Advanced Power System Protection

Lecture No.10

Dr. Muhammad Kamran

Lecture contents

• Intelligent Electronic device

Definition

• The term ‘intelligent electronic device’ (IED) is not a clear-cut definition, as for example the term ‘protection relay’ is
• Broadly speaking, any electronic device that possesses some kind of local intelligence can be called an IED
• The functions of a typical IED can be classified into five main areas, namely protection, control, monitoring, metering and communications
• Some IEDs may be more advanced than the others, and some may emphasize certain functional aspects over others, but these main functionalities should be incorporated to a greater or lesser degree

• The protection functions of the IED evolved from the basic overcurrent and earth fault protection functions of the feeder protection relay (hence certain manufacturers named their IEDs ‘feeder terminals’)
• This is because a feeder protection relay is used on almost all cubicles of a typical distribution switchboard, and that more demanding protection functions are not required to enable the relay’s microprocessor to be used for control functions

• IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise/lower voltage levels in order to maintain the desired level
• Common types of IEDs include protective relaying devices, load tap changer controllers, circuit breaker controllers, capacitor bank switches, recloser controllers, voltage regulators, etc.
• Digital protective relays are primarily IEDs, using a microprocessor to perform several protective, control, and similar functions
• A typical IED can contain around 5-12 protection functions, 5-8 control functions controlling separate devices, an auto reclose function, self monitoring function, communication functions etc
• Hence, they are aptly named as Intelligent Electronic Devices.
• Some recent IEDs are designed to support the IEC61850 standard for substation automation, which provides interoperability and advanced communications capabilities

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• The protection functions are typically provided in discrete function blocks, which are activated and programmed independently
• Non-directional three-phase overcurrent (low-set, high-set and instantaneous function blocks, with low-set selectable as long time-, normal-, very-, or extremely inverse, or definite time)
• Non-directional earth fault protection

• Directional three-phase overcurrent (low-set, high-set and instantaneous function blocks, with low-set selectable as long time-, normal-, very-, or extremely inverse, or definite time)
• Directional earth fault protection
• Phase discontinuity protection
• Three-phase overvoltage protection

• Residual overvoltage protection
• Three-phase under voltage protection
• Three-phase transformer inrush/motor start-up current detector
• Auto-re closure function
• Under frequency protection
• Over frequency protection
• Synchro-check function
• Three-phase thermal overload protection

Control

• Control function includes local and remote control, and are fully programmable
• Local and remote control of up to twelve switching objects (open/close commands for circuit breakers, isolators, etc.)
• Control sequencing

Monitoring

• Monitoring includes the following functions:
• Circuit-breaker condition monitoring, including operation time counter, electric wear, breaker travel time, scheduled maintenance
• Trip circuit supervision
• Internal self-supervision
• Gas density monitoring (for SF6 switchgear)
• Event recording
• Other monitoring functions, like auxiliary power, relay temperature, etc.

Metering�

• Metering functions include:
• Three-phase currents
• Neutral current
• Three-phase voltages
• Residual voltage
• Frequency
• Active power
• Reactive power
• Power factor
• Energy
• Harmonics
• Transient disturbance recorder (up to 16 analog channels)
• Up to 12 analog channels

Communications

• Communication capability of an IED is one of the most important aspects of modern electrical and protection systems, and is the one aspect that clearly separates the different manufacturers’ devices from one another regarding their level of functionality
• See figure in next slide

Communication capabilities

• IEDs are able to communicate directly to a SCADA system
• Figure shows the present day concept of SCADA using IEDs connected through LAN and other network configurations

RS-485

• RS485--is a specialized interface that would not be considered standard equipment on today's home PC but is very common in the data acquisition world
• RS485 will support 32 drivers and 32 receivers (we are talking about bi-directional - half duplex - multi-drop communications over a single or dual twisted pair cable

Transformer Failure

Over current protection

• Protection against excess current was naturally the earliest protection system to evolve
• Over current protection, on the other hand, is directed entirely to the clearance of faults, although with the settings usually adopted some measure of overload protection may be obtained

Co-ordination procedure

• Correct overcurrent relay application requires knowledge of the fault current that can flow in each part of the network
• The data required for a relay setting study are:
• i. a one-line diagram of the power system involved, showing the type and rating of the protection devices and their associated current transformers
• ii. the impedances in ohms, percent or per unit, of all power transformers, rotating machine and feeder circuits

• iii. the maximum and minimum values of short circuit currents that are expected to flow through each protection device
• iv. the maximum load current through protection devices
• v. the starting current requirements of motors and the starting and locked rotor/stalling times of induction motors
• vi. the transformer inrush, thermal withstand and damage characteristics
• vii. decrement curves showing the rate of decay of the fault current supplied by the generators
• viii. performance curves of the current transformers

• The basic rules for correct relay co-ordination can generally be stated as follows:
• a. whenever possible, use relays with the same operating characteristic in series with each other
• b. make sure that the relay farthest from the source has current settings equal to or less than the relays behind it, that is, that the primary current required to operate the relay in front is always equal to or less than the primary current required to operate the relay behind it.

