Electrical Protection

FOREWORD

The subject entitled ‘Electrical Protection’ is one of a series which comes under the heading of Electrical Technology. This and other series have been prepared for our employees who

attend our trai ning programmes. .~ _..

The three ‘Fundamentals of Electricity’ manuals introduce the subject of electrical power and provide a basis for further study of related’ topics such as power systems, generation, distribution, motors,~control, protection a6d electrical safety. This manual has been designed so that it can be used for self-study;~and, w.ith this in mind, a series of questions and answers has been incorporated.

A list of the electrical power manuals is included inside the front cover, and a list of all training manuals in the s’eries is given on the inside of the back cover.

Harry To/t

Shell Expro Training, Aberdeen.

Shell Expro is the major operator exploring for and producing oil and gas in the United Kingdom -~ working alone and in joint ventures with third parties. In the North Sea it is the operator for a SO/50 joint venture with Esso, where the projected output from fields already in operation will meet more than a third of the UK’s estimated oil needs and over 12% of its natural gas requirements.

Chapter 1’ Chapter 2 Chapter 3 Chapter 4. Chapter 5 Chapter 6 Chapter 7 Chapter 8 Chapter 9 Chapter 10 Chapter 11 Chapter 12 Chapter 13

CONTENTS

Faults and Fault Levels Overcurrent Protection Discrimination

Earth-fault and Earth-leakage Protection Differential Protection

Undervoltage and System Undervoltage Protection Additional Forms of Protection

Generator Protection Transformer Protection. Cable Protection Motor Protection Questions and~Answers Page 1 4 11 30 34 42 48 50 52 59 65 68 80 91

CHAPTER 1

INTRODUCTION

TO PROTECTION

1.1 THE REASONS FOR PROTECTION

Electrical plant, machines and distribution systems must be protected against damage which may occur through abnormal conditions arising.

Abnormal conditions may be grouped into two types:

(a) Operation outside the designed ratingsde t~bverloadifigor incorrectfunction- ing of the system.

(b) Fault conditions due usuallyvto breakdown of some part’of the system.

Condition (a) is usually ‘chronic’ -that ii, it may persist for some time and is often accept- able for a limited period. It may give rise to temperatures outside the design limit of the machines and equipment, but, unless these are very excessive or very prolonged, it seldom causes sudden or catastrophic failure. It can usually be corrected before it leads to breakdown or a fault condition.

Condition (b) on the other hand is ‘acute’ and arises from electrical or.,mechanical failure which, once established, produces a condition beyond.control. It usually gives rise to very severe excess currents which will quickly cause catastrophic failure of other electrical and mechanical plant in the system unless the fault is rapidly isolated. It may be caused by a breakdown of insulation due to a material failure or overheating or to external conditions such as weathe~r, or it may be due to physical damage to an item of plant or cable.

Automatic protection against conditions (a) and (b) is possible~ in electrical installations because it is easy to measure various parameters, to detect abtiormalities, and to set in motion the protective action the instant an abnormality arises.

Protection of an electrical system is provided for,one or more of the following principles:

(a) To maintain electrical supplies to as much of the system as possible after a fault has been isolated.

(b) To protect the generators and other plant against damage due to abnormal conditions and faults.

(c) To protect the consumer equipment against damage due to abnormal conditions (e.g. overload).

(d) To isolate faulted equipment to limit the risk of fire locally. (e) To limit damage to the cable system resulting,from a fault.

These principles will determine the type of protective equipment fitted in any installation. It will be noted that principle (a) conflicts with the other requirements to some extent. For example, the best way to protect a generator againstdamageby fault currents is to disconnect it, but it would not then be available to supply other consumers. For this reason a method of disconnection (called ‘discrimination’) has been devised. It is fairly complex and has to be very carefully ,engineered. ,It is dealt with in Chapter 4.

Ail the protection devices in this manual are assumed to be fed from voltage transformers (VT) or current transformers (CT). In high-voltage systems this is always the case. In low- voltage systems, such as 44OV, voltage-operated devices are sometimes fed direct from the busbars through fuses without an intervening VT. Except where currents are small, current- operated devices always use CTs even on low-voltage systems.

The above five principles relate mainly to the protection of plant and equipment in the system. There remains of course the protection of personnel.

An arc may occur at the point of the fault. Apart from possibly burning or blinding anyone in the vicinity, an arc in a high-power system may produce enough heat to melt heavy copper bars or even structural steel in a very short time, and a rapidly spreading fire may result. Arcs are particularly dangerous in areas where flammable gas may be present. It is vital therefore that the source of power which is feeding the arc should be cut off as quickly

as possible.

1.2 PRINCIPLES OF PROTECTION

The fundamental principle of protection is to disconnect and isolate the faulty part of the system so that the fault is not sustained and aggravated by a continuing flow of power into it, and the rest of the system is not damaged and can revert to its normal state.

Generally speaking this means automatically detecting the fault condition by means of a suitable device and disconnecting the faulty section by means of a circuit-breaker or other

interrupter. For some purposes the two functions are combinrd in one item of switchgear, as in a moulded-case circuit-breaker. In many cases protection is provided by fuses, in which the functions are inseparable. Protection relays as devices xe described in the manual ‘Electrical Control Devices’, and fuses are discussed in Chapter 3 of this present manual.

The occurrence of a fault is indicated by various quantities, usually excess currents, depend- ing upon the nature of the fault. The way in which the protection devices respond to faults, in terms both of magnitude and of time, is very important for several reasons:

- _{The affected part of the system should be disconnected quickly, before any} av&dable damage is done.

- _{The protection should not operate unnecessarily. Transient disturbances are} liable to occur on most systems for many reasons connected with operation, and most electrical plant is capable of operating safely with moderate over- loads for short periods.

- _{If the amount of .equipment disconnected is to be kept to the minimum} necessary to clear the fault, the sensitivities of the various protection devices which respond to the fault must, as far as possible, be so graded and related that only that device needed to clear the fault actually operates. This is the principle known as ‘discrimination’, which is discussed in Chapter 4.

