization check is used at substations also before closing any CB, so that two different systems are not interconnected without checking synchronization. As shown in image below Before closing feeder CB at Station-B Synchronisation is is required.

In substation already connected through alternate route, frequency will be same on both sides of CB, but phase angle and voltage needs to be check by synchronization check. As shown below, Station-A and Station-B are alraedy connected through Station-C, But before closing feeder CB at Station-B, voiltage difference and phase angle difference needs to be checked.

Calculation of relay settings for transmission lines - Distance protection

Introduction: Electricity is transferred on higher voltage for long distances. Transmission lines pass through forests, hills, fields etc befor reaching destination. Being exposed to uncontrolled atmosphere, faults on transmission lines are as high as 85% of the total faults in power system. These lines are protected by distance relays working on impedance function. Now with the advancement in optical fibre technology, line differential relays are also being used. Line differential relays are also having distance protection function which comes in to action whenever there is optical communication failure. In addition to protection these relays also work as fault locator which is also based on impedance measrement principle.

Line Parameters: Transmission line is a long conductor having resistance, inductance and capacitance distributed uniformly throughout the length. Following line constants are provided by designer based on calculations, which are used for relay settings:

Sr	Parameter		Unit
1	Positive sequence reactance	X1	ohm/km
2	Positive sequence resistance	R1	ohm/km
3	Zero sequence reactance	X0	ohm/km
4	Zero sequence resistance	R0	ohm/km

Conversion to Secondary value from Primary value: Above parameters are given for primary equipment. The protection relays are connected to primary equipment through Current transformer and Voltage transformer (CT and VT). Relay reads the current and voltage on secondary side of CT and VT. Therefore the parameters needs to be converted to secondary side as per CT and VT ratio.

Z secondary = Z primary x (CT Ratio / VT Ratio)

Setting calculation: We will drive settings for Station-A end relay of a 220kV line to station-B. Actual relay setting calculation will depend on many factors like relay make and model, network size etc. Here we are showing a simple example to get an idea of basics for relay setting calculation. 

VT ratio: 220kV/110V 
CT ratio: 800/1A

Primary side line parameters are:
X1 : 0.398 ohm/km
R1 : 0.069 ohm/km
X0 : 1.290 ohm/km
R0 : 0.281 ohm/km
Line length LL: 100 km
Next Longest line: 80 km

CT Ratio: 800/1 = 800
VT Ratio: 220kV/110V = 2000 
As shown in Fig-2:
Positive sequence impedance Z1 = Sqrt (R1^2 + X1^2) = 0.404 ohm/km
Line Angle = ArcTan (X1/R1) = 80.16 deg
Zero sequence impedance Z0 = Sqrt (R0^2 + X0^2) = 1.320 ohm/km

Line Angle = ArcTan (X0/R0) = 77.71 deg

Total line positive sequence impedance ZL = LL x Z1 = 40.4 ohm

Zone settings are shown in Fig-3 for a four zone protection relay. Zone-1, 2 & 3 are in forward direction and Zone-4 is in reverse direction. Typical zone settings are as below:

Zone-1: 80% of protected line = 40.04 x 0.8 = 32.320 ohm
Zone-2: 120% of protected line = 40.04 x 1.2 = 48.048 ohm
Zone-3: 100% of protected line + 120% of next longest line = 40.04 + (1.2 x 80 x 0.404) =  78.824 ohm
Zone-4: 10% of protected line = 40.04 x 0.1 = 4.04 ohm

Relay setting to be entered in relay (Secondary values):
Zone-1: Primary value x CTP/PTR = 32.320 x 800/2000 = 12.928 ohm
Zone-2: Primary value x CTP/PTR = 48.048 x 800/2000 = 19.219 ohm
Zone-3: Primary value x CTP/PTR = 78.824 x 800/2000 = 31.596 ohm
Zone-4: Primary value x CTP/PTR = 4.040 x 800/2000 = 1.616 ohm

Neutral compensation factor KZN = (Z0-Z1) / 3Z1 = 0.757
KZN Angle = ArcTan [(X0-X1)/(R0-R1)] - ArcTan (X1-R1) = -3.5 deg

Typical time settings for Zone is given below, however these are co-ordinated with relay settings of other elements of the network:

Zone-1 time delay: 0.0 sec
Zone-2 time delay: 0.5 sec
Zone-3 time delay: 1.0 sec
Zone-4 time delay: 0.5 sec

Calculating fault location from COMTRADE file through Wavewin

Introduction: Basic information regarding COMTRADE files (CFG and DAT) was given in earlier post here: Understanding disturbance record files. It is recommended to read this first.

