Date:
Showing posts with label protective relaying. Show all posts
Showing posts with label protective relaying. Show all posts

Thursday, December 17, 2020

What is the Advantage of IDMT in Protective Relaying?

 


In protective relaying there are two philosophies available to effectively achieve selectivity and coordination by time grading two philosophies are available, namely: 


  1. Definite time lag (DTL), or 
  2. Inverse definite minimum time (IDMT). 


Traditionally, design engineers have regarded medium- and low-voltage networks to be of lower importance from a protection view, requiring only the so-called simpler type of IDMT overcurrent and earth fault relays on every circuit. In many instances, current transformer ratios were chosen mainly based on load requirements, whilst relay settings were invariably left to the commissioning engineer to determine. Most of the times, the relay settings had been chosen considering the downstream load being protected without an effort to coordinate with the upstream relays. 


Read: Basic Guide in Power System Protection


However, experience has shown that there has been a total lack of appreciation of the fundamentals applicable to these devices. Numerous incidents have been reported where breakers have tripped in an uncoordinated manner leading to extensive network disruption causing longer down times or failed to trip causing excessive damage, extended restoration time and in some cases loss of life. 


In Definite Time Lag or DTL, the relays are graded using a definite time interval of approximately 0.5 s. The relay R3 at the extremity of the network is set to operate in the fastest possible time, whilst its upstream relay R2 is set 0.5 s higher. Relay operating times increase sequentially at 0.5 s intervals on each section moving back towards the source as shown below,


Definite Time Lag or DTL


The problem with this philosophy is, the closer the fault to the source the higher the fault current, the slower the clearing time – exactly the opposite to what we should be trying to achieve. 


Read: IEC 61850 Logical Nodes and Data Classes in Power System Automation Data Modelling


On the other hand, inverse curves as shown in the figure below which describes operating faster at higher fault currents and slower at the lower fault currents, thereby offering us the features that we desire. This explains why the IDMT philosophy has become standard practice throughout many countries over the years



Although not appreciated by many engineers, the widespread use of inverse definite minimum time overcurrent and earth fault (IDMT OCEF) relays as the virtual sole protection on medium- and low-voltage networks requires as much detailed study and applications knowledge as does the more sophisticated protection systems used on higher voltage networks.  


Applying IDMT in the System


When deciding to apply IDMT relays to a network, a number of important points have to be considered. Firstly, it must be appreciated that IDMT relays cannot be considered in isolation. They have to be set to coordinate with both upstream and downstream relays. 


Their very purpose and being is to form part of an integrated whole system. Therefore, whoever specifies this type of relay should also provide the settings and coordination curves as part of the design package to show that he knew what he was doing when selecting their use. This very important task should not be left to others and once set, the settings must not be tampered (even by the operating staff ) as otherwise coordination is lost.


Minimum Grading Intervals


To engineers planning the protection for a medium- to low-voltage network and wishing to adopt the widespread use of the IDMT OCEF relay, the above can be summarized as follows: 

  • Design networks with a minimum number of grading levels possible. 
  • Choose CT ratios based on fault current – not load current. 
  • Consider using 1 A secondary. 
  • Check CT magnetization curves for knee-point voltage and internal resistance. 
  • Connect ammeters, etc. onto own metering cores. 
  • Provide relay settings and coordination curves as part of the design package. 
  • Be careful when choosing relay plug tap setting on electromechanical relays. The lower the tap, the higher the burden. 
  • Relays should not pick-up for healthy conditions such as permissible transient overloads, starting surges and reconnection of loads, which have remained connected after a prolonged outage. 
  • Care should also be taken that the redistribution of load current after tripping does not cause relays on healthy circuits to pick-up and trip. 
  • HV IDMT relays on transformers should trip both HV and LV breakers. 
  • Normal inverse curves should not be selected for overload protection. Rather use the inverse characteristic for this duty. 
  • Take advantage of the additional features offered by the modern electronic relays, e.g. fixed very low burden, integral high-set, breaker fail and busbar blocking protections, event memory, etc. However, remember, one has to do the same calculation exercises for settings and draw coordination curves whether the relays are of the electronic or electromechanical design. 
  • Finally, if the switchgear suppliers also manufacture relays, do not expect them to do the protection application settings free of charge as part of the service. If this is required, specify this as a separate cost item in the specification. 