1.3 DISCONNECTION DEVICES

The means of detecting a fault and the means oi disconnecting it are equally important. There are three categories of devices used to disconnect faulty circuits:

1.4

Circuit-breakers. These are generally capable of interrupting the maximum fault currents that can flow in the circuits which they feed. Since under some fault conditions the current may rise to ten or more times the normal full-load current, the design and selection of circuit-breakers is of great importance. Several types of circuit-breaker are in use with different arrangements for arc suppression - air-break, oil-break, sulphur hexafluoride (SF,) and vacuum; these are described in detail in the manual ‘Electrical Distribution Equipment, Part A’,

Contactors. Contactors are rated to close onto the most severe’faults but have limited breaking capacity; in most cases this is less than the maximum possible fault current in the circuit which they feed. Therefore they have usually to be supplemented by fuses. Contactors may be air-break or vacuum-break; they are described in more detail in the manual ‘Electrical Distribution Equipment, Part A’. Fuses. A fuse constitutes an intentional ‘weak--link’ in an electrical circuit and,, suitably rated, is particularly apt for the quick interruptionofshort-circuit~currents.

Fuses, are described in Chapter 3. They are expendable and have to be replaced after they have operated. They are very costly.

PROTECTION AND SYSTEM DESIGN

No system of protection can be designed without knowing the conditions in the network which it.has to protect. This means that the level of fault currents at various pojnts of the network must be known in advance so that the right type of switchgear may be installed and a proper system of~protection worked,out.

The first tasks therefore is to calculate the ‘fault levels’ at all those points in the, network where switching is to take place. Fortunately this is not a difficult calculation, and it is described in Chapter 2.

CHAPTER 2

FAULTS AND FAULT LEVELS

2.1 GENERAL

An electrical network normally operates within its designed rating. Generators, transformers, cables, transmission lines, switchboards, busbars and connected apparatus are each designed to carry a certain maximum current. Most can carry a moderate overload for a short time without undue overheating.

However, if a fault should develop somewhere in the system, that is to say a phase-to-phase short-circuit or a phase-to-earth breakdown, then all connected generators will at first feed extremely high currents into that fault, which will be limited only by the impedance of the complete circuit from generator to fault. Fault currents can be ten or more times the normal full-load current.

Such currents will quickly cause intense overheating of conductors and windings, leading to almost certain breakdown unless the.y are quickly disconnected. They will also give rise to severe mechanical forces between the current-carrying conductors or windings. All such apparatus must be manufactured to withstand these forces. A fault current of 50 OOOA (rms) flowing in two busbars 3 inches apart will produce between~them a peak mechanical force of nearly half a ton-force per foot run of bars.

The pui-pose of automatic protection is to remove the fault from the system and so break the fault current as quickly as possible. Before this can be achieved, however, the fault current will have flowed for a finite, if small, time, and much heat energy will have been released. Also the severe mechanical forces referred to above will already have occurred and will have subjected all conductors to intense mechanical stress.

2.2 FAULT LEVEL CALCULATION

In order td design electrical equipment to withstand the expected thermal and mechanical stresses, and to engineer the protective system to operate decisively and quickly, it must be possible to calculate the maximum ~fault current to be expected anywhere in the system under the worst possible conditions.

Phase-to-phase and phase-to-earth faults may be nietal-to-metal, but more probably they will be arcing faults where the arc itself has some resistance which will reduce the flow of fault current. However, for calculation purposes the worst condition is considered, and short- circuits are assumed to be ‘bolted’ - that is, it is assumed that all three conductors are firmly bolted together and that the fault itself has zero impedance.

In order to understand the fault conditions in an a.c. network, it will be helpful to consider what happens in the simpler d.c. case.

2.2.1 D.C. Case

Referring to Figure 2.1, suppose the full-load current I of a d.c. generator is produced with an external load resistance R. If E is the emf and r the internal resistance of the generator, then the internal voltage drop is /.r an~d the terminal voltage (that is, rated voltage) V.of the generator at full load is E - /.r. Suppose the internal drop is, say, 20% of the open-circuit voltage E (assuming that there is no automatic voltage regulation).

FIGURE 2.1

D.C. GENEYATOR ON LOAD

If now the external load R is decreased so that the current doubles to 2/, then the internal drop increases to 2/x, or 40%. If R is further reduced so that the current is trebled to 3/, then the internal drop increases to 3/x, or 60%. Similarly a current of 4/ will cause an internal drop of 80%, and 5/ would produce 100%.

A 100% internal drop means that the whole emf is used in overcoming the internal drop, and there is no voltage left between the terminals - that is, they are effectively at short- circuit. Put the other way, a dead short-circuit across the generator produces B current five times (1 + 20% or 1 + 0.2) full-load current. The generator is then said to have an internal resistance of 20%. This is an alternative way of expressing it instead of in ohms.

2.2.2 A.C. Case

The same argument applies to the ax. generator shown in Figure 2.2, except that, instead of external and internal resistance, there is now impedance. However, in all ax. generators the internal impedance is almost wholly reactive, and it is therefore customary to talk of a generator’s ‘reactance’ x and to ignore the resistance. It is, like the resistance in the d.c. case; expressed as a percentage. Therefore a generator with a reactance of 20% will deliver 1 + 0.20, or five times, full-load current on short-circuit. This method of using percentages rather than ohms avoids having to con,sider the size (kVA) or voitage of the particular generator. The above applies whatever its size or voltage.

FIGURE 2.2

A.C. GENERATOR ON LOAD

An a.c. genes-ator has in fact a varying reactance, which increases as the fault proceeds, due to its complicated magnetic behaviour. For fault calculation purposes however the lowest reactance at the beginning of the fault is always taken; it is the ‘subtransient’ reactance and is typically between 8% and 20% on most generators. This is the most severe condition.

A similar argument applies to transformers where the reactances are typically between 4% and 10%. A transformer reactance however is fixed and does not vary as the fault proceeds.

5000kVA BASE

FOR CALCULATION

(a) TYPICAL N,ETWORK

15%

u

-iI

(b) WITH LV SECTION BREAKER OPEN

(c) WITH LV SECTION

BREAKER CLOSED

FIGURE 2.3

SIMPLE FAULT CALCULATION

Figure 2.3(a) shows a typical, but simple, network comprising two generators, two trans- formers and an WV and LV distribution system. A fault at a point P on one of the HV feeders would, if all HV breakers were closed, be fed by both generators in parallel. A fault

at a point Q on the LV system would be fed by both generators (as before), but they would be in series with one transformer- if the LV section breaker web-e open, or with both trans- formers in parallel if it were closed.

The exact calculation should, strictly, also take into account the resistances of thegeneratol-s and transformers as well as the impedances of the connecting cables, but for a rough calcu- lation with platform-sized lengths of cable these can be disregat-ded.

