Those of us who work in the electric power industry all know that protective relay is an absolutely vital part of the power system. It impacts on all areas of the system. generation, transmission, distribution, and utilization.
Protection is of concern to many different departments and divisions of the power company. The first that come to mind are the relay technicians and engineers who are responsible for installation and test and calibration of the protective circuitry. Also very much involved are system operators, the operators of power plants, transmission systems, and distribution systems who need to interpret and respond to the operation of protective relays. The subject is also extremely important to planners and system designers, as the design of the power system depends to some extent upon the protection schemes to be installed and vice versa. And last but not least, Company management is extremely concerned with protection as it affects the reliability of power supply to the customers.
If protection schemes do not operate correctly, the result can be extensive damage to power equipment, with consequent high repair costs and perhaps long outage times. It is perhaps a little annoying, if not ironic, to technicians and engineers working in the relay department that when the power system is functioning properly, most of the staff completely forget about protection. However, when upsets do occur on the system, everyone expects the protection schemes to work precisely and initiate action to prevent equipment damage, to prevent injury to personnel, to protect the public, and to reduce customer outage to a minimum.
This video program discusses and demonstrates the application of protective relaying in all parts of the power system. We'll be discussing protective schemes and also be looking at different types of relays. The specific design of protective relays varies with different manufacturers and from time to time changes and updates are made.
Especially as solid state technology is more widely used. Detailed test and calibration procedures for particular manufacturers'relays are thoroughly covered in another video program of ours dealing with relay test and calibration. However, this video program emphasizes application of protective relaying, which remains basically the same regardless of design variations. In this, the first tape in the series, we'll be looking at why protection is necessary.
And then we'll discuss some of the general philosophy involved in the protection schemes. As we've mentioned before, protection touches on all parts of the power system. Therefore, in preparing this program, we have to assume that you, the viewer, have a general knowledge of all of these areas, in addition to very detailed knowledge in at least one particular area. In fact, most electric power companies already have our well-known video training programs, which cover generation, transmission, and distribution.
All these programs include a review of electrical fundamentals, therefore this material will not be repeated here. So why do we need protective schemes? Well, the primary objective of all power systems is to maintain continuity of service to our customers. When abnormal conditions do occur, the protection equipment must function so as to reduce damage to the minimum and at the same time minimize the outage time to all customers. But what are the causes of abnormal conditions?
Well, they're usually the consequence of one or more of the following. One, natural events. Two, physical accidents. Three, equipment failure.
And four, misoperation. Natural events which can cause problems to power systems are lightning, wind, ice, earthquake, fire, explosions. falling trees or flying objects. Physical accidents include such things as a vehicle crashing into a pole, or perhaps animals or people coming into contact with live equipment, or a contractor digging into underground cables. An example of equipment failure would be, say, a breakdown of insulation in a transformer.
An example of misoperation would be if the operator inadvertently closed the breaker to energize a line which was still solidly grounded. All of these abnormal conditions will result in a fault, that is, an unwanted short-circuit connection between one phase wire and another. or between a phase wire and ground. The consequence of the fault is usually a dramatic increase in the value of current flowing, and the resultant increase in heat produced in the conductors is the main cause of damage.
The actual magnitude of fault current depends upon the amount of power available to feed into the fault. It's also dependent upon the resistance to flow, that is, the impedance between the fault and the source of power supply. The total impedance is made up of A, resistance of the fault itself, B, resistance and reactance, that is, impedance of the line conductors, C, impedance of any transformers or reactors in the circuit, and D, impedance of the generating source. The calculation of probable fault currents for different conditions is a very important task for the system designer.
Now, why is this? Well, any switchgear which is installed must be capable of handling the fault current. If a breaker is undersized, it could be completely destroyed when trying to clear a heavy fault current.
However, as you know, overcurrent is not the only effect resulting from fault conditions. For example, a fault in a generator could cause serious change to system conditions, such as undervoltage, a change in power and power factor, A change in direction of current and power flow. A change in frequency.
A change in temperature inside the generator. Physical movement, for example, the generator windings. I'm sure you can think of others, and it's these very changing conditions which allow the relays to sense and detect the presence of a fault. Most relays use one, but often several of these changing factors, sometimes called handles, to determine whether the fault condition is acceptable or not. We must recognize that some fault conditions may be tolerable, at least for a short period of time, but others may be intolerable and require immediate isolation from the system to prevent damage.
