Power system protection and switchgear OBJECTIVES :

In this paper, we plan to teach the following: 1. Fundamental principles of fuse and over current protection and application to feeder and motor protection. 2. Fundamental principles of distance relaying and application to transmission system protection. 3. Fundamental principles of differential protection and application to transformer, busbar and generator armature winding protection. 4. Role of Current and Voltage transformers in power system protection.

5. Relay co-ordination in transmission and distribution system. 6. Introduction to Numerical relaying. DSP fundamentals like aliasing, sampling theorem, Discrete Fourier Transform and application to current and voltage phasor estimation. 7. Numerical relaying algorithms for over current, distance and differential protection with application to transmission system, transformer and bus bar protection. 8. The various ear thing practices usage of symmetrical components to estimate fault current and fault MVA. 9. The relays, protection scheme and solid state relays. 10. The methods of circuit breaking, various arc theories, arcing phenomena, capacitive and inductive breaking. 11. The construction and operation of different circuit breakers.

Syllabus 3 0 0 3

UNIT – I PROTECTIVE RELAYS 9 Principles and need for protective schemes – nature and causes of faults – types of faults Power system earthling - Zones of protection and essential qualities of protection –Protection scheme – construction and characteristics of relays – over current relays –directional, distance and differential relays – under frequency relays – negative sequencerelays – static relays – microprocessor based relays. UNIT - II APPARATUS PROTECTION 9 Apparatus protection – generator and transformer protection – protection of bus bars,transmission lines, CT's & PT's and their application in protective schemes UNIT - III THEORY OF CIRCUIT INTERRUPTION 9 Physics of arc phenomena and arc interruption. Restriking voltage & Recovery voltage,rate of rise of recovery voltage, current chopping, interruption of capacitive current,resistance switching – DC circuit breaking. UNIT - IV CIRCUIT BREAKERS 9 Switch gear – fault clearing process – interruption of current – Types of Circuit Breakers– Air blast, oil, SF6 and Vacuum circuit breakers – comparative merits of different circuitbreakers – Testing of circuit breakers – Circuit breaker ratings. UNIT - V PROTECTION AGAINST OVER VOLTAGES 9 Causes of over voltages – methods of protection against over voltages – ground wires,Peterson coil, surge absorbers, surge diverters – relay co-ordination – selection ofprotective system – Insulation co-ordination. Lecture : 45, Tutorial : 0, TOTAL : 45 REFERENCE BOOKS 1 Sunil S. Rao, ‘Switchgear and Protection’, Khanna publishers, New Delhi, 1986. 2 C.L. Wadhwa, ‘Electrical Power Systems’, New Age International (P) Ltd., 2000. 3 M.L. Soni, P.V. Gupta, V.S. Bhatnagar, A. Chakrabarti, ‘A Text Book on Power System Engineering’, Dhanpat Rai & Co., 1998. 4 Badri Ram, Vishwakarma, ‘Power System Protection and Switchgear’, Tata McGraw Hill, 2001. 5 B. Ravindranath, and N. Chander, ‘Power System Protection & Switchgear’, New Age Publishers, 1977.

UNIT-1 PROTECTIVE RELAYS

Objectives In this lecture: We will provide an overview of electrical energy systems.

Make a case for protection systems.

Describe necessity of apparatus and system protection

. Define a relay element.

Discuss evolution of relays from electromechanical to numerical relay.

Overview of Electrical Energy Systems Electrical energy systems consists of various equipments connected together. Typically, power is generated at lower voltages (a few kV) (3-phase ac voltage source) which is stepped up by a transformer and fed into a transmission grid. Thermal power should be generated at pit heads and hydro power at reservoirs. A transmission grid is a meshed network of high voltage lines and transformers. It can have multiple voltage levels like 400 kV, 220 kV, etc. The power is delivered to load centers which may be far off (even thousands of km's apart).

Fig shows the western region grid of India. It can be seen that large amount of generation is concentrated in the eastern end while large load centers are concentrated in the western end. The power is transferred through the ac network and HVDC lines. At load centers, voltage levels are stepped down by step down transformers in multiple stages and finally power is delivered to the end user by a distribution system which is mostly radial (no loops) in nature. A unique feature of electrical energy systems is its natural mode of synchronous operation. It implies that during steady state the electrical frequency is same all

through the system irrespective of the geographical location. This closely knits the system together. We can perceive all generators acting in tandem like the ballet dancers in a dance. They may occupy different angular positions, but all machines rotate at the same electrical speed. This close knitting implies an embedded interaction of generators through the transmission network which is governed by the differential and algebraic equations of the apparatus and interconnects. This aspect is referred to as the system behavior. This system has to be protected from abnormalities which is the task of protection system.

Introduction Electrical power system operates at various voltage levels from 415 V to 400 kV or even more. Electrical apparatus used may be enclosed (e.g., motors) or placed in open (e.g., transmission lines). All such equipment undergo abnormalities in their life time due to various reasons. For example, a worn out bearing may cause overloading of a motor. A tree falling or touching an overhead line may cause a fault. A lightning strike (classified as an act of God!) can cause insulation failure. Pollution may result in degradation in performance of insulators which may lead to breakdown. Under frequency or over frequency of a generator may result in mechanical damage to it's turbine requiring tripping of an alternator. Even otherwise, low frequency operation will reduce the life of a turbine and hence it should be avoided. It is necessary to avoid these abnormal operating regions for safety of the equipment. Even more important is safety of the human personnel which may be endangered due to exposure to live parts under fault or abnormal operating conditions. Small current of the order of 50 mA is sufficient to be fatal! Whenever human security is sacrificed or there exists possibility of equipment damage, it is necessary to isolate and de-energize the equipment. Designing electrical equipment from safety perspective is also a crucial design issue which will not be addressed here. To conclude, every electrical equipment has to be monitored to protect it and provide human safety under abnormal operating conditions. This job is assigned to electrical protection systems. It encompasses apparatus protection and system protection. Protective Device Operation

The protective device usually consists of several elements that are arranged to test the system condition, make decisions regarding the normality of observed variables, and take action as required. These elements are depicted graphically in Figure 1.3.

Figure 1.3 Protective device functional elements.

The protective system always measures certain system quantities, such as voltages and currents, and compares these system quantities, or some combination of these quantities, against a threshold setting that is computed by the protection engineer and is set into the device. If this comparison indicates an alert condition, a decision element is triggered. This may involve a timing element, to determine the permanence of the condition, and may require other checks on the system at other points in the network. Finally, if all checks are satisfied, an action element is released to operate, which usually means that circuit breakers are instructed to open and isolate a section of the network.

The time required to take any necessary corrective action is called the clearing time and is defined as follows:

TC = TP + Td + Ta (1.1)

where T, = clearing time Tp = comparison time Td = decision time

Ta = action time, including circuit breaker operating time. The clearing time is very important since other protective systems in the

network may be time-coordinated with this protective device in order to ensure that only the necessary portions of the network are interrupted. There is an important message here, namely, that many protective devices will observe a given disturbance and many of them will find that disturbance to exceed their threshold settings. Each device should have some kind of restraint to allow those closest to the disturbance to trip first. Time is one kind of restraint that is often used. Other restraint mechanisms will be discussed later.

Clearing time is also important because some disturbances, such as short circuits, must be cleared promptly in order to preserve system stability. This depends on many factors, including the location and type of disturbance. However, it is a general rule that abnormal system conditions must be corrected, and speed of correction is always important. DEFINITIONS USED IN SYSTEM PROTECTION In this section we define certain terms which are used in system protection engineering. Other, more specific terms, will be introduced later, as required.