Figures 2.3(b) and 2.3(c) show the reactance equivalent of each of the elements of the network, with the percentage reactance placed against each. Since the size of each generator is 5 OOOkVA the impedance of all other elements, such as that of the transformers, mustbe raised to th~is ‘base’. So, though the transformers are each rated 5% at 5OOkVA, they are entered as 50% at 5 OOOkVA, giving the same short-circuit current. The ‘adjusted’ reactances are shown in Figures 2.3(b) and (c) in red. it should be noted that any figure, such as 100 OOOkVA, may be chosen as a base; it makes no difference to the result. Choosing as a base the kVA of the largest generator is merely a convenience. ,(For onshore grid network calculations 100 OOOkVA base is usually chosen. In those cases generator and transformer resistances and cable impedances cannot be ignored.)

The adjusted reactances are then resolved by ordinary series-parallel network methods until they become a single reactance. Thus in Figure 2.3(b) the reactance up to the point P with both generators connected is two 15% in parallel, equivalent to one 7%%. To the chosen base of 5 OOOkVA the fault level at P is:

5 006

- _0.075 = 67 OOOkVA, or 67MVA

(Note. For the purpose of calculation, percentages are expressed as ‘per unit’. Thus 7%% = 0.075 p.u.)

For point Q with one transformerconnected there is a further series reactance of 50% to add, making 57%% in all. The fauhlevel at Q would be:.

m ‘= 8 7OOkVA, or 8.7MVA

For point Q with two transformers in parallel (Figure 2.3(c)) there is a further series reac- tance of 25% to add (derived from the two 50% in parallel), making 32%% in all. The fault level at Q would then be:

5

0.325 = 1,5 4OOkVA, or 15.4MVA

If the generators had been of different sizes - say 5 OOOkVA and 2 5OOkVA, each with reactance 15% - the larger would have been chosen as ‘base’ and the smaller raised to it - that is, call it 5 OOOkVA at 30%, and proceed as before:

This calculation, though much simplified, illustrates the basic method of making fault calcu- lations. It shows too the advantage of regarding all reactances as percentages; the actual voltage levels have not come into the calculation. It also illustrates the considerable reducing effect of transformers on a system fault level.

The fault levels so calculated would apply respectively to the whole HV system and the whole LV system, and they are usually marked in MVA on drawings. The switchgear at each level must be capable of breaking the currents appropriate to those levels, and all conductors, busbars, cables, etc, must be able to withstand the thermal and mechanical stresses induced by those currents. Armed with the result of his fault calculations, the designer will specify exactly what the various items of equipment are required to withstand.

Fault levels calculated as shown are expressed in MVA, which is usually sufficient for most purposes, but if act+1 fault currents are needed, the MVA is converted to current (kA) by dividing by,/3 times the voltage (kV). Thus:

67MVAat 6.6kV = - 6.g3 = 5.9kA =5 900A

8.7MVA at 440V = 0.4;&3 = 11.4kA=ll 400A

15.4MVA at 440V = ,,&$, = 20.2kA = 20 200A

(Note that MVA +43kV gives the current in kA.) These are all runs symmetrical currents.

From the above calculations two points should be noted:

- _{A single transformer between the source of supply and an LV switchboard} greatly ‘cushions’ the MVA fault level beyond it and reduces it drastically. In this case an HV fault level of 67MVA is reduced by the transformer to 8.7MVA. - _{Notwithstanding the great reduction of MVA by a transformer, the actual}

fault current on the LV side is actually increased - in this case from 5 900A to 11 400A. This is because the smaller MVA is obtained fror,l a still smaller voitage.

2.3 FAULT LEVELS AT LOW VOLTAGE SWITCHBOARDS

Whereas apple designs of switchgear exist to handle the fault levels to be found on the largest offshore and onshore high-voltage systems, this is not the case on the low-voltage boards. As will be seen from the above calculation, the LV fault currents are in general higher than the HV - in some cases much higher indeed. On many offshore installations the

LV fault level with the LV section breaker closed (that is, with both transformers feeding in parallel) exceeds the breaking capacity of the largest LV circuit-breaker available.’

It is therefore ~necessary to ensure that the switchgear fitted is not subjected to such a possible fault. From the above calculation it can also be seen that the LV fault level with one transformer feeding is about half of that with two. Therefore it is arranged in such cases that the two transformers should no? be allowed to feed in parallel. The LV section breaker is normally kept open when both transformers are feeding (the normal condition). The section brea!;er may only be closed if one or other transformer supply breaker is open. This is known as the ‘two-out-of-thl-ee’ method. Any two LV breakers out of the three (two incomers and one section) may be closed at any one time, but not all three. Interlocks

.~p@vetit this. .~I.

However, this arrangement may be temporarily ‘cheated’ and the vulnerability accepted when changing over from one transformer to the other. FOI- a short period the operation of the interlock is delayed to avoid interrupting supplies to the board. If one of the three breakers is not opened within that short time (typically 30 seconds) the section breaker will trip automatically.

2.4 ASYMMETRICAL FAULT CURRENTS

The fault currents as derived from the above calculation. usins the oercentage reactances of the various items of plant, are all ‘rms symmetrical’.

rms Symmetrical Current

FIGURE 2.4

ASYMMETRICAL FAULT CURRENT

The actual currents which occur in the early part of a fault however are generally asymmetrical, giving a greater heating rate. Moreover the highest mechanical forces will occur with the first asymmetrical peak of current, as shown in Figure 2.4. This can, with 100% asymmetry, be up to 2.55 times the rms symmetrical value, so the 67MVA at 6.6kV referred to above, equivalent to 5.9kA rms symmetrical, can rise to 15kA asymmetrical peak. It is this latter figure which determines the mechanical strength of.the busbars and other equipment.

When a fault current is quoted in kA it is always wise to add the words ‘rms symmetrical’ if that is what is meant. This avoids confusion with ‘kA peak asymmetrical’ which is also often quoted in addition. Fault levels quoted in MVA are always rms symmetrical.

2.5 PROSPECTIVE FAULT CURRENT

In, some cases the actual fault current, even with a bolted short-circuit, may be limited by the operation of the protection device itself - notably in the case of a current-limiting fuse which can interrupt the current before it reaches its first peak (see Chapter 3, para. 3.3). In that case the current never attains its calculated level. However for the purposes of calcula- tion it is assumed that no such limiting effect occurs and that the current will reach its calculated value. This value is called the ‘prospective fault current’, even though, in certain given systems, the fault current will not reach that level.