The protective system must be able to measure and respond to its incoming signals in a very short time period. If the conditions are determined to be intolerable, then the protective system must take action immediately, usually to trip out circuit breakers. Conversely, if the fault is tolerable, then the protective system must be taken out immediately.
system must not operate in most power systems the protective relays are rarely called upon to operate but under fault conditions it is absolutely imperative that they do operate precisely and provide the correct action. If a relay fails to operate and hence clear and intolerable fault, then equipment damage may occur and certainly there would be a system upset. For this reason, it is customary to install additional or duplicate relays to provide backup. If the backup relays are installed in the same station as the primary relays, this is known as local backup.
Sometimes backup relays are located at a remote station, and this is called logically remote backup. Here we see the fault way out along the line, but the local protection fails to operate. The remote backup will then operate to open this breaker and so clear all of this line, as well as the bus and other outgoing feeders.
When remote backup relays operate, they will generally isolate a larger area from the system and so cause a Loss of power supply to more customers. The backup relays must be correctly coordinated so that they allow primary protective schemes to operate first. Only in the case of failure of the primary protection would the backup relays need to operate. We'll be looking at all of this in great detail as we proceed through this program. Remember at this point, we're looking only at the basic philosophies behind protective schemes.
At this point, let's take a break and then we'll come back. and look at some simple protection schemes. For now, please switch off the tape and review this material in your workbook.
As we all know, there are many different types of relays used in protective schemes. However, most relays follow the same logic pattern. That is input, measurement, determination, and output. The input will represent current or voltage or frequency or perhaps other values which exist in the protected circuit at any instant in time.
The relay measures these values and then determines if the circuit operating conditions are within normal parameters. Under normal operating conditions, output is zero. That is, a set of open or closed contacts at rest. However, with an intolerable fault level, then the relay output will impose an operating signal on a control circuit, usually in terms of DC volts.
This tripping signal is then fed to one or more circuit breakers to cause them to open so as to isolate the faulty circuit. What is the purpose of the circuit breaker? Well, obviously, the relay itself is a small, low-voltage control device, whereas the circuit breaker is an integral part of the high-voltage, high-current power system.
In fact, for the protective relay to have any impact at all on the power system, it must be coupled to a switching device. The exception to this is where relays are used to give alarm only, but for action it must command a switching operation. Conversely, the circuit breaker would have little value other than as a manual switch if it were not coupled to protective relays.
The circuit breaker is specifically designed to interrupt fault current, which may be ten times or more than normal full load current. It achieves this by breaking the current flow in a specially designed interrupter. As the contacts open inside the interrupter, an arc is drawn.
on. It is essential that this arc be extinguished immediately and the contacts thoroughly insulated from each other so as to prevent a re-strike which could result in considerable damage to the breaker. Various methods are used to quench the arc inside the interrupter depending upon the size and voltage of the breaker. The quenching medium may be oil as in the case of this 100 432 kV oil circuit breaker. In this type of breaker, all three phases are immersed in oil tanks, and the tanks are grounded.
This is known as a dead tank breaker. We mention it here because the item does have some significance in protection, as you'll see in later tapes. Incidentally, current transformers are usually located in the bushings here.
This type of breaker is usually provided with a single trip coil to operate the opening mechanism on all three phases. In rare incidences, a breaker may fail to open, perhaps due to a problem in the tripping circuit or in the mechanism itself. Indeed, as we shall see, this is one of the conditions that must be protected against.
Where breaker operation is critical, an additional parallel tripping coil and circuit is often provided, fed from its own second set of relays. Another type of arc quenching is through air blast, as in this 345 kV breaker. As you can see, each phase has... as its own interrupter mounted on insulators.
As it is insulated from ground, the tank is known as a live tank. Each of the phases is equipped with its own separate tripping coil, and they are usually, but not always, wired in series. Problems can and do occur if perhaps one phase fails to open, or conceivably all three phases open, but not at precisely the same time. This can give rise to severe transience on the system, as we shall see in later tapes.
Additional, redundant tripping circuits and relays are usually provided with high-voltage breakers, that is, 230 kilovolts and up. Yet another quenching medium is SF6, sulfur hexafluoride gas. And in lower-voltage breakers, arc brake chutes are provided. Vacuum breakers use vacuum as the arc quenching medium. The subject of circuit breaker design is obviously outside the scope of this video program, but further details are provided in other programs.