Protective relaying is the term used to signify the science as well as the operation of protective devices, within a controlled strategy, to maximize service continuity and minimize damage to property and personnel due to system abnormal behavior. The strategy is not so much that of protecting the equipment from faults, as this is a design function, but rather to protect the normal system and environment from the effect of a system component which has become faulted. Reliability of a protective system is defined as the probability that the system will function correctly when required to act. This reliability has two aspects: first, the system must operate in the presence of a fault that is within its zone of protection and, second, it must refrain from operating unnecessarily for faults outside its protective zone or in the absence of a fault [2]. Security in protective systems is a term sometimes used to indicate the ability of a system or device to refrain from unnecessary operations. Often we use security as a generic term to indicate that the system is operating correctly, whereas reliability is usually taken to be a quantifiable variable. Sensitivity in protective systems is the ability of the system to identify an abnormal condition that exceeds a nominal "pickup" or detection threshold value and which initiates protective action when the sensed quantities exceed that threshold.

Selectivity in a protective system refers to the overall design of protective strategy wherein only those protective devices closest to a fault will operate to remove the faulted component. This implies a grading of protective device threshold, timing, or operating characteristics to obtain the desired selective operation. This restricts interruptions to only those components that are faulted. Protection zones (primary protection zones) are regions of primary sensitivity. Figure 1.4 shows a small segment of a power system with protection zones enclosed by dashed lines. Coordination of protective devices is the determination of graded settings to achieve selectivity. Primary relays (primary sensitivity) are relays within a given protection zone that should operate for prescribed abnormalities within that zone. In Figure 1.4, for example, consider a fault on line JK. For this condition, relays supervising breakers J and K should trip before any others and these relays are called primary relays. Backup relays are relays outside a given primary protection zone, located in an adjacent zone, which are set to operate for prescribed abnormalities within the given primary protection zone and independently of the primary relays. For example, suppose a fault on line JK of Figure 1.4 cannot be cleared by breaker J due to relay or breaker J malfunc-

17

tion. Assume that breaker K operates normally leaving the fault connected to the bus terminated by breakers IJM. Backup relays at locations I and M should be set to operate for the fault on line JK, but only after a suitable delay that would allow breaker J to open first, if possible. Local backup relays are an alternate set of relays in a primary protection zone that operate under prescribed conditions in that protection zone. Often such local backup relays are a duplicate set of primary relays set to operate independently for the same conditions as the primary set. This constitutes an OR logic trip scheme and is an effective safeguard against relay failures. Undesired tripping (false tripping) results when a relay trips unnecessarily for a fault outside its protection zone or when there is no fault at all. This can occur when the protective system is set with too high a sensitivity. Such operation may cause an unnecessary load outage, for example, on a radial circuit, or may cause overloading of adjacent lines of a network. Thus, in some cases, unnecessary tripping is merely an inconvenience, which, although undesirable, may not cause serious damage or overloading. In other cases, where an important line is falsely tripped, it can lead to cascading outages and very serious consequences. Failure to trip is a protective system malfunction in which the protective system fails to take appropriate action when a condition exists for which action is required. This type of failure may result in extensive damage to the faulted component if not rectified by backup protection.

Other definitions used in system protection are given in [2], which is a standard for such definitions in the United States. Many of these definitions will be introduced as needed for clarity and precision.

Figure 1.4 One line diagram of a system showing primary protection zones [3].

Keypoint: Types of Protection Protection systems can be classified into apparatus protection and system protection Apparatus Protection Apparatus protection deals with detection of a fault in the apparatus and consequent protection. Apparatus protection can be further classified into following: Transmission Line Protection and feeder protection Transformer Protection Generator Protection Motor Protection Busbar Protection System Protection

System protection deals with detection of proximity of system to unstable operating region and consequent control actions to restore stable operating

point and/or prevent damage to equipments. Loss of system stability can lead to partial or complete system blackouts. Under-frequency relays, out-of-step

protection, islanding systems, rate of change of frequency relays, reverse power flow relays, voltage surge relays etc are used for system protection. Wide Area Measurement (WAM) systems are also being deployed for system protection.

Control actions associated with system protection may be classified into preventive or emergency control actions.

Analogy with Functioning of a Human being A human being is a complex system that performs through various apparatus like legs, hands, eyes, ears, heart, bones, blood vessels etc. The heart is analogous to an electrical generator and stomach to the boiler. The eating process provides raw material to generate calories. The power generated is pumped by heart through a complex network of blood vessels. The primary transmission is through arteries and veins. Furthermore, distribution is through fine capillaries. The system operator is the brain which works on inputs of eyes, ears, skin etc. Diagnosing abnormality in any of these organs and taking remedial measures can be thought of as job of "apparatus protection". However, does this cover the complete gambit of anomalies? Are fever, infection etc, a specific apparatus problem? Why does it cause overall deterioration in functioning of the human being? The answer lies in the fact that the system which encompasses body has also abstraction like the mind. Overall health is not just an aggregation of apparatus.

It is something much more complex. It involves complex process and associated dynamics (biological, chemical, mechanical etc.) and control. Thus, protecting a system is not just apparatus protection but something much more. Since we cannot define this "much more" clearly, it is complex and challenging. Monitoring of system behavior, taking corrective measures to maintain synchronous operation and protecting the power system apparatus from harmful operating states is referred as system protection. What is a Relay? Formally, a relay is a logical element which processes the inputs (mostly voltages and currents) from the system/apparatus and issues a trip decision if a fault within the relay's jurisdiction is detected. A conceptual diagram of relay is shown in fig 1.2. In fig 1.3, a relay R1 is used to protect the transmission line under

fault F1. An identical system is connected at the other end of the transmission line relay R3 to open circuit from the other ends as well.

TYPICAL RELAY CONNECTIONS

As an introduction to relay and circuit breaker connections, consider the system shown in Figure 2.2, where a radial line is protected by time-overcurrent relays (51) in each phase. Only the connection in one phase is illustrated for simplicity. The circuit breaker (52) control circuit consists of a battery that is connected through the circuit breaker auxiliary contacts (52a) and the circuit breaker trip coil (52TC), and finally to the relay contact (51). During normal operation, the circuit breaker is closed and load currents are flowing (downward in the figure). The circuit breaker front contacts (52a) are closed under this condition. Think of the "a" in 52a as meaning in agreement with the circuit breaker main contacts.1 If a

fault is detected such that the current in the relay coil exceeds a given preset threshold value, the relay will close its contacts in a measured time, which depends on the magnitude of the current and on the relay characteristics. This will cause current to flow in the circuit breaker trip coil (52TC),

'There may be other contacts in a relay control scheme that use the letter "a" in the contact identification, but such contacts are not part of the circuit

breakerandtheir open/close position is independent of the circuit breaker state. tripping the circuit breaker main contacts and also the auxiliary contacts. Tripping the main contacts removes the fault from the system and allows the relay to reset itself in a short time, which depends on the relay design. Tripping the auxiliary contacts opens the control circuit and interrupts the flow of current in that circuit.

Figure 2.2 A simple relay and circuit breaker control circuit.