Many problems down the line can be avoided and the performance, efficiency and safety of the plant improved if a protection engineer is included in the design team, if not full time, but at least to do an audit on the proposals. Finally, remember – while  IDMT relays are the most well known and the cheapest, they are in fact the most difficult relays to set. 


Reference: 

Practical Power System Protection | Download

Authors: 
  • Les Hewitson
  • Mark Brown PrEng, DipEE, BSc (ElecEng), Senior Staff Engineer, IDC Technologies, Perth, Australia  
  • Ben Ramesh Ramesh and Associates, Perth, Australia
Series editor: 
  • Steve Mackay FIE(Aust), CPEng, BSc (ElecEng), BSc (Hons), MBA, Gov. Cert. Comp., Technical Director – IDC Technologies.

Saturday, November 28, 2020

How to Convert IEC 60044-1 Standard Protection Classification to IEEE Standard Voltage Rating?

 

MiCom P63x Protection Relay


There are a series of protection relays such as MiCom protection relays that are compatible with ANSI/IEEE CTs as specified in the IEEE C57.13 standard. The applicable class for protection is class "C", which specifies a non air-gapped core. The CT design is identical to IEC class P but the rating is specified differently. 


The IEEE C class standard voltage rating required will be lower than an IEC knee-point voltage. This is because the IEEE voltage rating is defined in terms of useful output voltage at the terminals of the CT, whereas the IEC knee-point voltage includes the voltage drop across the internal resistance of the CT secondary winding added to the useful output. The IEC knee-point is also typically 5% higher than the IEEE knee-point. 


Read: What are the Conditions in Selecting Current Transformer in Protective Relaying


Where IEEE standards are used to specify CTs, the C class voltage rating can be checked to determine the equivalent knee-point voltage (Vk) according to IEC. 


The equivalence formula is: 


Vk = (C x 1.05) + (Ksc x In x Rct)

Vk = (C x 1.05) + (100 x Rct)


Note: IEEE CTs are always 5A secondary rated, i.e. In =5A, and are defined with an accuracy limit factor of 20, i.e. Kssc =20.


Read: Types and Classes of Current Transformers According to IEC 60441 


The following table allows C57.13 ratings to be converted to a typical IEC knee-point voltage:


  • * Assuming 0.002/turn typical secondary winding resistance for 5A CTs

Reference: 

Friday, November 27, 2020

Types and Classes of Current Transformers According to IEC 60441

Substation Current Transformer


The behavior of inductive CTs in accordance with IEC 60044-1 and IEEE C57.13 is specified for steady-state symmetrical AC currents. The more recent standard IEC 60044-6 is the only standard that specifies the performance of inductive CTs (classes TPX, TPY and TPZ) for currents containing exponentially decaying DC components of the defined time constant. This section summarises the various classes of CTs.


IEC 60044-1


Class P Class P current transformers are typically used for general applications, such as overcurrent protection, where a secondary accuracy limit greatly in excess of the value to cause relay operation serves no useful purpose. Therefore a rated accuracy limit of 5 will usually be adequate. When relays, such as instantaneous ‘high set’ overcurrent relays, are set to operate at high values of overcurrent, say 5 to 15 times the rated current of the transformer. 


Read: Protection Relays in Power System


The accuracy limit factor must be at least as high as the value of the setting current used in order to ensure fast relay operation. 





Rated output burdens higher than 15VA and rated accuracy limit factors higher than 10 are not recommended for general purposes. It is possible, however, to combine a higher rated accuracy limit factor with a lower-rated output and vice versa. 


When the product of these two exceeds 150, the resulting current transformer may be uneconomical and/or of unduly large dimensions. 


Class P current transformers are defined so that, at rated frequency and with rated burden connected, the current error, phase displacement and composite error shall not exceed the values given in the table below. 




Class PR 


A current transformer with less than 10% remanence factor due to small air gaps for which, in some cases, a value of the secondary loop time constant and/or a limiting value of the winding resistance may also be specified.  


Class PX 


A current transformer of low leakage reactance for which knowledge of the transformer secondary excitation characteristic, secondary winding resistance, secondary burden resistance and turns ratio is sufficient to assess its performance in relation to the protective relay system with which it is to be used. 


Class PX is the definition in IEC 60044-1 for the quasi-transient current transformers formerly covered by class X of BS 3938, commonly used with unit protection schemes. 


Class PX type CTs are used for high impedance circulating current protection and are also suitable for most other protection schemes. 