The important factor to remember is that the circuit breaker is capable of interrupting fault currents. There are many other switching devices, particularly in use on the distribution system, such as reclosers. sectionalizers and oil switches, but in general these are capable of very limited fault interruption. On the distribution system fuses are often used in place of the relay circuit breaker combination. The fuse is not so fast or accurate as protective relays, but it does provide satisfactory economical protection for distribution transformers and feeds.
Another type of protection frequently encountered at utilization voltage of, say, 480 volts, is the direct acting contactor. In one common type, overcurrent causes thermal contacts to open the circuit. In another type, a built-in relay opens the contactor. However, let's return to the thrust of this program, that is, protective relaying of the power system. This circuit shows the elements of a very basic protection scheme.
The inputs to the relay... Relays are provided by current and voltage. The voltage is measured by a voltage transformer connected to the bus, which may be at, say, 33 kV.
The secondary side of the voltage transformer, or potential transformer as they are often called, delivers 120 volts to the relay. This voltage will, of course, rise or fall in proportion to variations in the bus voltage, so it will represent the actual bus voltage to the relay. Similarly, the line current is represented by the input to the relay from the current transformer. We shall be talking more about CTs and VTs later. This circuit breaker is located in the line that is the protected circuit.
Let's suppose that a high magnitude fault occurs on the line at this point. The relay will detect the intolerably high current and send a tripping signal to open the circuit breaker. Let's look at the circuit breaker. this tripping circuit. A 125 volt DC system is provided for operation of the breakers.
The circuit breaker closing and tripping coils are energized by 125 volt DC from the station battery as this provides a continuous and reliable power supply. When the circuit breaker is closed, the elementary tripping circuit will look like this. These auxiliary contacts are closed because the breaker is closed, but the tripping coil will not be energized until either, one, the protective relay contacts close, or two, the manual switching contacts are closed. are operated.
In practice, there may be other parallel contacts which can open the breaker. Remember, the circuit breaker tripping coil and its auxiliary contacts are normally located at the circuit breaker inside the cabinet. This is probably in the switch yard, some distance away from the relay panel. However, relay operating contacts are located inside the relay.
The manual switching contacts are normally located... ...on the control panel. Now, when the relay operates due to sensing intolerable conditions, the relay contacts will close, and this now energizes the breaker tripping coil.
This in turn causes the breaker to open, and also causes the auxiliary contact to open, so breaking the DC tripping circuit. But it is possible that the relay contacts may bounce open first as the fault is removed by opening the breaker. These delicate contacts inside the relay are not made to interrupt this relatively high current flow through the tripping circuit.
So in order to protect the contact surfaces, a seal-in arrangement is usually wired into the relay. It functions like this. When the tripping circuit is energized, the ceiling contactor switch is also energized by the passage of current. This, in turn, closes the ceiling contacts here, and they will remain closed as long as the circuit remains energized. Now, if the relay contacts open first, they will not interrupt the tripping current, as the closed seal-in contacts provide an alternative path.
Only when the breaker auxiliary contact opens will the circuit be de-energized, and the seal-in contacts also opened. When working with protective relays, it is always essential to keep these two circuits separate in the mind. First, the relay itself functions according to the inputs being fed into the relay. Secondly, when the relay does operate, it closes its operating contacts, thus completing an external circuit, that is, the DC tripping circuit of the main breaker. Relays are often tested in place so that the total circuitry can be checked as well.
Alternatively, they can be removed from the casing and placed on the test bench for test and calibration. When you remove a relay from its case on the panel, you can see the base contacts. These are providing input from the VTs and CTs or other sources to the relay sensing circuit and also are providing a continuity of the breaker trip circuit.
When the relay is removed, it is always necessary to open the circuits of the incoming VT and to disconnect DC to the relay. Conversely, the CT connections must be shorted. I'm sure you already know why this is so. If the secondary of a CT is open-circuited, when current is flowing in the primary, a very high voltage would arise across the secondary terminals. Of course, the circuit that we have been studying is extremely simple, and we have not specified any particular type of relay.
You know that this is going to get far more complicated as we go along. For example, considering the three phases of the same circuit, we now have to include three relays, one per phase, plus a ground relay, all with their separate CTs and sometimes VTs as well. But before we go on, let's...
Take a short break. Please switch off the tape now and thoroughly review this material in your workbook. Let's look at our simple protection circuit again.
In order to identify the components, we have had to write the names of the devices on this circuit. diagram. An easier way would be to use a standard code or numbering scheme.