Fuses are given the credit in their ratings for interrupting the full prospective fault current notwithstanding that they do so by preventing it ever happening.

2.6 MOTOR CONTRIBUTION

A factor that may have a significant effect on the fault level of a system which includes an .~ appreciable proportion of motor loads is that known as ‘motor contribution’. This refers to short-circuit current which is generated for a very brief period by a short-circuited induction motor as a result of magnetising currents still circulating in the rotor. (Synchronous motors also generate short-circuit current but are not likely to be encountered in Shell installations.) The magnitudes of such currents are not easy to determine with any accuracy, but they are commonly roughly estimated on the basis of a percentage reactance in the motor assumed to be about 30%. Thus a motor that presents a full load of 1 MVA is calculated to contribute l/O.3 = 3.3MVA to the fault ievel of the circuit which supplies it, and it will contribute to the fault level at any point in the system as if it were a IMVA generator with a subtransient reactance of 30%. This should be added to the calculated system fault level.

2.7 NON SYMMETRICAL FAULTS

A short-circuit between two phases results in a lower fault cukent than does a symmetrical short-circuit, because it is driven through the impedance of two phases by the line voltage which is only ,/3 times the phase .voltage. This condition therefore requires no further consideration here.

2.8 EARTH FAULTS

Earth-fault currents, especially when iimited by earthing resistors,are dealt with in Chapter 5. Havir;g only 1143 of the system voltage behind them, they are in general lower than the short-circuit fault currents and will not therefore influence the fault level calculations.

CHAPTER 3 OVERCURRENT PROTECTION

3.1 BASIS OF OVERCURRENT PROTECTION

Overcurrent protection is related primarily to heating effects in, and in some circumstances

to electromechanical forces on, electrical conductors and may cover both fault and overload protection.

Overcurrent protection methods may be divided into three categories according to the type of device used:.

- _{Overcurrent relay tripping a circuit-breaker or contactor (but see Chapter 1,} para. 1.3 for the limitations of contactors).

- _{Direct tripping device (‘release’) on a circuit-breaker or Contactor.}

- _Fuse.

A distinction should be made between~ the terms ‘overcurrent’ and ‘overload’. Whereas the mechanical overloading of a machine will certainly cause overcurrents, OvercUrrents can occur from causes other than overloading - for example, stalling or single-phasing of a motor, short-circuits Or earth faults, none of which is an overload.

The term ‘overload’ should be reserved for mechanical loading, and the word ‘overcurrent’ should be used in Its literal sense. All the devicesdescribed in thischapterare trueovercurrent

sensors.

3.2 OVERCURRENT PROTECTION RELAYS

Overcurrent devices, though all depend on an excess of current to operate them, are of several different forms; these are described below. The official abbreviation (BS 3939) for each type is also given.

3.2.1 instantaneous Overcurrent (OC)

An instantaneous overcurrent relay is shown pictorially in Figure 3.1. It consists of a simple iron armature attracted by a coil carrying the current from a line current transformer and restored to its rest position either by gravity or by a control spring. When the current in the coil just exceeds a certain preset value, the pull on’the armature overcomes the spring or gravity and causes it to close. In so doing it operates auxiliary contacts which initiate a tripping circuit or other desired function.

Though termed ‘instantaneous’ this type of relay nevertheless requires ‘a small but finite time to operate; this /s usually taken to be a maximum of 0.2 seconds, but it is often much less. The current/time characteristic is thus a ‘square’ one as indicated in Figure 3.1 (c). The value of the current required to operate the relay is set by the screw adjustment at the top. In a single-phas6 system a current transformer in one line,is connected to the relay coil (see Figure 3.1 (a)). In a 3-phase system a current transformer in each phase is connected to one of three relay coils (see Figure 3.1(b)). The three relay elements may be enclosed in one case or in separate cases. However, in a 3-phase, 3-wire, system any overcurrent in one line

Trip Circuit

(a) SINGLE PHASE

OC R&v

-T--Fe

4

TYPICAL INSTANTANEOUS OVERCURRENT RELAY

must be accompanied by an overcurrent in one or both of the return lines. Therefore, to achieve complete overcurrent protection in a 3-wire system, it is only necessary to provide overcurrent relay elements in two of the three phases (see also Figure 5.2).

3.2.2 Inverse Time Overcurrent (OCIT) ’

An inverse-time overcurrent relays is shown pictorially in Figure 3.2. It has an ‘induction- type’ movement similar to that of a household meter. It consists of a rotating aluminium disc driven by a shaded-pole magnet element which receives the driving current from the CT in the circuit to be monitored. As in a household meter, the disc also revolves between the poles of an eddy-current brake magnet; it is restrained by a light pre-tensioned control hairspring.

The relay is used with current transformers in single-phase or 3-phase systems as described for simple overcurrent type and as shown in Figures 3.2(a) and (b).

When normal current flows from the CT a driving torque is applied to the disc, but it is prevented from rotating by the pre-tensioned spring. If the current exceeds a certain preset value the disc begins to move and is driven, against the drag of the brake, right round until a contact on the spindle touches a fixed contact. The greater the excess of current above this

I

1-

: 6- Circuit Circuit

(a) SINGLE PHASE

. . .

I I I

Ii

-e -id Hieh Set

El&&t (as Fig 3.1) be added Minimum Operating Current (c) CHARACTERISTIC CURVE CU~~~~t Setting Setting Sockets FIGIJRE 3.2

TYPICAL INVERSE TIME OVERCURRENT RELAY

value, the greater the drive torque and the faster the disc tries to rotate. But the drag of the eddy-current brake also increases with the speed of rotation, and itsslowingeffect isgreatest at the highest currents.

The combined effect of this is to produce a time/current characteristic as shown in Figure 3.2(c). For currents less than a certain .min,imum the disc does not move at all. For currents in excess of the ‘just move’ minimum the disc moves, and the operating time becomes shorter with increasing current - that is, it has an ‘inverse-time’ characteristic. This is very important when dealing with ‘discrimination’ (Chapter 4).

Two setting adjustments are possible with this relay: current and time. Current adjustments are made by fixed taps on the driving coil. They are +sually set by moving a peg between a number of holes on the front of~the relay face. Typically the range is from 50% to 200% of the normal operating current (1 A or 5A depending on the CT used). The time adjustment is made by moving the ‘fixed’ contact so as to increase or decrease the travel of the disc before the contacts touch. The relay is fitted either with a time-scale marked in seconds, or more usually with a ‘time multiplier’ adjustment, which is used in conjunction with curvessupplied with the relay.