The control circuit of Figure 2.2 is simpler than that found in most practical applications. A practical circuit would include a relay for each phase conductor and may have a fourth relay to measure ground currents. Also, since most faults are temporary, it may be desirable to include a means of automatically reclosing the circuit breaker after allowing time for the fault to deionize. These additional features will be introduced later. Finally, we note that this is a special case, being a radial line, making a simple overcurrent relay adequate to provide the necessary selectivity and control required. Most transmission lines are not operated radially and require more elaborate relay protection. Figure 2.3 shows a typical ac connection for a relay that requires both current and potential supplies. The connection of Figure 2.3 is typical of that used for a directional relay. Note that relay element 1 sees current Ia and voltage Vhr, and that these quantities are nearly in phase for a

Protective Circuit Line Breaker

transmission line fault, which usually has the current lagging the phase voltage by nearly 90 degrees. One reason the connection of Figure 2 .3 has been popular goes back to a principle of electromechanical relays, where having the relay current and voltage in phase on a wattmeter type element produces maximum torque on the relay element. Obviously, other connections of the current and voltage transformers are possible.

The dc circuit of the relay is the circuit breaker tripping circuit, as shown in Figure 2.4, which shows a tripping circuit that could be used with the relay connections of Figure 2.3. This dc trip circuit incorporates a holding coil or "seal-in" relay labeled "S" in the figure. The operation is as follows. If one of the relay elements detects a fault condition, the corresponding relay contact R is closed by the relay logic. Since the breaker auxiliary relay "a" contacts are closed (note that the breaker is still closed) closing R causes current to flow in the circuit breaker trip coil (TC). In many cases, the relay contacts are not designed for the relative severe duty of interrupting the trip circuit, hence the R contacts are paralleled by the seal-in relay contacts S, which remain closed throughout the breaker operation even though the relay contacts may drop out. When the circuit breaker main contacts open, the breaker auxiliary contacts "a" also open, interrupting the current flow in the dc control circuit. This interruption also causes the seal-in relay to drop out and the circuit is ready for reclosing and for tripping the next fault.

46

Figure 2.3 Typical ac relay connection showing both the current and voltage supplies (90 degree

connection).

To monitor the health of the apparatus, relay senses current through a current transformer (CT), voltage through a voltage transformer (VT). VT is also known as Potential Transformer (PT).

The relay element analyzes these inputs and decides whether (a) there is a abnormality or a fault and (b) if yes, whether it is within jurisdiction of the relay. The jurisdiction of relay R1 is restricted to bus B where the transmission line terminates. If the fault is in it's jurisdiction, relay sends a tripping signal to circuit breaker(CB) which opens the circuit. A real life analogy of the jurisdiction of the relay can be thought by considering transmission lines as highways on which traffic (current/power) flows. If there is an obstruction to the regular flow due to fault F1 or F2, the traffic police (relay R1) can sense both F1 and F2 obstructions because of resulting abnormality in traffic (power flow). If the obstruction is on road AB, it is in the jurisdiction of traffic police at R1; else if it is at F2, it is in the jurisdiction of R2. R1 should act for fault F2, if and only if, R2 fails to act. We say that relay R1 backs up relay R2. Standard way to obtain backup action is to use time discrimination i.e., delay operation of relay R1 in case of doubt to provide R2 first chance to clear the fault. Evolution of Relays

With the advent of transistors, operational amplifiers etc, solid state relays were developed. They realize the functionality through various operations like comparators etc. They provide more flexibility and have less power

consumption than their electromechanical counterpart. A major advantage with the solid state relays is their ability to provide self checking facility i.e. the relays can monitor their own health and raise a flag or alarm if its own component fails. Some of the advantages of solid state relays are low burden, improved dynamic performance characteristics, high seismic withstand capacity and reduced panel space. Relay burden refers to the amount of volt amperes (VA) consumed by the relay. Higher is this value, more is the corresponding loading on the current and voltage sensors i.e. current transformers (CT) and voltage transformers (VT) which energizes these relays. Higher loading of the sensors lead to deterioration in their performance. A performance of CT or VT is gauged by the quality of the replication of the corresponding primary waveform signal. Higher burden leads to problem of CT saturation and inaccuracies in measurements. Thus it is desirable to keep CT/VT burdens as low as possible.

Keypoint:

These relays have been now superseded by the microprocessor based relays or numerical relays.

1.5.3 Numerical Relays

The block diagram of a numerical relay is shown in fig 1.5. It involves analog to digital (A/D) conversion of analog voltage and currents obtained from secondary of CTs and VTs. These current and voltage samples are fed to the microprocessor or Digital Signal Processors (DSPs) where the protection algorithms or programs process the signals and decide whether a fault exists in the apparatus under consideration or not. In case, a fault is diagnosed, a trip decision is issued. Numerical relays provide maximum flexibility in defining relaying logic. 1.5 Evolution of Relays 1.5.3 Numerical Relays The hardware comprising of numerical relay can be made scalable i.e., the maximum number of v and i input signals can be scaled up easily. A generic hardware board can be developed to provide multiple functionality. Changing the relaying functionality is achieved by simply changing the relaying program or software. Also, various relaying functionalities can be multiplexed in a single relay. It has all the advantages of solid state relays like self checking etc. Enabled with communication facility, it can be treated as an Intelligent Electronic Device (IED) which can perform both control and protection functionality. Also, a relay which can communicate can be made adaptive i.e. it can adjust to changing apparatus or system conditions. For example, a differential protection scheme can adapt to transformer tap changes. An overcurrent relay can adapt to different loading conditions. Numerical relays are both "the present and the future". Hence, in this course, our presentation is biased towards numerical relaying. This also gives an algorithmic flavour to the course.

Summary: In this lecture we have learnt the following:

• Necessity of a protection system. • Three generations of relays. • Types of protection i.e. apparatus protection and system protection.

Review questions:

1.What are the two types of protection?

2. Why is system protection required?

3. What are the functions of a relay and a circuit breaker?

4. Describe various generation of relays.

1.2 : Protection Paradigms - Apparatus Protection Objectives: In this lecture we will introduce the following:

• Principle of over current protection. • Principle of directional over current protection. • Principle of distance protection. • Principle of differential protection. • For simplicity in explaining the key ideas, we consider three phase

bolted faults. • Generalization of different fault types will be discussed in

subsequent lectures. 1 Overcurrent Protection

This scheme is based on the intuition that, faults typically short circuits, lead to currents much above the load current. We can call them as overcurrents. Over current relaying and

fuse protection uses the principle that when the current exceeds a predetermined value, it indicates presence of a fault (short circuit). This protection scheme finds usage in radial distribution systems with a single source. It is quite simple to implement. Fig 2.1 shows a radial distribution system with a single source. The fault current is fed from only one end of the feeder. For this system it can be observed that: To relay R1, both downstream faults F1 and F2 are visible i.e. IF1 as well as IF2 pass through CT of R1. To relay R2, fault F1, an upstream fault is not seen, only F2 is seen. This is because no component of IF1 passesthrough CT of R2. Thus, selectivity is achieved naturally. Relaying decision is based solely on the magnitude of fault current. Such a protection scheme is said to be non-directional.

Directional Overcurrent Protection

In contrast, there can be situations where for the purpose of selectivity, phase angle information (always relative to a reference phasor) may be required. Fig 2.2 shows such a case for a radial system with source at both ends. Consequently, fault is fed from both the ends of the feeder. To interrupt the fault current, relays at both ends of the feeder are required. In this case, from the magnitude of the current seen by the relay R2, it is not possible to distinguish whether the fault is in the section AB or BC. Since faults in section AB are not in its jurisdiction, it should not trip. To obtain selectivity, a directional overcurrent relay is required. It uses both magnitude of current and

phase angle information for decision making. It is commonly used in subtransmission networks where ring mains are used. Distance Protection

Consider a simple radial system, which is fed from a single source. Let us measure the apparent impedance (V/I) at the sending end. For the unloaded system, I = 0, and the apparent impedance seen by the relay is infinite. As the system is loaded, the apparent impedance reduces to some finite value (ZL+Zline) where ZL is the load impedance and Zline is the line impedance. In presence of a fault at a per-unit distance ‘m', the impedance seen by the relay drops to a mZline as shown in fig 2.3.