This is especially important when we come to complex diagrams like this. Well it just so happens that the American National Standards Institute in collaboration with the IEEE have provided a standardized list of device function numbers. These are used throughout North America and indeed in many other parts of the world.
The list is quite extensive, numbering from 1 to 94. For example, quickly running your eye down the list, we find a master contactor, synchronous speed device, distance relay, field circuit breaker, AC circuit breaker, ground detector relay, rheostat, frequency relay, line switch, and so on. all with their respective numbers. The circuit breaker is represented by number 52, so we can place this into our elementary diagram. And supposing the protection relay is an AC directional overcurrent relay, this would be device number 67. In addition to device numbers, a list of abbreviated letters are also provided. And here we can see just at random that A is an abbreviation for alarm, CS represents a control switch or contactor switch, G indicates ground or a generator, N stands for neutral, TC for trip coil, and so on.
Now there is no need for you to remember all of these abbreviations or device numbers. A list is included in your workbook. But as you probably know from experience, you soon get accustomed to certain numbers, especially those referring to protective devices. Every time you look at a schematic and see the number 87, you know that this refers to a differential protection relay.
In this case, differential protection across the primary and secondary of a transformer. What else does the diagram tell us? Well, we can see that the primary is delta connected, and the secondary is Y-grounded through a resistance. The circuit breakers are represented by 52P.
primary and 52S secondary. What do these other device numbers represent? Looking up our reference list, we find that the transformer itself is equipped with a thermal relay, 49, and a gas pressure relay, 63. This is a commonly used symbol for a CT, but please make sure you are familiar with your own company standards. This CT is installed in the neutral to ground connection, measuring ground current. It feeds time over current relays, 51G.
Another time over current relay, 51, is installed on the secondary output, before the breaker. And what is this on the primary, device number 50? An instantaneous over current relay.
Well now, before you get too involved in this circuit, remember, our objective here is not to discuss the settings and coordination of these relays, but rather to get ourselves thoroughly familiar with using electrical diagrams. Now, I know many of you are doing this every day, but not everybody is so fortunate, so please stick with it. Here is another simple protection diagram.
A generator connected directly to a bus through circuit breaker 52G. You can already recognize some of these device numbers. 51G is a time over current relay in the neutral to ground. 87G, a differential relay across the generator. What is this 46?
A negative phase sequence relay. 51V is a voltage restrained time over current relay fed by the CT in the generator output and a voltage transformer which also feeds a directional power relay, 32, and a loss of field relay, 40. In studying these diagrams, it is essential to note the location of the source of input to each device. That is, the CTs and the VTs. Of course, here we are looking at a one-line diagram.
Here is part of a typical three-line diagram showing more detailed connections. Another type of diagram that you must be completely familiar with is the control circuit schematic. As we've already mentioned, circuit breaker components may be physically far apart. The closing and tripping coils are located adjacent to the breaker.
The manual switching contact... considerable distance on the control panel. The protection relay contacts inside the relay may be in yet another location.
However, from an electrical point of view, the breaker control circuit looks like this. The DC positive and negative may be drawn horizontally or vertically it really makes no difference. You soon get used to working through the circuit to determine the sequence of events. Look at the closing circuit of this breaker. To energize the closing coil, the circuit must be completed by closing one or more of these pairs of contacts.
This symbol indicates an open pair of contacts. Do not confuse this with the symbol for a capacitor, which looks like this. Now, a closed pair of contacts is shown by this symbol, and indeed, if they are closed under normal operating conditions, the letters NC may be added. Similarly, NO means normally open contacts.
Conventionally, the diagram is shown with the contacts in the at-rest condition. That is, the tripping and closing circuits are de-energized. The circuit breaker is open. You would think that to close the breaker, it would be sufficient to close any pair of the manual switching contacts. In this installation, we have local and remote operation.
But look, there are other contacts in series with the closing coil, and these are known as permissive contacts. For example, this pair will only close when there is adequate pneumatic pressure available to operate the breaker mechanism. This pair of permissive contacts are only closed when a synchronizing relay determines that conditions are correct for closing. And yet another pair only close when there is no remote inter-tripping signal on the system. I'm sure you can think of a lot more permissive conditions.
Once all of these permissive conditions are met and all contacts closed, the breaker will close when you operate one of the closing switches. On most breakers, once closed, both the closing and tripping circuits remain de-energized as the mechanism is mechanically latched in. How is this achieved?