Fault location is and important information, which is provided by fault locator installed for feeders. Normally it is inbuilt feature distance protection. Fault locator has record for latest faults locations (No. of records vary depending on Make/Model of device). Or there may be cases where we have COMTRADE files but access to device records is not available. In these cases we may calculate location from COMTRADE file.

Procedure: 

Open the file with Wavewin software. For fault location calculation, Clicke on Data > Fault Detector, A new window is opened as below

In the DR file, it can be seen that although Secondary is shown on the title bar, current and voltage values are in primary values (Voltage =241646V and Current =219A). This is because CT / VT ratio data is not available in this CFG / DAT file. It is taken as 1:1. It can be checked as below:

The information whether the CT and VT ratio is available or not, is an important information. We have to enter line parameters in Primary or Secondary based on it. In this example Secondary values are equal to Primary values of voltage and current (Due to 1:1 CT and VT ratio). Therefore we will enter primary side line parameters as per relay setting data: 

Positive sequence impedance Z1 = 0.301 ohm/km
Line angle = 80 deg
Zeo sequence compensation factor kZn = 0.750 
kZn angle = -10 deg
Line Length = 100km

In case of actual CT and VT ratio is available in disturbance record files, secondary parameters are to be entered.

Click here for more detail on line parameters

We can specify faulted phase in Advanced settings, which we have not used. Software has automatically sensed faulty phase and shown fault location.

Trip Circuit Supervision

Introduction: Trip circuit supervision relays (TSR) are used for monitoring of healthiness of Circuit Breaker trip circuit. During any fault in Power system, circuit breakers have to interrupt the fault currents. But if trip circuit is not healthy CB will not operate and fault will not be cleared. This will lead to operation of Breaker Failure Protection, causing larger disturbance in Power system and major damage to equipment. Click here for more information on Breaker Failure Protection (BFP).

Post close supervision: When the system is normal working condition the CB will be in closed state. In case any fault is detected by protection relays, it issue tripping command to CB. Trip circuit should be healthy so that CB is tripped without any failure.

Pre close supervision: When the CB is being closed from open state, the voltage will extend to uncharged portion. There may be existing fault in the system being charged which will lead to operation of protection relay. The CB trip circuit should be in healthy state so that any fault is cleared without ant delay.

The typical schematic is shown here

TSR relay is connected in series with trip coil. Trip coil is high energy coil (Low resistance, high current), due to fast operation required for CB. TSR relay is low energy coil (High resistance, low current). 

For example, resistance of CB trip coild is 55 ohm, operating voltage is 110V. Pickup current for CB tripping is 2A. TSR relay has resistance of 1100 ohm. Its pickup current will be low 100mA. All the relays are designed for pickup up at 60-70% os rated voltage / current. Therefore TSR will pickup at ~70mA).

As shown above, during normal condition when CB is close, both coils will be in series. Current through TSR will be 95mA. When tripping command is issued to CB, Post-close TSR will get bypassed. In this case, after CB is opened 52a will open and 52b will close. Now, post-close TSR will get de-energised and pre-close TSR will be energised. 

if any one relay (pre-close / post-close) is energised TSR alarm relay should be in energised condition. If both (pre-close and post-close) relays are de-energised TSR alarm relay gets denergised and alarm is generated to operator. A time delay of ~200ms is given to avoid false alarm during CB close / open operation.

Breaker Failure Protection

Intruduction: Breaker Failure Protection (BFP) is also known as BFR (Breaker Failure Relay) or LBB (Local Breaker Backup) protection.

The idea behind BFP is that in case of any protection operation the Circuit Breaker (CB) should interrupt the fault current within specified time (Normally < 60ms, depending on voltage level). There may be cases where CB is unable to interrupt the current doe to any of the following causes:

1. CB tripping circuit problems
2. CB operating mechanism problems
3. CB interrupter problems

In the first two cases, the interrupter is not at all operated. Therefore there is no risk of prolonged arc inside interrupter, Only risk is continuous feeding of fault current may lead to disturbance in grid operation.

In the third case, due to prolonged arcing inside interrupter, temperature may go high and it may explode due to high pressure buid-up. Normally porcelain enclosures are used for SF6 filled interrupters. Failure may lead to cracking of porceline into pieces, which are dangerous for men working the vicinity of CB. Further SF6 gas will be released to atmosphere, which is not good for environment. In addition, risk of disturbance in grid operation is already there.