The basic principle of distance relay is that the apparent impedance seen by the relay, which is defined as the ratio of phase voltage to line current of a transmission line (Zapp), reduces drastically in the presence of a line fault. A distance relay compares this ratio with the positive sequence impedance (Z1) of the transmission line. If the fraction Zapp/Z1 is less than unity, it indicates a fault. This ratio also indicates the distance of the fault from the relay. Because, impedance is a complex number, the distance protection is inherently directional. The first quadrant is the forward direction i.e. impedance of the transmission line to be protected lies in this quadrant. However, if only magnitude information is used, non-directional impedance relay results. Fig 2.4 and 2.5 shows a characteristic of an impedance relay and ‘mho relay' both belonging to this class. The impedance relay trips if the magnitude of the impedance is within the circular region. Since, the circle spans all the quadrants, it leads to non-directional protection scheme. In contrast, the mho relay which covers primarily the first quadrant is directional in nature.

Thus, the trip law for the impedance relay can be written as follows:

, then trip; else restrain. While impedance relay has only one

design parameter, Zset; 'mho relay' has two design parameters Zn, . The trip

law for mho relay is given by if , then trip; else restrain. As

shown in the fig 2.5 ' ' is the angle of transmission line. Based upon legacy of

electromechanical relays ' ' is also called 'torque angle'.

2.4 Principle of Differential Protection

2.4.1 Differential Protection for Transmission Line (Tapped Line)

Differential protection can be used for tapped lines (multiterminal lines) where boundary

conditions are defined as follows:

Under no fault condition:

Faulted condition:

2.4 Principle of Differential Protection Differential protection for detecting faults is an attractive option when both ends of the apparatus are physically located near each other. e.g. on a transformer, a generator or a bus bar. 2.4.2 Differential Protection for Transformer

Consider an ideal transformer with the CT connections, as shown in fig 2.8. To illustrate the principle let us consider that current rating of primary winding is 100A and secondary winding is 1000A. Then if we use 100:5 and 1000:5 CT on the primary and secondary winding, then under normal (no fault) operating conditions the scaled CT currents will match in magnitudes. By connections the primary and secondary CTs with due care to the dots (polarity markings), a circulating current can be set up as shown by dotted line. No current will flow through the branch having overcurrent current relay because it will result in violation of KCL. Now if an internal fault occurs within the device like interturn short etc., then

the normal mmf balance is upset i.e. . Under this condition, the CT secondary currents of primary and secondary side CTs will not match. The resulting differential current will flow through overcurrent relay. If the pick up setting of overcurrent relay is close to zero, it will immediately pick up and initiate the trip decision.

In practice, the transformer is not ideal. Consequently, even if , it is the magnetization current or (no load) current. Thus, a differential current always flows through the overcurrent relay. Therefore overcurrent relay pick up is adjusted above the no load current value. Consequently, minute faults below no load current value cannot be detected. This compromises sensitivity.

Summary: In this lecture we have learnt the following: Principle of overcurrent protection.

Principle of distance protection.

Principle of directional overcurrent protection.

Differential protection.

Applications to apparatus protection.

Review Questions:

1.Why is phase angle information required to protect a radial system with source at both ends? 2. Discuss the basic principle of distance protection. 3.

1.3 Protection Paradigms - System Protection Overview of Power System Dynamics Usually, system protection requires study of the system dynamics and control. To understand issues in system protection, we overview dynamical nature of the power system. Power system behavior can be described in terms of differential and algebraic system of equations. Differential equations can be written to describe behaviour of generators, transmission lines, motors, transformers etc. The detailing depends upon the time scale of investigation.

Figure 3.1 shows the various time scales involved in modelling system dynamics. The dynamics involved in switching, lightening, load rejection etc have a high frequency component which die down quickly. In analysis of such dynamics, differential equations associated with inductances and capacitances of transmission lines have to be modelled. Such analysis is restricted to a few cycles. It is done by Electromagnetic Transient Program (EMTP). At a larger time scale (order of seconds), response of the electromechanical elements is perceived. These transients are typically excited by faults which disturb the system equilibrium by upsetting the generator-load balance in the system. As a consequence of fault, electrical power output reduces instantaneously while the mechanical input does not change instantaneously. The resulting imbalance in power (and torque) excites the electromechanical transients which are essentially slow because of the inertia of the mechanical elements (rotor etc). Detection and removal of fault is the task of the protection system (apparatus protection). Post-fault, the system may or may not return to an equilibrium position. Transient stability studies are required to determine the post fault system stability. In practice, out-of-step relaying, under frequency load shedding, islanding etc are the measures used to enhance system stability and prevent blackouts. The distinction between system protection and control (e.g. damping of power swings) is a finer one. In the today's world of Integrated

Control and Protection Systems (ICPS), this distinction does not make much sense. In this lecture, we discuss these issues from distribution system perspective. In the next lecture, a transmission system perspective will be discussed.

3.2 System Protection Relays

Consider a medium voltage distribution system having local generation (e.g., captive power generation) as shown in fig 3.2 which is also synchronized with the grid. During grid disturbance, if plant generators are not successfully isolated from the grid, they also sink with the grid, resulting in significant loss in production and damage to process equipments. The following relays are used to detect such disturbances, its severity and isolate the inplant system from the grid. Underfrequency and over frequency relays. Rate of change of frequency relays. Under voltage relays. Reverse power flow relays. Vector shift relays. .2 System Protection Relays 3.2.1 Underfrequency Relay and Rate of Change of Frequency Relay

In case of a grid failure (fig. 3.3), captive generators tend to supply power to other consumers connected to the substation. The load-generation imbalance leads to fall in frequency. The underfrequency relay R detects this drop and isolates local generation from the grid by tripping breaker at the point of common coupling. After disconnection from the grid, it has to be ascertained that there is load-generation balance in the islanded system. Because of the inertia of the machines, frequency drops gradually. To speed up the islanding decision, rate of change of frequency relays are used. 3.2.2 Undervoltage Relay Whenever there is an uncleared fault on the grid close to the plant, the plant generators tend to feed the fault, and the voltages at the supply point drops. This can be used as a signal for isolating from the grid.

3.2.3 Reverse Power Relay

Distribution systems are radial in nature. This holds true for both utility and plant distribution systems. If there is a fault on the utility's distribution system, it may trip a breaker thereby isolating plant from the grid. This plant may still remain connected with downstream loads as shown in fig 3.4 and 3.5. Consequently, power will flow from the plant generator to these loads.

If in the prefault state, power was being fed to the plant, then this reversal of power flow can be used to island the plant generation and load from the remaining system. This approach is useful to detect loss of grid supply whenever the difference between load and available generation is not sufficient to obtain an appreciable rate of change of frequency but the active power continues to flow into the grid to feed the external loads.

Summary: In this lecture we have learnt the following: Dynamics in power systems. Various system protection relays like under frequency relays, rate of change of frequency relays, reverse power flow relay, under voltage relay etc. Lightning protection.

Review Questions 1. Describe various system protection relays in use. 2. What are the functions of an underfrequency relay? 3. Explain the functioning of reverse power flow relay. 4. How transmission lines are protected against lightning?