Relays could be custom-made to operate with any given CT and any given circuit data, but in practice relays are manufactured t.o certain standard conditions, and adjustments are provided to match this standard relay into a wide variety of circuit arrangements. This results in a fairly complicated setting procedure which is described in detail below.

Movable _{Plug I I}

OUT Relay Operating Coil

FIGURE 3.3

OClT RELAY CONNECTION

3.2.3 Setting of an Inverse Time Overcurrent Relay

To understand the setting of the current and timing adjustments and the interaction between them, consider the particular circuit shown in Figure 3.3. A standard inverse-timeovercurrent relay designed to work on a nominal secondary current of IA is fed from a 400/1A current transformer. Suppose the normal full-load line current is SOOA, then at full load the CT secondary current will be 1.25A - higher than the relay’s designed working current. The relay must. therefore be slightly desensitised. The operating coil has several taps, and a tap which reduces the effective turns by 20% is chosen by inserting the plug in the 125% socket. Thus 1.25A (the actual or ‘effective’ current) through 20% less turns has the same effect (ampere-turns) as the designed IA through the full turns; that is to say, with the 1.25A coming in, the relay will operate as designed for a IA input, and it will have the same designed characteristic time/current curve. Thus the current plug setting compensates for any deviation between the CT rated primary and the actual full-load current. If there is no deviation the plug is set at 100%.

For cases where the CT primary current rating is greater than the full-load current, the relay must be made more sensitive, and the tappings are extended below the nominal 1A (100%) so as to increase the effective turns (an ‘auto-transformer’ effect). Hence there are 75% and 50% plug positions. It should always be remembered that settings below 100% make the relay more sensitive, and settings above 100% make it less sensitive.

The plug settings 50% to 200% are seven discrete sockets, and no intermediate position is possible. If a calculated setting (e.g. 1 loo/) D comes between two positions, the next higher setting should be used.

Some relays, instead of having plugs marked in current percentages as already described, are marked in CT secondary amperes --for example 0.5, 0.75, 1.0, 1.25, 1.5, 1.75 and 2.OA instead of 50%, 75%, lOO%, 125%, 150%, 175% and 200% - but the purpose is the same. Other relays are designed for use with 5A current transformer secondaries. If the plugs are marked in current amperes, the markings would be 2.5, 3.75, 5.0, 6.25, 7.5, 8.75 and 1 O.OA.

If the calculated line fault current is, say, 5 OOOA - that is, IO times the normal full-load cur-rent in the case of Figure 3.3 - the CT secondary will then give 12.5A. Note that this is 10 times the plug setting, not 10 times the nominal 1 A (= 100% setting). Consequently the horizontal axis of the characteristic (set Figure 3.4) is scaled in ‘Current (Multiples of Plug Setting 50% - 200%)‘, not simply in multiples of full-load current.

The purp~ose of this exercise is to determine what current and timing settings should be put on the relay to achieve any desired time delay in its operation when subjected to a given short-circuit current. (The desired time delay will come out of the discrimination caicula- tions which~determine the delays required at various points of the network -see Chapter4.) It therefore only remains, having determined the current operating plug setting for the calculated short-circuit current at the point where the relay is installed, to choose the time multiplier which will give the desired time delay.

aperating Time (Secondsl 1 0.8 0.6 (= Time Multiplier Settings) Relay _ Operating Line 1

Current$lultiples40f Plut S&:50% - 2:%) 30

FIGURE 3.4

RELAY SETTING CURVES

Figure 3.4 is a set of time/current characteristic curves as provided with a typical OCIJ relay. Both scales are logarithmic.

For the circuit of Figure 3.3 it has already been determined that a plug setting of 125% is required, and that a short-circuit current of 5 OOOA will mean a current 10 times that of the plug setting. If in Figure 3.4 a vertical line is drawn through the current multiplier point ‘IO’ on the horizontal axis, this is the ‘relay operating line’ for that short-circuit current.

Suppose the d~iscrimination calculation requires a time delay of 1.35 seconds at this point in the network. Draw a horizontal line through the point 1.35s on the ‘Operating Time’ (that is vertical) axis. Let it cut the vertical relay operating line at point P.

It will be seen from Figure 3.4 that P lies b~etween the Time Multiplier curves 0.4 and 0.5. By interpolation it would be 0.44. Although such a setting would be possible, it is usual to

choose the next higher, namely 0.5 (point Q). This setting will actually give a time delay of 1.5 seconds at 5 OOOA - very slightly higher than the desired 1.35, which errs on the safe side.

Similarly, if a calculated current plug-setting came between two sockets, the next higher plug-setting should be used. This too errs on the safe side in making the relay marginally less sensitive, needing slightly more time to operate for a given fault current.

It is required to determine the current and timing settings on an OCIT relay to give a 1.35s delay with a short-circuit current of 5 OOOA. Full-load current is 450A and the CT-ratio is 400/1A. (Note that in this example the full-load current is slightly different from before in order to show how an ‘in-between’ figure should be interpolated.)

The setting sequence is shown in Figure 3.5 and uses the curves of Figure 3.4.

Full load current of circuit Rated primary LI current of i EFFECTlVE _CT LuRRENT

I 0, -9 ..__ --&:-^ /Y” = Short circuit

C”“e”t (If intermediate.

(as a fraction) _I

I (i.e. calculated short circuit L.lse next higherj

FIND RELAY OPERATING _{DRAW HORIZONTAL}

LINE LINE THROUGH THE

‘SC

- REQUIRED TIME DELAY -

TO CUT VERTICAL RELAY

Effqctive Current OPERATING LINE, POINT ‘P’

current at point of fault)

Example

Plugsetting=$$x 100=112.5%(use125%)

400/l ,~ ,,,=45OA ~ l&.jOOOA

Effective current = 400 x 1.25 = 500A

Relay operating line = E = lb

I----

q

Desired Time Delay 1.35s

Desired time delay = 1.35s Time multiplier setting at crossover (‘P’)

= 0.44 bf interpolation. Use next higher 0.5 (‘Q’) Reading across, actual time delay achieved = 1.5s FIGURE 3.5

It should be noted that the plug setting in this case comes out at 1 .125, or 112.5%. Th,ere is no such plug position, so the next higher one, 125%, is chosen.