When the breaker is firmly closed, it mechanically actuates auxiliary contacts in the control circuit. It opens the auxiliary contacts here, de-energizing the closing circuit. At the same time, it will close these auxiliary contacts in the tripping circuit, so enabling this circuit to operate when required.
To trip the breaker open, the tripping circuit must be energized. In the case of a tripping circuit, instead of permissive contacts in series, we'll find several pairs of contacts in parallel. Look at these tripping contacts.
Overcurrent relay, manual switching, differential relay, remote intertrip. Closing any one of these pairs will energize the tripping circuit and open the circuit breaker. Often these tripping contacts are provided with seal-in circuits, as we discussed in the previous segment. We have been looking at a relatively simple control schematic. In practice, these diagrams can be used to control the circuit.
become quite complex. You'll find it most challenging to get hold of a set of control diagrams on your own job and work through them. In fact, I'll leave you with that as an exercise. Let's take a break. Get zone protection.
Please switch off the tape and go through this material in your workbook. In our typical power system, we have generators, including their step-up transformers, buses, transformers, transmissions. transmission lines, sub-transmission lines, distribution lines, and utilization equipment such as motors and static loads. Also on most systems, capacitor banks and reactor banks are installed.
Now, all of this equipment needs to be protected, but the type of protection used is generally different for each area. So it is convenient to apply the protection to distinct zones. For example, let's start at the generator zone, which includes its associated step-up transformer. Any fault within this zone would result in tripping of the main generator breaker here, and hence isolation from the power system.
This will protect against faults in 1. the generator itself, 2. the primary of the transformer, 3. the secondary of the transformer, and 4. the breaker. The next area of protection is the bus zone. The bus will normally have several incoming and outgoing connections.
After all, that is the purpose of the bus. Any fault on the bus requires that all brakes... incoming and outgoing must be opened. So typically the bus zone area will overlap the generator area like this.
You can see that these generator breakers will operate either for a fault within the generator zone or a fault in the bus zone. The next area in this particular power system is the transmission line zone, and once again, this overlaps the bus zone at either end. Hence, these breakers will open for a line fault and also for a fault on its respective bus. In this particular substation, we have a transformer, which reduces voltage down to distribution level and feeds the distribution bus.
So we have a transformer protection zone, and this overlaps the bus zone on either side. On many systems, a sub-transmission line zone would be installed between the transmission and distribution systems. In this example, the distribution line feeds a particular industrial customer who has installed large motor loads.
So we have further zones of protection. Here is the distribution line zone overlapping the distribution bus zone, and at the other end overlapping the motor protection zone. Now remember, we're not talking about the type of protective relays installed, only the zones of protection.
In each zone, primary protection is installed to protect the equipment within that zone. In addition to this, backup protection is provided from other relays or from duplicate relays. It is no coincidence that as we go through this video training program, we'll be looking at each of these zones in great detail, studying the types of relays, protective schemes, and configurations employed in current practice.
Looking at the list of videotapes, you will see generator protection, transformer, reactor, and capacitor protection, bus protection, motor protection, line protection, that is, transformer protection. transmission, sub-transmission, and distribution, pilot protection, system stability, including re-closing and load shedding. But before we get into that, we'll have to study in the first tapes some of the basic technology and fundamentals to help us understand what happens to the power system under fault conditions.
Up to now, we've been talking about protective relays. In fact, the whole thrust of this video program is in the application of protective relays. The most common types of relays used for protection are overvoltage, Voltage relays, under-voltage relays, over-current relays, directional relays, distance relays, differential relays, and I'm sure you can think of many others. We'll be talking about these.
types of relays in the next videotape and as we proceed on through the series. However, there are other relays installed on the system which do not cause tripping of breakers for protection. But a knowledge of these relays is important in operating and maintaining the power system.
One such classification is that of regulating relay. A typical example is the type of relay used to change the taps on a transformer. Another regulating relay is that used to adjust the governor's set point on generating equipment and so control the power output.
Synchronizing relays are used to check the phase angle before allowing the paralleling of two systems or an incoming generator. Another type of relay is the monitoring relay. An example of this is where the relay is used to monitor the continuity of circuits within breaker trip circuits. Any failure will result in an alarm to the operator. You'll find a large number of auxiliary relays installed on every power system.