POWER SYSTEM FAULTS

Short circuits on power systems are usually shunt disturbances of one of the following types (shown along with their common abbreviation):

Three-phase short circuit (3PH) Phase-to-phase short circuit (L-L) Two-phase-to-ground short circuit (2LG) One-phase-to-ground short circuit (1LG)

The total current flowing to the fault depends on the type of fault and the phase in which the current is measured. It also depends on the location in the system where the fault occurs, since the Thevenin equivalent impedance seen looking back into the system varies with location, with the amount of generation in service at the time, and with the branch switching of thenetwork. This impedance also varies with load since the generators (and motors) are switched on and off in the normal course of scheduled activity on the network. All of these variations can be important, both in determining the exact fault current available at a given place and time, but also in fixing the critical parameters of the protective system. The total maximum fault current is important in determining the interrupting rating of devices. Both the maximum and minimum fault currents and voltages are important for

ensuring correct operation of the protective system over all possible operating conditions.

In some cases it is important to recognize system configurations that are not short circuits, but still should be considered "faults." These are often grouped together as longitudinal faults, as opposed to the lateral faults described in (5.1). These faults are described as follows:

One line open (1LO) Two lines open (2LO) (5.2) Three lines open (3LO) The first two of these conditions present unbalanced current flow in the

three-phase system, and may require protective response if the unbalance presents a serious threat to equipment. The third fault in (5.2) is nothing more than a line being open, which will not usually require any special protective system action except, perhaps, reclosure.

5.1.1 System Fault Characteristics

Fault currents in a power system depend on the impedance of the system between the generating sources and the fault location, on the prefault current flowing in a given line contributing to the total fault, and on the point on the sine wave of voltage at which the fault occurs. Consider the system shown in Figure 5.1 where a fault is applied at some point in a power system.

We shall concentrate only on the contribution to the fault labeled i that is radial from the source e on the left in Figure 5.1. The power system is represented by the resistance R and the inductance L, which are Thevenin equivalent parameters of the entire system to the left of the fault point F. We can write the differential equation of the circuit on the left side as follows.

L— + Ri = Em sin(cyf + /?) (5.3) dt

where Em is the maximum value of the sinusoidal source voltage and (5 represents the angle of the supply voltage at which the fault is applied. This representation of the system neglects the shunt susceptances of the transmission lines, but this is often an acceptable assumption in fault studies since the voltages are severely depressed in the vicinity of the fault. This assumption needs to be checked, however, for high-voltage systems.

Figure 5.1 Fault applied to a power system.

Solving (5.3) for the fault current, we get

i ( t ) = i s U ) + / , ( / ) E

= — sin(wf + 0- 0) +

where Z = J R2 + X2

X = coL coL\ ~ R )

Note that the total fault current has been divided into two components, a steady-state component and a transient component i,. The steady-state component has the frequency of the applied voltage, but shifted in phase by the angle f> and the constant angle of the system impedance, 0, and with a magnitude that is determined by the magnitude of the applied voltage and of the system impedance. The transient component has two parts, one that depends on the angle f> on the voltage wave at which the fault is applied. The other component is a function of the prefault current that is flowing at the instant the fault is applied. In many cases, this prefault load current in negligible compared to the larger magnitude of the transient fault current.

The total fault current can be described as a sinusoidal current with a dc offset that decays with a time constant t = L / R . We can estimate the value of this time constant as follows.

L _ mL _ X!R (5.6)

MR co We know that power systems have X / R values of 10 to 20, with

the higher ratios being characteristic of the higher voltage (EHV) systems. The value of the system time constant for 50 and 60 Hz systems is shown in Figure 5.2. The transient component of current will be reduced to 1 fee of its initial value in c time constants. For example, in one time constant, the transient will be reduced to 1 /e, or about 36.8% of its initial value. On a low-voltage system with a system X / R of 8 and time constant of 0.02 seconds, the transient current reaches this 36.8% value in 0.02 seconds or about 1.2 cycles on an 60 Hz system. On low-voltage systems, the protection may require a few cycles to complete its operation, so the transient will be decayed a few time constants before the breaker operates. However, on a high-voltage system with an X / R of 20, it takes a little over 0.05 seconds for the decay to reach 36.8%, or just over

(5.4)-Rl/L sin(0 — P) + /'(0+)

(5.5)= tan

three cycles. This is a large difference considering that the protection system on EHV systems should be much faster than three cycles.

This transient component has its maximum value at t — 0, and this is the value of greatest interest as it represents the maximum current. The maximum positive current offset occurs under the following conditions:

sin(6> - fi) = +1 i(0+) > 0 where both conditions apply simultaneously. Ignoring the prefault load current, for the moment, the maximum positive offset occurs when

P = 9 - n / 2

The maximum negative offset can be similarly computed, but we are not so much concerned by the sign of the offset as its magnitude and rate of decay.

Considering only the maximum condition, but ignoring the prefault load current, we can write the maximum current as

iP(t) = — [sin(<uf T Jt/2) ± e',/z] Z E,

'(=Fcoswr±e t/z)

where the choice of sign is determined arbitrarily on whether one is interested in a positive or a negative dc offset. The magnitudes are the same in either case. Also note that the current (5.9) is subscripted "P" to indicate that this is the current in the primary of the current transformer of the protective system.

The measurement of the fault current is shown in Figure 5.3, where the secondary current sees a burden Zg that consists of the relay impedance as well as the impedance of the leads from the CT secondary to the relay. Since the primary fault current is often very large, there is always a concern for the saturation of the current transformer. If we ignore the transformer excitation current, for the moment, we can write the voltage across the burden as

ZBiP vB = ZBis =

For an ideal transformer, we can write the voltage in terms of the rate of change of flux linkages. d<p v B = n dt where n is the turns ratio of the transformer. The flux is then computed by integrating (5.11)

(5.7)

(5.8)

(5.9)

(5.10)

(5.11)

for a total system impedance of Z [also see (2.4) for review].

( / > = - / " v B d t - K f (e~'/T - cos u t ) d t n Jn Jo

(5.12) K K — O - e " ' ) ---sin cot Wb = </>,+</>, a coz

where Z/lEn

K — Zn2 X / R

and Z is the total impedance seen by the source voltage. A plot of the primary current and the flux, with arbitrary vertical

scaling, is shown in Figure 5.4. Note that the primary current is completely offset at time zero. The flux also has a dc offset that is relatively large compared to the steady-state component because the time constant multiplier for the transient term is relatively large compared to the 1 /co multiplier of the steady-state component in (5.12). The transient flux plotted in Figure 5.4 assumes an ideal transformer and represents an unrealistic condition. Any physical transformer will saturate with high values of dc flux unless the core has a very large cross section. Therefore, a more realistic picture would be for the flux to level off at some saturated value immediately after zero time. This would provide very small values of secondary voltage due to the small (saturated) value of the flux rate of change. This means that the secondary current will be much smaller than the ideal value shown in the figure until the core saturation reduces to a small value, which may take quite a long time [I], [2j.

Figure 5.3 Measurement of the fault current.

One way to measure the relative magnitude of the severity of the saturation is to integrate the steady-state peak flux over 0.5-1.5 cycles and compare this with the transient flux integrated from zero to infinity. If this is done, we can compute the ratio of the two quantities as

4>< x Z = » ( 5 1 3 ) </'v R

Using this result, we can write the total flux as

<A = < A , ( l + ^ ) Fault Currents Near Synchronous Machines

Another important characteristic that affects certain protective system decisions is the nature of the fault current in close proximity to synchronous generators. This characteristic is largely due to the way in which fault currents decay with time in the stator windings of the machine. At the instant the fault occurs, each phase current has a value that depends on the generator load at that instant. Following the incidence of the fault, the currents in each phase change rapidly to very high values that depend on the type of fault, its location (severity), and the generator subtransient reactance, x/. This very high current begins immediately to decay, first at a rapid rate determined by the subtransient time constant t a n d later at a slower rate determined by the transient time constant t/. Depending on the speed of the relaying and circuit breaker action, the large initial current may have to be interrupted. It is important, therefore, that the protective system designer check the highest possible value that this current can reach, which would occur for a fault at the maximum generation condition and with no impedance from the relay location to the fault location, in other words, a close-in fault. Usually this is done for the three-phase fault with maximum dc current offset in one phase.It may also be important to estimate the contribution to the fault of nearby motors,

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 Time in cycles

Figure 5.4 Plot of primary current and transient current transformer flux.

articularly large motors. Synchronous motors contribute fault current in exactly the same way as synchronous generators, since they have their own source of excitation. Induction motors, however, experience a rapid decay in air gap flux and their contribution to the fault is usually negligible after two or three cycles. In both cases, the prime mover power for the motor comes from the shaft load. This load will often have sufficient inertia to cause the motor to feed the fault for a few cycles.