IEC 60044-6


Class TPS 


Protection current transformers specified in terms of complying with class TPS are generally applied to unit systems where the balancing of outputs from each end of the protected plant is vital. This balance, or stability through fault conditions, is essential of a transient nature and thus the extent of the unsaturated (or linear) zones is of paramount importance. 


It is normal to derive, from heavy current test results, a formula stating the lowest permissible value of Vk if the stable operation is to be guaranteed.


The performance of class TPS current transformers of the low (secondary) reactance type is defined by IEC 60044-6 for transient performance. In short, they shall be specified in terms of each of the following characteristics: 

  • Rated primary current
  • Turns ratio (the error in turns ratio shall not exceed ±0.25%)
  • Secondary limiting voltage
  • The resistance of secondary winding Class TPS CTs are typically applied for high impedance circulating current protection.

Class TPX 

The basic characteristics for class TPX current transformers are generally similar to those of class TPS current transformers except for the different error limits prescribed and possible influencing effects which may necessitate a physically larger construction. 



Class TPX CTs have no air gaps in the core and therefore a high remanence factor (70-80% remanent flux). The accuracy limit is defined by the peak instantaneous error during the specified transient duty cycle. Class TPX CTs are typically used for line protection.


Class TPY

Class TPY CTs have a specified limit for the remanent flux. The magnetic core is provided with small air gaps to reduce the remanent flux to a level that does not exceed 10% of the saturation flux. 

They have a higher error in current measurement than TPX during unsaturated operation and the accuracy limit is defined by peak instantaneous error during the specified transient duty cycle. Class TPY CTs are typically used for line protection with auto-reclose.

Class TPZ 

For class TPZ CTs the remanent flux is practically negligible due to large air gaps in the core. These air gaps also minimize the influence of the DC component from the primary fault current but reduce the measuring accuracy in the unsaturated (linear) region of operation. 

The accuracy limit is defined by peak instantaneous alternating current component error during single energization with maximum DC offset at specified secondary loop time constant. Class TPZ CTs are typically used for special applications such as differential protection of large generators. 


Reference: 

Sunday, November 15, 2020

The Fundamental Theory of Generator Protection

 

Steam Turbine Generator



There are many abnormal conditions that can result in damage to the generator. Some of these conditions are a result of a failure within the generator or one of its subsystems and others originate in the power system itself. The following table summarizes the types of failures that can occur and the associated methods of protection. 


Stator Ground Faults 


The most commonly occurring failure of the stator winding is a break down of the insulation between a single phase and ground. Undetected, this fault can quickly damage the generator core. Fires are also possible on air-cooled machines. The ability of the stator differential element to detect a ground fault is a function of the available ground fault current. As such, dedicated ground fault protection is generally required for the stator. 


Generators provide the energy used by all of the loads in the power system and much of the reactive power needed to supply the inductive elements thereby maintaining the system voltage at nominal values. Power systems have little capacity for energy storage. As such, lost generation must be immediately replaced or an equivalent amount of load must be shed. It is of primary importance that the protection system for the generator is highly secure during external disturbances. 


The generator is one component of a complex system that includes a prime mover, an exciter, and various auxiliary systems. In addition to the detection of short circuits, the generator protection IED is therefore required to detect an array of abnormal conditions that could damage the generator or one of it’s subsystems. Generators can be classified into two major types: induction and synchronous. Induction machines are typically smaller in size, ranging down to as little as one hundred kVA, and are normally driven from a reciprocating engine. Synchronous machines range in size from several hundred kVA to 1200 MVA. 


Synchronous generators may be driven by a variety of prime movers, including reciprocating engines, hydro turbines, combustion turbines, and large steam turbines. The type of turbine affects the design of the generator and can therefore impact protection requirements. The generator size and it’s method of grounding also affect its protection requirements. Small and medium sized machines are often directly connected to a distribution network (direct connected). In this configuration several machines can be connected to the same bus. Large machines are usually connected via a dedicated power transformer to the transmission network (unit connected). 


A second power transformer at the generator terminals provides auxiliary power for the unit. Generators are grounded in order to control from damaging voltage transients and to facilitate the operation of protection functions. Direct-connected generators are often grounded through a low impedance that limits the ground fault current to 200-400 amps. Unit connected machines are typically grounded through a high impedance that limits the current to less than 20 amps.