Working Principle: The BFP protection is activated when tripping command is issued to CB. If after a pre-set time (typical 200ms), current is still flowing through CB, BFP will operate. Operation of BFP will isolate the concerned CB from all sides by tripping all the CBs connecting to it. For example in the image shown below, following will be the isolation logic:

BFP operated for	CB to be opened
CB-1	CB-2, CB-4, CB-11
CB-2	CB-1, CB-3, CB-11, CB-21
CB-3	CB-2, CB-6, CB-21

There are two methods used for operation of BFP:

1. Current level detection: If current through CT is above set value (typical value 100A) after pre-set time, relay interprets that CB has failed to interrupt the current.
2. CB status from auxiliary contacts: If CB status as per auxiliary contacts (52a) is still closed, relay interprets that CB has failed to open.

First method is more reliable and works for all the three cases mentioned in introduction, therefore used in most of the cases. Only drawback is there must be some significant amount of current flowing for operation of BFP.

Second method does not work for third case (CB interrupter problems). It is used where lower level of current, which is not significant of operation of relay, is also dangerous for health of equipment / person working in the vicinity,

The working principle can be understood from image below:

Restricted Earth Fault (REF) protection

REF protection is Based on Kirchhoff's current law : 

Current flowing into a node (or a junction) must be equal to current flowing out of it. Or in other words vector sum of currents in and out from a node is zero

REF protection is a basic protection used in many equipment in Power system like transformers, reactors, generators etc.

For REF protection is applied to windings having electrical couplings. Magnetic coupling is ignored for this purpose. For example we may consider following single phase two winding transformer:

Here both windings are electrically isolated and magnetically coupled. current entering from primary side I11 shall be same as current leaving primary side I12.  Similarly, current entering from primary side I21 shall be same as current leaving primary side I22. Therefore

I11 + I12 = 0
I21 + I22 = 0

In this example we have used two REF relays, one for primary and other for secondary side. In some cases, in transformers having small transformation ratios, single REF can be used for cost saving. In that case 

I11 + I21 + I12 + I22 = 0

Setting calculation: The simplified circuit is shown as below:

In normal condition I11 and I12 will be equal and opposite to each other, these will cancel each other and there will be no current flow through relay coil.

The typical setting for transformers is ~15% of full load current. For example transformer has full load current of 400A and CT ratio is 500/1A. CT ratio  should be same for all CTs connected to REF relay. The current setting for REF relay shall be 400 x 15% = 60A primary (0.12A secondary).  

In some relays the setting is entered in Volts. Voltage is calculated by multiplying setting current with stabilizing resistor value. Say stabilizing resistor is  1000 ohm, the voltage setting will be 120V.

Value of stabilizing resistor: CT saturation sometimes occur during high fault currents, we need stable relay operation during CT saturation. Stabilization resistor is used for avoiding relay operation during CT saturation during through faults.  Its value is calculated on maximum through fault current of the protected equipment. 

Let us assume CT2 (Neutral side CT) saturates during through fault. It will not generate any output and will act as resistor as per its secondary winding resistance.

In this case let us assume percentage impedance of transformer to be 10%. Maximum through fault current will be 400A/10% = 4000A Primary (8A Secondary). If CT secondary resistance is 6 ohm and lead resistance is 4 ohm, Voltage developed in case of maximum fault current will be 8A x (4 + 6) = 80V. Now our requirement is that for this voltage relay should not operate. In other words stabilizing resistor should restrict the relay current below set value. 

Now keeping 150% safety margin the current produced by 120V throgh relay coil shall be 0.12A. For this requirement stabalizing resistor shold be 120V / 0.12A =  1000 ohm. In the above case of CT saturation, Voltage developed was 80V, the current through relay coil will be 80V / 1000 ohm = 0.08A. This is much below the set value of 0.12A. Therefore relay will not operate during this CT saturation, which meets our requirement.

Varistor:  Stablizing resistor is in series to relay circuit, it may have values upto 2 K ohm. During fault condition, there may be high voltage across the CT terminals due to higher value of relay circuit. To protect equipment (lCT, cables relays etc) and persons working in relay panels varistor is used to limit the voltage below ~300V.

Three Phase transformers: For three phase transformers the example is as below:

z

REF protection will not operate on phase to phase fault, as the vector sum of IR + IY + IB + IN shall be zero in fault case also. 

Similarly, REF protection can be used for 3-phase auto transformers as shown below:

Generally the relay is set to operate for Earth Fault current of ~15% of rated winding current. In this way it protects restricted protection of winding. Hence the name is called Restricted Earth Fault protection.