From here, the plug having been inserted in the 125% position, carry on as before. The 5 OOOA short-circuit current represents 10 times the chosen plug setting. Draw a vertical line through ‘10’ on the Current Multiplier axis of Figure 3.4 and let itcut the horizontal through the desired delay time of 1.35 seconds. The crossing point Pfalls between theTime Multiplier curves 0.4 and 0.5, so the larger is chosen. This will give an actual time delay (horizontal through Q) of 1.5 seconds, slightly longer than the 1.35 desired.

3.2.4 Combined inverse Time Overcurrent and High Set Instantaneous Relay (OCIT/OC) An inverse-time relay may be equipped with an additional instantaneous element in the same casing but operating at a ‘high-set’ current value. This gives it the feature ofa combined ‘inverse-time and high-set instantaneous’ relay, the instantaneous feature overriding the time delay only on the most severe faults. An eiample of this additional feature is shown dotted in the drawing of Figure 3.2.

This arrangement is particularly desirable where overcurrent protection is installed,near the generator end of a network. It is at this end that discrimination requires the longest delays, and a purely inverse-time relay would allow a severe short-circuit to persist until eventually cleared. .An overriding high-set instantaneous overcurrent relay, fed through the same CTs and actuating the same trip circuit, would clear such currents very quickly. It would however operate only on severe faults and would take no part in fault currents below its own high setting. This feature is further investigated in para. 3.2.6, ‘Busbar Protection’.

Usually a 3-element OCIT relay (one per phase) would be combined with two instantaneous high-set elements in two phases only’- all in a single case (30CIT/ZOC).

3.2.5 Inverse and Definite Minimum Time (OCIDMT)

An inverse and definite minimum time overcurrent relay is shown pictorially in Figure 3.6. The current transformer arrangements with single-phase or 3-phase systems are similar to those for the simple overcurrent relay and are shown in Figures 3.6(a) and (b).

This relay is simply a variation of the inverse-time type shown in Figure 3.2, but here the characteristic, instead of tending towards zero time for the highest fault currents, now tends towards a definite and finite small value, as in Figure 3.6(c). This is built into the relay and cannot be adjusted.

The relay is similar in construction to the normal inverse-time type shown in Figure 3.2.

The purpose of this variation is to render the relay settings more accurate. All characteristic curves are subject to tolerance, and the separation of the sloping curves of Figure 3.2 at the high-current end for different relays has to be enough to allow for such tolerances. Therefore tripping delays would need to be longer than would be necessary with more accurate curves. The definite minimum time feature at the highest currents, making the curves horizontal at those currents, enables greater accuracy (that is, smaller tolerance) to be achieved, resulting in less separation of the curves and consequently shorter tripping times.

An OCIDMT relay may be combined with instantaneous high-set overcurrent elements as

described for an OCIT relay in para. 3.24. It is shown in dotted outline in Figure 3.6.

Trip Trip Circuit Circuit OCI DMT Relay

(a) SINGLE PHASE (a) SINGLE PHASE

III

(b) 3.PHASE

II

Time Multiplier Adjustment

Eldment (as Fig may be added Sett,ing SoZkets Plug Definite linimum +-‘---- Time :---.. I WI

* 4

TYPICAL INVERSE ANG DEFINITE MINIMUM TIME OVERCURRENT RELAY

3.2.6 Busbar Protection

A fault on a high-voltage busbar will produce severe overcurrents which should cause the generator overcurrent relays - the only protection that the generator has upstream of the busbars - to operate and clear it. However the generator inverse-time relays, being the last on the discrimination ‘ladder: will have a comparatively long operating time, despite the heavy fault current; it may well be of the order of 2 to 3 seconds in some networks.

During this time the short-circuit current will have passed from its initial large subtransient value, thl-ough the transient value and probably well towards its final synchronous value

which, as already shown, could well be even less than normal full-load. In this state there is no overcurrent at all, and the generator protection relays would probably not operate; there would then be no protection against a busbar fault which, by its very nature, could be highly damaging. There are several ways in which this situation can be dealt with, and these are descl-ibed below.

(4 Instantaneous

Instantaneous protection is b y the addition of simple high-set instantaneous overcurrent elements to the OCIT relay. With heavy faults these elements would cause an immediate trip

inverse-time element had worked off its long d&y. This was briefly mentioned in para. 3.2.4 but not in the context of a busbar fault.

(b) Voltage Restrained

This type of protection is by using ‘voltage-restrained’ inverse-time overcurrent relays for the generator. Operating T:-- ,O IcpC”“rfC\ 8 6 4 3 1 0.8 0.6 0.4 0.3 0.2 0.1 1 Current&ult?ples4af PluzSet8tinTSO% - 22d%) 30 FIGURE 3.7

VOLTAGE RESTRAINED INVERSE TIME OVERCURRENT RELAY

The operation of this type of relay is explained in the manual ‘Electrical Central Devices’, Chapter 2. It is a normal overcurrent inverse-time relay with an additional voltage-sensitive element which, under normal voltage conditions, produces a counter-torque and so restrains the drive of the overcurrent element. When voltage falls this restraint is lifted, allowing the overcurrent element to operate more rapidly - that is, it becomes more sensitive as voltage falls. The black curve in Figure 3.7 shows the normal (restrained) time/current characteristic similar to Figure 3.4 with time multiplier 0.3, and the red curve shows the change of charac- teristic (with the same time multiplier) as the voltage falls and the restraint is completely removed. For example, an overcurrent of three times the plug setting will cause the relay to operate in 1.8 seconds with normal voltage (restrained), but it will operate in 0.5 seconds under low voltage with the restraint removed. This allows the generator breaker to clear a busbar fault in a far shorter time than it would with normal OCIT protection (if indeed it would at all).

The change of characteristic as the voltage falls is a gradual process, and the black and red curves are the two limits - that is with full restraint and with no restraint. For partial fall of voltage there would be a whole family of curves in between.

There is another type of voltage-restrained overcurrent relay where the change of characteristic is not gradual but is abrupt. This type of relay is not strictly restrained, btit its sensitivity is increased by a discrete step when the voltage falls to a specific percentage, either 60% or 30% of the nominal value. This is achieved not by use of a voltage element producing a counter-torque as with the first type but by altering the main driving torque produced by the current element. The sensitivity change is initiated by a voltage-sensitive changeover relay which alters the pole-shading on the current element.