For direct connected, low impedance grounded machines, a current-based detection method is used. This protection needs to be fast and sensitive for internal ground faults while at the same time secure during external disturbances. This can be achieved using a restricted ground fault element or a neutral directional element. The restricted ground fault element implemented in the G30 and G60 employs a symmetrical component restraint mechanism that provides a high degree of security during external faults with significant CT saturation.


For unit connected, high impedance grounded machines, voltage-based methods are often used to provide ground fault detection. Using a combination of fundamental and third harmonic voltage elements, ground fault coverage for 100% of the stator winding can be achieved. GE relays employ a third harmonic voltage element that responds to the ratio of the neutral and terminal values of the third harmonic. This element is simple to set and insensitive to variations in third harmonic levels under normal operation.


Read: What are the Different Generator Cooling System in Power Plants


Stator Phase Faults


Phase faults not involving ground can occur at the winding end or within a slot on in machines having coils of the same phase in the same slot. Although a phase fault is less likely than a ground fault, the current resulting from this fault is not limited by the grounding impedance. As such it is critical that these faults be detected quickly so as to limit the damage to the machine. Since the system XOR ratio is particularly high at the generator, the stator differential element is particularly susceptible to CT saturation due to the DC component of the current during an external disturbance. The G60 stator differential algorithm adds additional security in the format of a directional check when CT saturation is suspected due to either the AC or DC components of the current. 


Overload/Thermal


The Figure below shows the permissible short-time loading limits of a generator according to C50.13-2004. Loading beyond these limits will quickly damage the machine. An overcurrent element with a very-inverse characteristic can be used to ensure that the generator is operated within permissible limits. GE IED’s are also equipped with RTD inputs. In addition to detection of overloading, RTDs can detect overheating due to a cooling system failure or localized overheating due to a failure of the insulation between the stator core laminations.





Tripping Faults


There are a variety of faults or disturbances for which the generator protection IED must operate. For each fault type there are generally a set of actions that are carried out. These include tripping the generator breaker, tripping the field breaker, transfer of the auxiliaries, and tripping the prime mover. For example, an overfluxing condition requires a trip of the generator and field breaker, a transfer initiation, but no trip to the prime mover. This allows the machine to be resynchronized if the problem is resolved quickly. Internal programmable logic allows the tripping logic to be easily implemented. Additionally there are instances where the generator powerhouse is at a substantial distance from the switchyard. Using peer-peer messaging, tripping and status signals can be sent directly from the relay over fiber to a controller such as a C30 located adjacent to the generator breaker


Source: GE Multilin www.gemultilin.com

Download the whole document here


What are the IEEE/ANSI Device Numbers Used in Power System Protection ?

Generator Protection
Sample Application in Generator Protection 
(Photo Credit: General Electic)

In power system, the protection and control of equipment is represented by ANSI device numbers, with corresponding suffix letters when necessary, in relation to the functions they perform. The numbers are based on a system that is adopted by a standard for automatic switchgear by Institute of Electrical and Electronics Engineers (IEEE), and incorporated in American Standard C37.2-1996. 


This system is used  along with the diagrams that can be found in instruction books and in specifications. The International Electrotechnical Commission (IEC) standards 617 and 60617 also provide different symbols and terminology for most of the device numbers that are defined by C37.2. 


The second portion of this document provides a brief overview of a few of the more common IEC symbols used.