To estimate the fault current contribution of the synchronous generator, consider a fault on the terminals of a generator that is initially unloaded. At the instant the fault occurs, the generator is operating with an open circuit terminal voltage E, which is equal to the rated rms voltage. The flux in the air gap is maintained by the field excitation system at a value that will just provide E at the correct value. When the fault strikes, the peak air gap flux will have some value and this flux will have a given angle with respect to the a-phase stator winding, which we consider the reference position. This flux is trapped at its prefault value and currents will flow in the three-phase windings, the field winding, and the damper windings (or solid rotor body) to try and maintain this trapped flux at its prefault magnitude and angle, according to Lenz's law. The energy stored in this magnetic field is quickly absorbed by ohmic losses and the flux begins to decay immediately, and the currents decay as well, finally reaching a new steady-state condition. The actual stator currents have three types of components, a dc offset, a double frequency component, and a rated frequency component. The rated frequency component of five to 10 times normal is initially present in the stator and this current decays to its final value, which depends on the machine synchronous reactance. We are most interested in this rated frequency component and its rms value.

It is convenient to divide the rated frequency current into three components, as follows [3], [4]:l'd = 4 (5.16)

xd

xd where E is the rated rms generator phase voltage which is a function of the field current. These equations give the synchronous, transient, and subtransient components of the symmetrical ac stator current at time t = 0+, i.e., immediately following the fault. The transient and subtransient currents decay, each with its own time constant. These three currents and their decay pattern are shown in Figure 5.5. Note the different decay time constants of the transient and subtransient components.

E

Xd

Also, the field current can be written as

X') + Xf, xa = , 1 / (5-44) (ra + re)(oB

The concepts discussed above are accurate enough for most normal circuit breaker application guidelines and for preliminary relay settings. In some special cases, however, it may be considered necessary to make more accurate calculations. For example, if the machine time constants are unusually long or when one wishes to consider the relay currents a long time after fault inception, more accurate procedures may be desired. For these cases, the manufac-turers can furnish accurate decrement curves that can be used for more precise computations. Even these curves, however, are constructed using a set of assumptions regarding the generator prefault loading, the effect of excitation, and other simplifying assumptions. Still, this offers an optional alternate method that may be considered by the protection engineer.

Three-Phase (3PH) Faults

The arrangement of the sequence networks and the derived sequence and phase currents are shown in Figure 5.15. Obviously there are no negative or zero sequence currents for this type of fault as it is completely balanced. This means that there is no current through the ground impedance and it makes no difference if ZG is zero or infinite.

phase fault on an unloaded generator.

+ V.,

Zero Positive Negative

Figure 5.14 Sequence networks with defined sequence quantities [4], F

la 0 ^ 1 'F0

JZo

N0 n2

Z, + ZF

Figure 5.15 Three-phase fault connection and current equations [4].

The Thevenin equivalent voltage V p completes the fault data necessary for three-phase faults. This voltage will not usually be known precisely and is usually taken to be between 1.0 and 1.1, with 1.05 a good estimated value. The angle is usually taken to be zero, and this voltage then becomes the phasor reference for the calculations.

Double Line-to-Ground (2LG) Faults

The faulted phase designation and sequence network connection for the 2LG fault is shown in Figure 5.16 where is noted that the sequence networks are connected in parallel [4], The constant "a" in Figure 5.16 is the familiar 120 degree operator, i.e.,

a = e JW = e J™ = - l + j^- 2 2 There are three currents of interest for this type of fault, the line

currents lb and /c, and the ground current h + h- The line currents 4 and /c are not equal and must be calculated separately.

The positive and negative sequence impedances are exactly equal except for machines, and equating these sequence impedances is usually a very good approximation.

The zero sequence impedance Z0 is very difficult to determine accurately for multi- grounded systems. Chapter 6 provides a method of estimating this impedance for certain systems.

Fault impedances Z F and ZG are chosen arbitrarily, or based on data from typical faults. For simplicity we often let Z F = 0 and give ZG an estimated value.

Z0 + Z2 + 2ZF + 3ZC Z i +ZF Z0 + Z2 + 2ZF + 3ZC Figure 5.16 2LG fault connection and current equations [4],

Line-to-Line (L-L) Fault

The faulted phase designation and sequence network connections for the line-to-line fault are given in Figure 5.17. Usually, the positive and negative sequence impedances are taken to be equal impedances.

(5.57)

a b c

h = laO + lai + la 2 h = ho + a2Jat +ala 2 I , = I a t ) + al„\ +a2Ia 2 h h = 3/„o

la 1 = (Z2 + Zf)(Zo+ZF

+ 3Zc)

Vf Z, +Z f+ Z0 + Z2 + 2Zf

+ 3ZC Z0 + ZF + 3 ZG /«2 = -

laO =

No zero sequence current flows for the line-to-line fault since there is no path to ground. Since the fault is unbalanced and we wish to keep phase a as the symmetrical phase, this fault is usually represented as a phase b-c fault, as shown in Figure 5.17.

Figure 5.17 Line-to-line fault connections and current equations [4],

5.4.4 One-Line-to-Ground (1LG) Fault

The 1LG fault configuration and sequence network connections are shown in Figure 5.18. The comments above regarding the sequence impedances are applicable here, as well. With phase a as the symmetrical phase, the 1LG fault is usually represented as a fault on phase a. Sequence currents for this type of fault flow in all three sequence networks and are equal.

-a

5.4.5 Summary of Fault Currents

The foregoing summary provides the basic sequence network connections and the formula used in computing fault currents for common types of fault configurations. Fault current information is needed in all types of protective system coordination studies. Examples of the use of fault currents will be given in Chapter 6 and in other chapters. In all coordination studies it is assumed that these basic fault conditions are known.

Questions for practice: Choose the best Answer: 1. Which of the following relay is overload relays a)Thermal b)Electromagnetic c)Induction d) Solid state e)All of the above

2. Earth fault relays are a) directional relays b) Non-directional relays c) short operate time relays d)none of these

3. Impedance relay may use a) Balance beam structure b) induction cup structure c) shaded pole structure d)either a or b

4) How many relays are used to detect inter phase fault of a three line system a)one b)Two c)Three d)Six

la = 3/aO __________ Vf j » = / e = 0 " 0 a l a 2 ~ Z „ + Z , + Z 2 + 3Z,

Figure 5.18 One-line-to-ground fault connections and current equations [4],

Answer: 1. e)All of the above 2) a) directional relays 3. d)either a or b 4. c)Three

True or False 5) In electromagnetic relays the restraining torque is produced by springs 6) Relays using induction disc principle operate both on ac and dc system

Answer: 5. False 6. False

TWO MARKS QUESTIONS AND ANSWERS

1.What is relay? The protective relaying is used to give an alarm or to cause prompt

removal of any element of power system when that element behaves abnormally.The relays are compact and self contained devices. 2.What are the main reasons for main protection failure? 1.Failure in circuit breakers. 2. Failure in protective relay. 3. Failure in tripping circuit. 4. Failure in d.c tripping voltage. 5. Loss of voltage or current supply to the relay. 3.Name the methods of backup protection. 1.Relay Backup Protection 2.Breaker Backup Protection 3.Remote Backup Protection 4.Centrally Co-Coordinated Backup Protection 4.Give the essential quantities of protective relaying. 1.Reliability 2.Selectivity 3.Speed And Time.