Figure 3.7 can be regal-ded as illustrating this type also if the black curve is the normal characteristic and the red cut-ve the more sensitive characteristic when the voltage has fallen and the changeover relay has operated. Its effect on speeding the operation of the relay under short-circuit conditions is just the same as described above for the truly voltage- restrained type of relay.

(c)

A different way of dealing with a busbar fault is by the method known as ‘Frame Leakage’ protection, which is indicated ip. Figure 3.8.

FIGURE 3.8

FRAME LEAKAGE PROTECTION

It is assumed that a busbar arcing fault will rapidly go to earth on the switchboard frame. The frame is lightly insulated from the deck and is connected to the true earth through a current transformer-. If the switchboard consists of several sectionsasshown,each is insulated both from the deck 2nd from its neighbours. Each section is separately earthed through a CT.

If there is a busbar fault involving the frame, the frame becomes live and current flows to earth through whichever CT is invqlved. This frame leakage current is used to provide an instantaneous trip on all generators and section breakers feeding into that section.

Care must be taken not to allow any conducting material to lean against theswitchboard, as this would shunt the CT connection.

(4 Zone Protection

This method provides each incomer, each feeder and each section breaker on theswitchboard with a set of current transformers and applies differential protection (see Chapter 6) to the entire group. Under heaithy conditions all the currents entering the switchboard from the incomers and section breakers are exactly balanced by those leaving it through the feeders. Any busbar fault upsets this balance and causes an instantaneous trip.

This method is known as ‘Zone Protection’. It is by its nature very costly and difficult to set up. It is only likely to be found in major shore netw~orks.

In most normal installations busbar faults are considered so rare that special protection is not provided. This is the case with Shell offshore installations, but busbar protection is provided at certain onshore plants.

3.2.7 Relays - General

Most protective relays are fitted with flags which indicate when they have operated. They show the operator, for example, which of the protective systems may have caused a turbo- generator to have tripped out. Such relays are themselves narmally self-resetting - that is, ,they revert to their normal state as soon as the fault has been removed. This may occur either because the circuit-breaker has tripped, so disconnecting the fault, or because the fault itself has disappeared. The flag however remains showing until it has been reset by hand.

Ian some protective systems, particularly for generators and transformers, all the protective relays trip the breaker through an intervening hand-reset trip, or ‘lock-out’, relay (TH). It too has a flag, but this relay, having once operated, does not reset itself automatically and so prevents the breaker being reclosed until the relay has been deliberately reset by hand. This prevents accidental reclosure onto a fault, and the breaker remains locked out until cleared by the operatorresetting the lock-out relay.

Whenever an item of plant has tripped because one of the protective systems has operated, it is most important that the operator should not reset the relay flags until he has carefully noted down which. flags are showing. If this is not done, all evidence of the cause of the malfunction will be lost. The lock-out relay must on no account be reset until it is safe to operate the plant again.,

3.2.8 Electronic Relays

Those relays which have so far been described are of the ‘electromagnetic’ type, where an electromagnet provides the driving force to a mechanical system of moving armature or rotating disc and mechanical contacts.

Many of these relays are now being superseded on offshore, and numerous onshore, installa- tions by electronic types which are entirely static except for their final output contacts. Electronic circuits carry out the detection, processing and timing; only the output circuit is passed through normal electromagnetic auxiliary contacts to the external trip circuits. This also isolates the trip circuits proper from the electronics.

Though using different methods, electronic relays reproduce similar characteristics td’those of the electromechanical types, and they have similar adjustments such as for current and. time setting. Their use does not affect the principles of protection described in Chapter 1. An electronic counterpart exists for almost every relay described in this and succeeding chapters. To illustrate the principle of operation, a single-phase, electronic inverse-time and instantaneous overcurrent relay (OClTjOC) is described here and shown in Figure 3.9.

The input from the line current transformer is fed through a small adapting transformer to a low-pass filter Rl-Cl which suppresses transient voltage surgesA voltage proportional to the input current is developed across the current-setting potentiometer R2. This voltage is applied to the bridge rectifier.

Time

(a)- CIRCUIT DIAGRAM --ve

input

Filter & Current

Transducer setting M

I

I

I nstantaneous Trip

(b) CORRESPONDING BLOCK DIAGRAM

FIGURE 3.9

ELECTRONIC OVERCURRENT RELAY

The d.c. output voltage, which is proportional to the line current, is used to charge the capacitor C2 through the potentiometer R5. Tbe setting of this potentiometer determines the rate at which the voltage across C2 increases and hence the timing of the inverse-time operating characteristic of the relay. When the’voltage across C2 reaches a predetermined value, the detector circuit operates to switch the electromechanical relay RLA through the output amplifier and power transistor T2.

instantaneous operation is obtained by applying the output voltage of the bridge rectifier directly to the input of the amplifier through R4. Thus; for higher values of fault current, the inverse-time delay circuit is bypassed.

The power supply for the solid-state circuits is applied through D3 and R6. It is stabilised by zener diode DZl, and spike protection is affor-ded by R7 and C3. The diode D3 protects against reversed polarity of the d.c. power supply.

By suitable choice of elements the electronic relay current/time characteristic can be made to reproduce exactly that of the equivalent electromagnetic type. Having virtually no moving parts, they are, in general, more robust, smaller and lighter. Current and time settings in this case are applied through simple variable resistors.

3.3 FUSES

3.3.1 The High Rupturing Capacity (HRC) Fuse

A fuse consists essentially of a length of metallic wire or strip carrying the cil-cuit current which, if that current exceeds a certain stated value for a certain minimum time, will melt and break the path of the current in that circuit. It has both a normal current rating corres- ponding to its service current and a breaking current rating corresponding to the maximum fault current of that part of the system in which it will be used.

Originally fuses consisted merely of a length of suitable wire stretched between the terminals of, a holder, the holder being designed to plug into permanent fixed sockets. These had the disadvantages of having much exposed live metal, and the melting open wire tended, under some conditions, to give rise to severe arcing and risk of fire. The wire also tended to corrode and weaken with the passage of time.

The open-wire fuse is no .longer used, having been superseded by the cartridge type. That used on offshore and onshore installations consists of an outer ceramic tube in which there is a silver fusible element completely surrounded by quartz powder, as.shown on the left of Figure 3110.