PRINCIPLES OF TIME/CURRENT GRADING

• Among the various possible methods used to achieve correct relay co-ordination are those using either time or overcurrent, or a combination of both
• The common aim of all three methods is to give correct discrimination
• That is to say, each one must isolate only the faulty section of the power system network, leaving the rest of the system undisturbed

Relay Grading

• The time interval that must be allowed between the operation of two adjacent relays in order to achieve correct discrimination between them is called the grading margin
• The grading margin depends on a number of factors:
• fault current interrupting time of the circuit breaker relay timing error
• all relays have errors in their timing compared to the ideal characteristic as defined in IEC 60255

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• overshoot time of the relay
• when the relay is de-energised, operation may continue for a little longer until any stored energy has been dissipated
• For example, an induction disc relay will have stored kinetic energy in the motion of the disc; static relay circuits may have energy stored in capacitors
• CT errors
• current transformers have phase and ratio errors due to the exciting current required to magnetise their cores
• The result is that the CT secondary current is not an identical scaled replica of the primary current

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• final margin on completion of operation
• the discriminating relay must just fail to complete its operation
• Some extra allowance, or safety margin, is required to ensure that relay operation does not occur.
• At one time 0.5s was a normal grading margin
• With faster modern circuit breakers and a lower relay overshoot time, 0.4s is reasonable, while under the best conditions even lower intervals may be practical
• The use of a fixed grading margin is popular, but it may be better to calculate the required value for each relay location.

Grading margin Calculation

Discrimination by Time

• In this method, an appropriate time setting is given to each of the relays controlling the circuit breakers in a power system to ensure that the breaker nearest to the fault opens first
• A simple radial distribution system is shown in Figure , to illustrate the principle

• Overcurrent protection is provided at B, C, D and E, that is, at the infeed end of each section of the power system
• Each protection unit comprises a definite-time delay overcurrent relay in which the operation of the current sensitive element simply initiates the time delay element
• Provided the setting of the current element is below the fault current value, this element plays no part in the achievement of discrimination

• The relay operation is sometimes described as an ‘independent definite-time delay relay’, since its operating time is for practical purposes independent of the level of overcurrent
• It is the time delay element, therefore, which provides the means of discrimination
• The relay at B is set at the shortest time delay possible to allow the fuse to blow for a fault at A on the secondary side of the transformer.
• After the time delay has expired, the relay output contact closes to trip the circuit breaker

• The relay at C has a time delay setting equal to t1 seconds, and similarly for the relays at D and E
• If a fault occurs at F, the relay at B will operate in “t” seconds and the subsequent operation of the circuit breaker at B will clear the fault before the relays at C, D and E have time to operate

• The time interval t1 between each relay time setting must be long enough to ensure that the upstream relays do not operate before the circuit breaker at the fault location has tripped and cleared the fault.
• The main disadvantage of this method of discrimination is that the longest fault clearance time occurs for faults in the section closest to the power source, where the fault level (MVA) is highest.

Discrimination by Current

• Discrimination by current relies on the fact that the fault current varies with the position of the fault because of the difference in impedance values between the source and the fault
• For a fault at F1, the system short-circuit current is given by:

paper insulated, lead covered (PILC) cables

• So, a relay controlling the circuit breaker at C and set to operate at a fault current of 8800A would in theory protect the whole of the cable section between C and B
• However, there are two important practical points that affect this method of co-ordination;
• a. it is not practical to distinguish between a fault at F1 and a fault at F2, since the distance between these points may be only a few meters, corresponding to a change in fault current of approximately 0.1%

• b. in practice, there would be variations in the source fault level, typically from 250MVA to 130MVA
• At this lower fault level the fault current would not exceed 6800A, even for a cable fault close to C
• A relay set at 8800A would not protect any part of the cable section concerned

• Discrimination by current is therefore not a practical proposition for correct grading between the circuit breakers at C and B
• However, the problem changes appreciably when there is significant impedance between the two circuit breakers concerned
• Consider the grading required between the circuit breakers at C and A in Figure
• Assuming a fault at F4, the short circuit current is given by:

• I= 6350/(Zs+ZL1)
• Zs→ Source Impedance = 0.485 ohm
• ZL1= cable impedance between C and B =0.24 ohm
• ZL2 = cable impedance between B and 4 MVA Transformer = 0.04Ω
• ZT = transformer impedance, =0.07 (11²/4)= 2.12Ω

• I =11/sqrt (3)X 2.885= 2200 Amp;

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• For this reason, a relay controlling the circuit breaker at B and set to operate at a current of 2200A plus a safety margin would not operate for a fault at F4 and would thus discriminate with the relay at A
• Assuming a safety margin of 20% to allow for relay errors and a further 10% for variations in the system impedance values, it is reasonable to choose a relay setting of 1.3 x 2200A, that is 2860A, for the relay at B

• Now, assuming a fault at F3, at the end of the 11kV cable feeding the 4MVA transformer, the short-circuit current is given in next slide;

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• As the fault MVA is shifted from 250 MVA to 130 MVA; the source impedance will be changed from 0.485 to 0.93 with the concept of base change;
• 250/130*0.485=0.93;
• Similarly ZL1 will be changed as in numerical.

Next lecture

• Over current protection will be continued