4.Sencitivity 5.Stability 6.Adequateness 7.Simplicity And Economy. 5.Classify the protective relays. 1.Electro Magnetic Attraction Type Relays. 2.Induction Type Relays 3.Directional Type Relays. 4.Relays Based On The Timing 5.Differential Relays 6.Distance Type Relays. 6.Define plug setting multiplier.

The ratio of actual current in the relay coil to the pickup current is called plug-setting multiplier

P.S.M= fault current in the relay coil /pickup value

7.What are the advantages of electromagnetic relays?

1.It Can Be Used For Both A.C And D.C 2.Fat Operation 3.The Operating Time Varies With Current 4.High Operating Speed. 5.Compact, Reliable, Simple, Robust

8. What are the disadvantages of electromagnetic relays?

1.The Directional Feature Is Absent 2.Due To Fast Operation The Transients Can Affect The Working.

9. What are the applications of electromagnetic relays?

1.A.C And D.C Equipments. 2.Over/Under Current And Over/ Under Voltage Protection 3.Differencial Protection 4.Used As A Auxiliary Relays. 5.Earth Fault Protection

10.Name the types of induction type relays. 1.Shaded Pole Type

2.Watt Hour Meter Type 3. Induction Cup Relay The Above Relays Are Classified Based On The Construction. 11.Define differential relay. A differential relay is defined as the relay that operates when the phasor difference of two or more similar value electrical quantities exceeds a predetermined value. 12.What are the types of differential relay?

1.Current Differential Relay 2.Biaced Beam Relay Or Percentage Differential Relay 3. Voltage Balance Differential Relay

13.Define maximum torque angle. The angle by which the current supplied to the relay leads the voltage supplied to the relay so as to obtain the maximum torque is called maximum torque angle. It is denoted by ττττ. 14.Name the types of relay based on the voltage and current.

1.Impedance relay (measurement of Z) 2.Reactance relay.(measurement of X) 3.Admittance relay (measurement of Y)

15.Draw the operating characteristics of impedance relay. X ZR

R 16. Draw the operating characteristics of reactance relay.

X

XR

R 17. Draw the operating characteristics of mho relay. X ZR

R 18.Define static relays. The relays do not use moving parts and use the solid state electronic components such as diodes, transistors are called static relays. 19.What are the advantages of static relays?

1.The moving parts are absent. 2.The Power Consumption Is Low. 3.The Response Is Very Quick 4.Maintenance Is Less 5.The Sensitivity Is High. 6.The Testing And Servicing Required Is Less.

20.What are the disadvantages of static relays? 1.characteristics are temperature dependent. 2.Reliability is unpredictable. 3.Additional d.c supply is required. 4.less robust compared to electro magnetic relays. 5.susceptible to the voltage fluctuations

21.Give the types of static relays.

1.Frequency Relay. 2.Negative Sequence Relay.

3.Microprocessor Based Relay. 4.Static Distance Relay. 5.Static Differential Relay. 6.Static Time Over current Relay and Directional O/C Relay.

22.What are types of frequency relays?

1.under frequency relay 2.over frequency relay

23.What are the components present in the static relays?

1.rectifier 2.filter 3.level dector 4.amplifier

24.What are the types of comparators used in static relays?

1.rectifier bridge type 2.hall effect type

25.What are the types of induction type relays?

1.induction cup type 2.induction disc type

. What are the functions of protective relays To detect the fault and initiate the operation of the circuit breaker

to isolate the defective element from the rest of the system, thereby protecting the system from damages consequent to the fault. 26. Give the consequences of short circuit.

Whenever a short-circuit occurs, the current flowing through the coil increases to an enormous value. If protective relays are present , a heavy current also flows through the relay coil, causing it to operate by closing its contacts.The trip circuit is then closed , the circuit breaker opens and the fault is isolated from the rest of the system. Also, a low voltage may be created which may damage systems connected to the supply. 27. Define protected zone.

Are those which are directly protected by a protective system such as relays, fuses or switchgears.If a fault occurring in a zone can be immediately detected and or isolated by a protection scheme dedicated to that particular zone.

28.What are unit system and non unit system? A unit protective system is one in which only faults occurring within its protected zone are isolated.Faults occurring elsewhere in the system have no influence on the operation of a unit system.A non unit system is a protective system which is activated even when the faults are external to its protected zone. 29. What is primary protection?

Is the protection in which the fault occurring in a line will be cleared by its own relay and circuit breaker.It serves as the first line of defence.

30. What is back up protection? Is the second line of defence , which operates if the primary

protection fails to activate within a definite time delay. 31 Name the different kinds of over current relays.

Induction type non-directional over current relay,Induction type directional over current relay & current differential relay.

32. Define energizing quantity. It refers to the current or voltage which is used to activate the relay into

operation. 33. Define operating time of a relay.

It is defined as the time period extendind from the occurrence of the fault through the relay detecting the fault to the operation of the relay.

34. Define resetting time of a relay. It is defined as the time taken by the relay from the instant of

isolating the fault to the moment when the fault is removed and the relay can be reset. 35. What are over and under current relays?

Overcurrent relays are those that operate when the current in a line exceeds a predetermined value. (eg: Induction type non-directional/directional overcurrent relay, differential overcurrent relay)whereas undercurrent relays are those which operate whenever the current in a circuit/line drops below a predetermined value.(eg: differential over-voltage relay) 36. Mention any two applications of differential relay.

Protection of generator & generator transformer unit; protection of large motors and busbars . 37. What is biased differential bus zone reduction?

The biased beam relay is designed to respond to the differential current in terms of its fractional relation to the current flowing through the protected zone. It is essentially an over-current balanced beam relay type with an additional restraining coil. The restraining coil produces a bias force in the opposite direction to the operating force. 38. What is the need of relay coordination?

The operation of a relay should be fast and selective, ie, it should isolate the fault in the shortest possible time causing minimum disturbance to the system. Also, if a relay fails to operate, there should be sufficiently quick backup protection so that the rest of the system is protected. By coordinating relays, faults can always be isolated quickly without serious disturbance to the rest of the system.

39. Mention the short comings of Merz Price scheme of protection applied to a power transformer.

In a power transformer, currents in the primary and secondary are to be compared. As these two currents are usually different, the use of identical transformers will give differential current, and operate the relay under no-load condition. Also, there is usually a phase difference between the primary and secondary currents of three phase transformers. Even CT’s of proper turn-ratio are used, the differential current may flow through the relay under normal condition.

40. What are the various faults to which a turbo alternator is likely to be

subjected? Failure of steam supply; failure of speed; overcurrent; over voltage;

unbalanced loading; stator winding fault . 41. What is an under frequency relay?

An under frequency relay is one which operates when the frequency of the system (usually an alternator or transformer) falls below a certain value. 42. Define the term pilot with reference to power line protection.

Pilot wires refers to the wires that connect the CT’s placed at the ends of a power transmission line as part of its protection scheme. The resistance of the pilot wires is usually less than 500 ohms. 43. Mention any two disadvantage of carrier current scheme for transmission line only.