Read: Related Articles in Fault Analysis


1 - Master Element

2 - Time Delay Starting or Closing Relay

3 -  Checking or Interlocking Relay

4 - Master Contactor

5 - Stopping Device

6 - Starting Circuit Breaker

7 - Rate of Change Relay

8 - Control Power Disconnecting Device

9 - Reversing Device

10 - Unit Sequence Switch

11 - Multifunction Device

12 - Overspeed Device/Protection

13 - Synchronous-Speed Device

14 - Under-speed Device

15 - Speed or Frequency Matching Device

16 - Communication Networking Device

17 - Shunting or Discharge Switch

18 - Accelerating or Decelerating Device

19 - Motor Starter / Starting-to-Running Transition Contactor

20 - Electrically-Operated Valve

21 - Distance Relay

21G - Ground Distance

21P -  Phase Distance

22 - Equalizer Circuit Breaker

23 - Temperature Control Device

24 - Volts-per-Hertz Relay / Overfluxing

25 - Synchronizing or Synchronism-Check Device

26 - Apparatus Thermal Device

27 - Undervoltage Relay

27 TN  - Phase Undervoltage

27 X  - Third Harmonic Neutral Undervoltage

27 AUX - Undervoltage Auxiliary Input

27/ 27 X - Bus/Line Undervoltage

28 - Flame Detector

29 - Isolating Contactor

30 - Annunciator Relay

31 - Separate Excitation Device

32 - Directional Power Relay

32 L - Low Forward Power

32 N - Wattmetric Zero-Sequence Directiona

32 P - Directional Power

32 R - Reverse Power

33 - Position Switch

34 - Master Sequence Device

35 - Brush-Operating or Slip-ring Short Circuiting Device

36 - Polarity or Polarizing Voltage Device

37-  Undercurrent or Underpower Relay

37P - Underpower

38 -  Bearing Protective Device / Bearing Rtd

39 - Mechanical Condition Monitor 

40 - Field Relay / Loss of Excitation 

41 -  Field Circuit Breaker 

42 -  Running Circuit Breaker 

43 -  Manual Transfer or Selector Device 

44 - Unit Sequence Starting Relay

45 - Atmospheric Condition Monitor

46 -  Reverse-Phase or Phase Balance Current Relay or Stator Current Unbalance 

47 - Phase-Sequence or Phase Balance Voltage Relay

48 - Incomplete Sequence Relay / Blocked Rotor 

49 - Machine or Transformer Thermal Relay / Thermal Overload 

49 - RTD RTD Biased Thermal Overload 


Read: What are the Conditions in Selecting Current Transformer in Protective Relaying


50 - Instantaneous Overcurrent Relay 50BF Breaker Failure 

50 - DD Current Disturbance Detector 

50G - Ground Instantaneous Overcurrent 

50N -  Neutral Instantaneous Overcurrent 

50P - Phase Instantaneous Overcurrent 

50_2 -  Negative Sequence Instantaneous Overcurrent 

50/27 -  Accidental Energization 

50/74 - Ct Trouble 

50/87 - Instantaneous Differential 50EF End Fault Protection 

50IG - Isolated Ground Instantaneous Overcurrent 

50LR - Acceleration Time 

50NBF -  Neutral Instantaneous Breaker Failure 

50SG - Sensitive Ground Instantaneous Overcurrent 

50SP -  Split Phase Instantaneous Current 

51 -  Ac Time Overcurrent Relay

51 - Overload 

51G - Ground Time Overcurrent 

51N - Neutral Time Overcurrent 

51P - Phase Time Overcurrent 

51V - Voltage Restrained Time Overcurrent 

51R - Locked / Stalled Rotor

51_2 - Negative Sequence Time Overcurrent 

52 - Ac Circuit Breaker 

53 - Exciter or Dc Generator Relay 

54 - Turning Gear Engaging Device 

55 - Power Factor Relay 

56 - Field Application Relay 

57 - Short-Circuiting or Grounding Device 

58 - Rectification Failure Relay 

59 - Overvoltage Relay 

59B - Bank Phase Overvoltage 

59P - Phase Overvoltage 

59N - Neutral Overvoltage 

59NU - Neutral Voltage Unbalance 

59P - Phase Overvoltage 

59X - Auxiliary Overvoltage 

59_2 - Negative Sequence Overvoltage

60 - Voltage or Current Balance Relay 

60N - Neutral Current Unbalance 

60P - Phase Current Unbalance 

61 - Density Switch or Sensor 

62 - Time-Delay Stopping or Opening Relay 

63 - Pressure Switch Detector 

64 - Ground Protective Relay 

64F - Field Ground Protection 

64S - Sub-harmonic Stator Ground Protection 

64TN - 100% Stator Ground 

65 - Governor 

66 - Notching or Jogging Device/Maximum Starting Rate/Starts Per Hour/Time Between Starts 