Silver Wire Element Quartz Powder Filling

\ I

Before Fusing

C ‘eramic Body

After Fusing

FIGURE 3.10

PRINCIPLE OFF THE HIGH RUPTURING CAPACITY FUSE

If sufficient current flows through the silver element for sufficient time, the element melts and vaporise:; it reacts chemically with the quartz, under the heat of the arc, to produce a block of highly insulating material in the path of the arc, as shown on the right of Figure 3.10. This rapidly suppresses the arc and, unless the current is much in excess of the fuse rating, it will break the fault current within a matter of milliseconds. Such fuses can break very large prospective fault currents by simply preventing those currents from ever building up. The fuses are consequently known as ‘High Rupturing Capacity’ (HRC) type.

(a) OPEN WIRE FUSE

Load Current

jr\

Befpre Fault ; \ Fault Current

Tqtal Clearing Time (b) HRC FUSE

FIGURE 3.11

FAULT CURRENT IN OPEN WIRE AND HRC FUSES Figure 3.11 (a) shows a fault current passing through an open-wire fuse.

continue for several cycles of arcing before it is eventually broken at a current zero.

The current may

When a moderate fault current passes through an HRC fuse the melting time will be com- paratively slow, and the current may continue for several cycles before it is broken - in fact the HRC fuse will behave just like the open-wire type in Figure 3.11 (a). If however the fault current is very large, the melting time will be less than one-quarter of a cycle. The ensuing arcing time is so short that the current is broken even before it reaches its first peak, as shown in Figure 3.11 (b). Such a fuse is said to exhibit ‘cut-off’. If the current,wave is wholly asymmetrical the first peak is not reached until half a cycle has elapsed, and cut-off may occur if the melting time is somewhat longer - i.e. less than half a cycle.

If it had not been for this cut-off, the fault current would have risen to its full-fault peak (called the ‘prospective current’ peak) before reaching its first zero. The fuse, by cutting off, has protected the whole system from the effects of this severe peak. It is therefore given

credit for having interrupted the full prospective current, even though in fact the current may never reach it because of cut-off. The fault rating of an HRC fuse is consequently very h~igh for its size. In Chapter 4, ‘Discrimination ’ it is shown how such fuses are used to back , up switchgear of lower fault rating capacity.

There is often confusion between the ‘normal’ and ‘breaking’ cxrent ratings of a fuse. The normal rating is matched to the load and is the maximum value of current which the fuse can carry continuously without melting or deteriorating. The breakingratingisthe maximum prospective current which the fuse can safely interrupt at its rated voltage; it is usually quoted in kiloamperes (kA) rms symmetrical and is related to the system fault level.

The energy needed~to melt Xfuse~ is the product of the rate of heat generatio+(in watts) due to the fault current.in the resistance of the element and of the total time during which such heat is being generated. It is /‘R x t, where I is the rms current, R the resistance of the element and t the total time. Since R is virtually fixed for.atiy given size of fuse, the energy released is proportional to I* t.

A specific fuse element requires a given Izt to melt it. Therefore when I is very large, t (the melting time) will be very small, as indicated in Figure 3.11(b):/‘t is often referred to as the ‘let through’ energy.

Pre-arcing Time (seconds) Minihun ~Fusing CUrWlt 125A Current (amps) FIGURE 3.12 HRC FUSE CHARACTERISTIC

If the melting (or ‘pre-arcing’) time t is plotted against I (usually on log paper),~the curve of Figure 3.12 is produced. Most of this is the familiar inverse-time curve which many relays also have. There is of course a minimum current which will never melt the fuse however long it is applied, but above this lower limit the fusin, - time varies inversely as the current. The upper limit is set by the ability of a given make and size of fuse to absorbs the /2t energy and to handle the mechanical forces involved.

As the fault current becomes higher, the melting (or pre-arcing) time becomes shorter until the point is reached where it is less than one-quarter of a cycle (0.004 seconds at 60Hz), and cut-off begins. From this point on the characteristic changes and becomes almost linear, as shown on the extreme right of Figure 3.12 (this is because ‘rms’ no longer has any meaning). With a fully asymmetrical current wave, cut-off may occur up to one-half of a cycle (0.008 seconds at 60Hz) after the onset of the fault.

3.3.2 Fusing Element

Figure 3.10 shows a silver wire as the fusing element. This is normal with small fuses, but for larger ones a silver (or sometimes copper).strip is often used, as shown in Figure 3.13.

Copper~End Caps

/ Ceramic Tube

uartz Powder Filling Constricted Silver

FIGURE 3.13

BASIC CONSTRUCTION OF AN HRC FUSE LINK

The strip has a number of constrictions which form hot spots and assist rapid melting under short-circuit conditions. For the heaviest currents a number of such strips may be connected in parallel within the common housing, or many separate fuse-links may be permanently bonded in parallel to form a single multiple link.

3.3.3 Fuse Mountings

Within an equipment, especially high-voltage assemblies, fuses are often mounted without individual enclosure on pillar insulators or directly on busbars. Reliance for safety is placed on the metal enclosure of the HV compartment which houses them. Interlocks prevent the compartment being opened until the circuit has been made safe.

On low-voltage distribution boards fuses are housed in a fuse assembly such as the typical one shown in Figure 3.14. The replaceable ceramic cartridge with its metal terminal caps is known as the ‘fuse-link’ and is held in an insulated ‘fuse-carrier’ which completely shrouds all live metal. The carrier is supported on an insulated ‘fuse base’, where it is firmly fixed by various mechanical means, amongst them tongue contacts, butt contacts held by insulated screw pressure, or wedge contacts pressed in by insulated screws. A tongue-contact type is shown in Figure 3.14.

1 Fuse Carrier

FIGURE 3.14

COMPLETE Low VOLTAGE FUSE ASSEMBLY (TYPICAL)

3.3.4

A fuse has a ‘normal current rating’, which is the current which it can carry continuously without melting or deteriorating and without altering its characteristic. The current which, under specified ambient temperature conditions, will just cause the fuse to melt after a prolonged time (usually taken to be four hours) is termed the ‘minimum fusing current’. The ratio minimum fusing current.

normal rated current

Fuses are manufactured to different fusing factors for various applications. They are given classification accordingly as follows:

Class Q2 Fusing factor greater than 2.0 Class Ql Fusing factor between 1.5 and 2.0 Class P Fusing factor between 1.2 and 1.5

In Figure 3.12 the time/current characteristic of the IOOA (normal rating) fuse is shown to become almost vertical after IO seconds, at which point the minimum fusing current is 125A. After four hours it will still be only 125A, as the curve is vertical. The fusing factor in this case is 125/100 or 1’.25, and its Class is therefore P.