For example, in protection schemes, auxiliary relays are often used to amplify the action, which results from operation of protection relays. For example, supposing this bus differential relay operates due to a fault on the bus. When its contact closes, it will energize an auxiliary relay. This relay, in turn, will close a multiple set of contacts, which will result in tripping all of the breakers connected to that bus.
Another type of relay which is extremely familiar to system operators is the reclosing relay. This relay will cause a tripped breaker to reclose after a short time interval, say 30 seconds. But why would we want this to happen? Surely we wish to clear and isolate a fault.
Well, the vast majority of faults on overhead lines are due to lightning. The high voltage flashover to ground creates a flow of fault... current which trips the breaker on over current or perhaps over voltage.
However, the fault is only temporary in nature and will be removed as soon as the breaker trips. Therefore, when the breaker is Reclosed by the reclosing relay, the fault will have disappeared, and the line can continue operation as normal. However, if the fault is permanent, for example, perhaps a tree limb has fallen onto the line, then the protection will sense that the fault condition persists and will trip the breaker again. The reclosing relay may be set to lock out at this point, or it may be set to permit one or more attempts. at reclosing.
Now don't worry too much about memorizing all of the details. We'll be looking at all of this material in far greater depth in future tapes. One of the problems that concerns operators and relay personnel is how to measure the level of performance of the relays. Will the protection system work properly when needed?
Regular maintenance and testing is vital so as to assure us that the relay relays will operate when required to do so. But this is not enough. We also need to know how the relays actually performed during incidents of actual fault conditions.
After any incident, it is essential that all of the relevant information be recorded and analyzed. This analysis will require good coordination and cooperation between both operations and relay departments. In most utility companies, operation of the protection scheme will be classified as correct only when the following conditions have been met. That is one, at least one of the primary...
operated correctly, two, none of the backup relays operated to trip for the fault, and three, the faulty area was properly isolated in the time expected. Obviously, knowledge of all conditions on the system at the time of relay operation must be known. This will bring to light, in some cases, incorrect operation of the protection system. This could cause, perhaps, isolation.
of a no-fault area, or even worse, a failure to isolate the trouble area. The reason for incorrect operation of the protection system could be, one, incorrect setting of relays, two, failure to change protection scheme to keep pace with changing circuit configurations, that is, inadequate protection, or three, failure of some part of the protection system, such as the relays themselves, breakers, CTs or VTs, the station battery, the circuit wiring, and so on. With all the variables involved, it's often quite difficult to carry out this post-mortem and deduce what actually happened.
Fortunately for us, nowadays most power systems have installed data recording equipment, oscillographs, and fault indicators that will indicate conditions before and after the fault. These provide valuable assistance in evaluating the actual performance of the protection system. To summarize now, we can say that there are five... Basic factors in application of protective relays.
And these are 1. Reliability, 2. Selectivity, 3. Speed of operation, 4. Simplicity, and 5. Cost. The last two items speak for themselves, but let's look a little closer at the others. First, we have to rely upon the relay or relay system operating correctly.
That is, to operate and... trip out the faulty circuit when it's necessary to do so. The reliability of the relay is tested by inputting current and voltage, which simulate fault conditions.
The time of operation can be measured in relation to the degree of fault condition. A second aspect of reliability is that the system must not trip out during normal operation. Another important factor of relay performance is selectivity. A relay system is selective when it isolates only the faulty circuit and leaves the rest of the system operating intact. When the relay is...
When correctly set, its selectivity is such that it operates as fast as possible within the primary zone, but it will have a delayed action in the backup zone. This will give time for the primary protection in the external area to operate. This is also known as coordination. The terms high-speed relay and instantaneous relay are often used interchangeably.
This means a relay which operates within 50 milliseconds, that is, three cycles. But in opening a circuit, we also have... to consider the operating time of the circuit breaker. In general, modern circuit breakers operate within one to five cycles. So we can say that the total clearing time, that is the relay operation plus the breaker, ranges from about four to eight cycles, that is, 70 to 130 milliseconds.
But high-speed relays are not always desirable. Time coordination is often required between protective relays to allow them to operate in the correct sequence. For example, in the primary system, relay operating times may be slowed down to between 0.2 to 1.5 seconds. Now, in this tape, we've presented an overview of the subject of protective relay applications. We've looked at the principles and fundamentals of relay application, as well as the general philosophy involved in operation, in maintenance, and in design of the protective relay systems.
This is just the beginning. We'll be getting into much more complicated material in future tapes. For now, let's get started.
For now, switch off the tape and thoroughly go through this material in your workbook.