67 - Ac Directional Overcurrent Relay 

67G - Ground Directional Overcurrent 67N Neutral Directional Overcurrent 

67P - Phase Directional Overcurrent 

67SG - Sensitive Ground Directional Overcurrent 

67_2 - Negative Sequence Directional Overcurrent 

68 - Blocking Relay / Power Swing Blocking 

69 - Permissive Control Device 

70 - Rheostat 

71 - Liquid Switch 

72 - Dc Circuit Breaker 

73 - Load-Resistor Contactor 

74 - Alarm Relay 

75 - Position Changing Mechanism

76 - Dc Overcurrent Relay 

77 - Telemetering Device 

78 -  Phase Angle Measuring or Out-of-Step Protective Relay 

78V - Loss of Mains 

79 - Ac Reclosing Relay / Auto Reclose 

80 - Liquid or Gas Flow Relay 

81 - Frequency Relay 

81O - Over Frequency 

81R - Rate-of-Change Frequency 

81U - Under Frequency 

82 - Dc Reclosing Relay 

83 - Automatic Selective Control or Transfer Relay 

84 - Operating Mechanism 

85 - Carrier or Pilot-Wire Receiver Relay 

86 - Locking-Out Relay 

87 - Differential Protective Relay 

87B - Bus Differential 

87G - Generator Differential 

87GT - Generator/Transformer Differential 

87LG - Ground Line Current Differential 

87S - Stator Differential 

87S - Percent Differential 

87L - Segregated Line Current Differential 

87M - Motor Differential 

87O - Overall Differential 

87PC - Phase Comparison 

87RGF - Restricted Ground Fault 

87T - Transformer Differential 

87V - Voltage Differential 

88 - Auxiliary Motor or Motor Generator 

89 - Line Switch 

90 - Regulating Device 

91 - Voltage Directional Relay 

92 - Voltage And Power Directional Relay 

93 - Field-Changing Contactor 

94 - Tripping or Trip-Free Relay 

50/74 - Ct Supervision 2

7/50 - Accidental Generator Energization 

27TN/59N - 100% Stator Earth Fault

Download the whole document here

Tuesday, July 14, 2020

What are the Conditions in Selecting Current Transformer in Protective Relaying


Current Transformer

Current Transformer

The current transformer is one of the main essential components in protective relaying. Along with Potential Transformers (PT), this device is also the key element that will detect any abnormalities in the system. When it comes to protective relaying applications, the CT that will be used is those with large cores that allow the replication of the primary current during fault condition (high primary current). 

However, we should not rely on the physical sizes of selecting the right unit to use. We need to satisfy the essential requirements to prevent undesirable results. In order to achieve this goal, we need to comply with two conditions, namely: 

Condition 1: The current rating of the primary must be close to the full load current of the load or the system that it protects. For example, if the full load current is 387 Amperes, then it is better to choose a CT that has a conversion ratio of 400:5. 

Condition 2: Calculate the secondary voltage at the time of the fault to determine whether the CT will saturate during a fault condition. In this case, even if we satisfy condition 1, we need to select the next higher rating and do the same process. 

How to determine CT Saturation?

To determine whether a CT will saturate in a certain condition, we need to find the following values: 
  • Amount of fault current 
  • CT Secondary Resistance
  • Wire resistance that connects CT and the protection relay
  • The Burden resistance of the relay. 

Example: 

A protection relay is to be installed to a motor with full load current rating of 290. A CT with conversion ratio of 300:5 will be used and it has a total distance of 20 meters from the relay. The wire has a resistance of 1.5 ohms per kilometers. If the CT secondary resistance is 0.09 ohms and the relay burden resistance is 0.005 ohms. Determine if the CT ratio will saturate based on the curve given below. 

Note: Assume that the fault current in the system is 3.5 kA.



Solution:

In this case, we will enumerate the given values as, 
  • CT to be used is 300 : 5
  • Fault current = 3,500 Amperes
  • CT secondary resistance = 0.090 ohms
  • Wire distance to relay = 20 mtrs rated @ 1.5 ohms/ km
  • Relay burden resistance = 0.006 ohms

Calculate the wire resistance: 

Rwire = (2 x 20 m) x 1.5 ohms/ km 
                             1000 

Rwire = 0.06 ohms


Calculate the total burden

Total Burden = RCT (secondary) + Rwire + R relay

Total Burden = 0.090 + 0.06 + 0.006 = 0.156 ohms

Calculate the Secondary Voltage in the event of fault. 

V = (Total Burden * Fault Current)/ CT ratio

V = (0.156 * 3,500) / 60

V = 9.1 Volts

Check the CT Curve if the secondary voltage in the event of fault is below the KNEE POINT. 


The value of secondary voltage in the event of fault is 9.1 Volts which is below the knee point. Therefore, we can accept the 300:5 CT given in the problem. Otherwise, we will choose the next higher value and do the same process. 

Popular Posts

Select Topics