The program time (ie, the time taken by the carrier to reach the other

end-upto.1% mile); the response time of band pass filter; capacitance phase-shift of the transmission line .

44 What are the features of directional relay?

High speed operation; high sensitivity; ability to operate at low voltages; adequate short-time thermal ratio; burden must not be excessive.

45. What are the causes of over speed and how alternators are protected

from it? Sudden loss of all or major part of the load causes over-speeding in alternators.

Modern alternators are provided with mechanical centrifugal devices mounted on their driving shafts to trip the main valve of the prime mover when a dangerous over-speed occurs. 46. What are the main types of stator winding faults?

Fault between phase and ground; fault between phases and inter-turn fault involving turns of the same phase winding. 47. Give the limitations of Merz Price protection.

Since neutral earthing resistances are often used to protect circuit from

earth-fault currents, it becomes impossible to protect the whole of a star-

connected alternator. If an earth-fault occurs near the neutral point, the voltage may be insufficient to operate the relay. Also it is extremely difficult

to find two identical CT’s. In addition to this, there always an inherent phase difference between the primary and the secondary quantities and a possibility

of current through the relay even when there is no fault. 48. What are the uses of Buchholz’s relay?

Bucholz relay is used to give an alarm in case of incipient( slow-developing) faults in the transformer and to connect the transformer from the supply in the event of severe internal faults. It is usually used in oil immersion transformers with a rating over 750KVA.

49.What are the types of graded used in line of radial relay feeder? Definite time relay and inverse-definite time relay. 50.What are the various faults that would affect an alternator?

(a) Stator faults 1, Phase to phase faults 2, Phase to

earth faults 3, Inter turn faults

(b) 1, Earth faults 2, Fault between turns 3, Loss of excitation due to fuel failure

(c) 1, Over speed 2, Loss of drive

3, Vacuum failure resulting in condenser pressure rise, resulting in shattering of the turbine low pressure casing

(d) 1, Fault on lines 2, Fault on busbars

51.Why neutral resistor is added between neutral and earth of an alternator?

In order to limit the flow of current through neutral and earth a resistor is introduced between them. 52.What is the backup protection available for an alternator? Overcurrent and earth fault protection is the backup protections. 53.What are faults associated with an alternator?

(a) External fault or through fault (b) Internal fault

1, Short circuit in transformer winding and connection 2, Incipient or slow developing faults

54. What are the main safety devices available with transformer?

Oil level guage, sudden pressure delay, oil temperature indicator, winding temperature indicator . 55.What are the limitations of Buchholz relay?

(a) Only fault below the oil level are detected. (b) Mercury switch setting should be very accurate,

otherwise even for vibration, there can be a false operation.

(c) The relay is of slow operating type, which is unsatisfactory.

56.What are the problems arising in differential protection in power

transformer and how are they overcome? 1. Difference in lengths of pilot wires on either sides of the relay. This

is overcome by connecting adjustable resistors to pilot wires to get equipotential points on the pilot wires.

2. Difference in CT ratio error difference at high values of short circuit

currents that makes the relay to operate even for external or through faults. This is overcome by introducing bias coil.

3. Tap changing alters the ratio of voltage and currents between HV and

LV sides and the relay will sense this and act. Bias coil will solve this.

4. Magnetizing inrush current appears wherever a transformer is energized on its primary side producing harmonics. No current will be seen by the secondary. CT’s as there is no load in the circuit. This difference in current will actuate the differential relay. A harmonic restraining unit is added to the relay which will block it when the transformer is energized.

57. What is REF relay?

It is restricted earth fault relay. When the fault occurs very near to the neutral point of the transformer, the voltage available to drive the earth circuit is very small, which may not be sufficient to activate the relay, unless the relay is set for a very low current. Hence the zone of protection in the winding of the transformer is restricted to cover only around 85%. Hence the relay is called REF relay. 58. What is over fluxing protection in transformer?

If the turns ratio of the transformer is more than 1:1, there will be higher core loss and the capability of the transformer to withstand this is limited to a few minutes only. This phenomenon is called over fluxing. 59.Why busbar protection is needed?

(a) Fault level at busbar is high (b) The stability of the system is affected by the faults in the bus

zone. (c) A fault in the bus bar causes interruption of supply to a large

portion of the system network. 60.What are the merits of carrier current protection?

Fast operation, auto re-closing possible, easy discrimination of

simultaneous faults . 61.What are the errors in CT?

(a) Ratio error Percentage ratio error = [(Nominal ratio – Actual ratio)/Actual ratio] x 100 The value of transformation ratio is not equal to the turns ratio.

(b) Phase angle error: Phase angle =180/π[(ImCos -I1Sin )/nIs]

62. What is field suppression?

When a fault occurs in an alternator winding even though the generator circuit breaker is tripped, the fault continues to fed because EMF is induced in the generator itself. Hence the field circuit breaker is opened and stored energy in the field winding is discharged through another resistor. This method is known as field suppression. 63. What are the causes of bus zone faults?

Failure of support insulator resulting in earth fault Flashover across support insulator during over voltage Heavily polluted insulator causing flashover Earthquake, mechanical damage etc.

64. What are the problems in bus zone differential protection?

Large number of circuits, different current levels for different circuits for external faults.

Saturation of CT cores due to dc component and ac component in short circuit currents. The saturation introduces ratio error.

Sectionalizing of the bus makes circuit complicated. Setting of relays need a change with large load changes.

65.What is static relay?

It is a relay in which measurement or comparison of electrical quantities is made in a static network which is designed to give an output signal when a threshold condition is passed which operates a tripping device. 66. What is power swing?

During switching of lines or wrong synchronization surges of real and reactive power flowing in transmission line causes severe oscillations in the voltage and current vectors. It is represented by curves originating in load regions and traveling towards relay characteristics.

67. What is a programmable relay?

A static relay may have one or more programmable units such as microprocessors or microcomputers in its circuit.

68. What is CPMC? It is combined protection, monitoring and control system incorporated

in the static system.

69. What are the advantages of static relay over electromagnetic relay? o Low power consumption as low as 1mW o No moving contacts; hence associated problems of arcing,

contact bounce, erosion, replacement of contacts o No gravity effect on operation of static relays. Hence can be

used in vessels ie, ships, aircrafts etc. o A single relay can perform several functions like over current,

under voltage, single phasing protection by incorporating respective functional blocks. This is not possible in electromagnetic relays

o Static relay is compact o Superior operating characteristics and accuracy o Static relay can think , programmable operation is possible

with static relay o Effect of vibration is nil, hence can be used in earthquake-prone

areas Simplified testing and servicing. Can convert even non-electrical

quantities to electrical in conjunction with transducers

12 MARK QUESTIONS.

1. What are the essential quantities of protective relaying and explain it. 2. Explain the symmetrical components for L-G fault and derive the

expression for fault current.

3. With a neat diagram, explain the zones of protection.

4. Briefly explain the principle of protective relaying.

5. What is fault? Explain the nature, types and causes of faults.

6. What is meant by directional feature of a directional over current relay? Describe the construction and principle.(APR 04,AU).

7. Explain the negative sequence currents for the operation of relays.(APR

‘04 ,AU).

8. Explain the operation of directional and non-directional induction type over current relay.(APR’05 AU)

9. Draw and explain the operating characteristics of the directional over

current relay. .(APR’05 AU)

10. Describe the principle of operation of microprocessor based static relays.

11. How electromagnetic relays differ from static relays and describe the

block diagram for static relays.

12. What is meant by impedance, reactance &mho relay and differentiate it.