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1. INTRODUCTION
Switchgear is a general term covering switching devices and their combination with associated control, measuring, protective and regulating equipment. The term covers assemblies of such devices and equipment with associated inter connections, accessories, enclosures and supporting structures intended for use in connection with transmission and distribution networks. The different types of air, oil, vacuum and SF6 switchgear together with the theory of arc interruption are already well-covered in standard reference books.
This Section therefore concentrates on the description of various switching phenomena under different practical circuit conditions and then relates these basic principles to the different switchgear designs currently available on the market. In particular this Section is intended to assist the reader in specifying switchgear for particular applications.
TABLE 1 Explanation of Commonly Used Switchgear Terminology
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Terminology | Description
Circuit breaker
A mechanical switching device, capable of making, carrying and breaking currents under normal circuit conditions and also making, carrying for a specified time and breaking currents under specified abnormal circuit conditions such as those of short circuit.
Contactor
A mechanical switching device having only one position of rest, operated otherwise than by hand, capable of making, carrying and breaking currents under normal circuit conditions including operating overload conditions.
Current limiting circuit breaker and current limiting fuse link
A circuit breaker with a break time short enough to prevent the short circuit current reaching its otherwise attainable peak value. Similarly, a fuse link, during and by its operation in a specified current range, limits the current to a substantially lower value than the peak value of the prospective current.
Disconnector
A mechanical switching device which provides, in the open position, an isolating distance in accordance with the specified requirements. A disconnector is intended to open or close a circuit under negligible current conditions or when there is no significant voltage change across the terminals of each of its poles. It is capable of carrying rated current under normal conditions and short circuit through currents for a specified time. Also sometimes known as a no-load isolator.
It is important to clarify the term isolator or disconnector. It can apply as follows:
(a) Off-circuit isolator capable of switching 'dead' (non-energized) circuits only.
(b) No-load isolator capable of switching under 'no-load' (negligible current flow) conditions only. Ensure when specifying such a device that it is capable of switching any applicable no-load charging current.
Earthing switch
A mechanical switching device for earthing parts of a circuit, capable of withstanding for a specified period current under abnormal conditions such as those of a short circuit, but not required to carry current under normal circuit conditions. An earthing switch may have a short circuit making capacity either to act as a 'fault thrower' at the end, say, of a long distribution feeder or to cater for inadvertent operation of a live circuit to earth.
Fuse switch
A switch in which a fuse link or a fuse carrier with a fuse link forms the moving contact. Such a device may be capable of closing onto a fault ('fault-make' and the fuse will operate).
Molded case circuit breaker (MCCB)
A circuit breaker having a supporting housing molded insulating material forming an integral part of the circuit breaker. Also note the miniature circuit breaker (MCB) which is of the current limiting type (see Section 11).
Switch
A mechanical switching device capable of making, carrying and breaking current under normal circuit conditions. This may include specified operating overload and short-term, short circuit current conditions. If so specified breaking full load rated current. It may then be called a 'fault-make, load break' switch or isolator.
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2. TERMINOLOGY AND STANDARDS
The descriptions of different types of switchgear, intended for different duties, are listed in TABLE 1. It is important not to be too lax with the terminology. For example the use of the term isolator to describe a switch will not on its own sufficiently describe the required capability of the device.
A circuit breaker is intended to switch both load and short circuit currents.
Unlike a fused device it enables supplies to be quickly restored after operation on short circuit and is the most expensive form of switchgear. It is not primarily intended for frequent operation although vacuum and SF6 breakers are more suited to load switching duties than older switchgear types.
A contactor is operated other than by hand and is intended for switching loads under normal and overload conditions. It is designed for frequent operations but has a limited short circuit current carrying and switching capability. It is therefore often backed up by fuses or a circuit breaker.
A disconnector provides in the open condition a specific isolating distance. It has only a very limited current switching capability and is not intended for frequent use or for breaking full load current.
A switch is used for switching loads but is not suitable for frequent operation. Switches may be manual or motor operated, and have a short circuit current-making capability but no breaking capability and must there fore be used in combination with a short circuit interrupting device (usually fuses). Where the fuse and switch are in combination in series the unit is called a switch fuse; where the fuse forms part of the moving contact of the switch it is termed a fuse switch.
TABLE 2 Useful IEC Switchgear Standards
Some useful IEC standards covering switchgear are detailed in TABLE 2.
It is important to distinguish between the terms metal-clad and metal enclosed as applied to switchgear and control gear. Metal-enclosed refers to complete switchboards, except for the external connections, with an external metal enclosure intended to be earthed. Internal partitions may or may not be incorporated and where installed need not be metallic. Metal-clad refers to metal-enclosed switchgear and control gear in which the components (each main switching device, outgoing way, busbar system, etc.) are arranged in compartments separated by earthed metal partitions. The partitions and busbar/ feeder shutters or covers should be carefully specified to various IP levels of protection.
Gas insulated switchgear (GIS) has all live parts contained in SF6 gas tight enclosures. Three phase busbar systems may use steel or aluminum enclosures. The busbars are physically arranged in trefoil formation largely to cancel out the resultant stray magnetic fields and any associated enclosure eddy current losses. The enclosure may also be sectionalized with insulating parts to further reduce such losses. Single phase busbar arrangements normally use lighter aluminum alloy or stainless steel corrosion proof enclosures. FIG. 1 shows a modern 400 kV GIS indoor substation installation in Saudi Arabia (courtesy Reyrolle Switchgear and successors).
3. SWITCHING
3.1 Basic Principles
3.1.1 General
FIG. 2 shows a typical switching arrangement with a source impedance RS j-omega LS and downstream impedance from the circuit breaker to the fault RL j-omega LL. The shunt impedances (capacitance and insulation resistance of machines, switchgear, cables and overhead lines) may normally be ignored when calculating short circuit currents since they are several orders of magnitude greater than the series impedances involved. In addition, it should be noted that series resistance values are only some 1% to 3% of the inductive reactance for generators and transformers and some 5% to 15%, depending upon construction, for high-voltage overhead lines. Short circuit currents in a high-voltage network are therefore practically totally inductive with a power factor of some cos (phi) =0.07. At lower voltages resistance values become more important and may be investigated depending upon the accuracy of the analysis required.
FIG. 1 Modern 440 kV gas insulated switchgear (GIS) installation undergoing
final commissioning tests in Saudi Arabia.
FIG. 2 Simplified network representation for a circuit breaker operation
under short circuit conditions.
[ Traditionally the sub-transient reactances of the source contributing machines have been used to determine the fault current and circuit breaker-rated short-circuit current selection.
This, by ignoring the decrement of the AC component which occurs after the sub-transient stages, correctly leads to a conservative approach to circuit breaker ratings. ]
Initially the circuit breaker shown in FIG. 2 is closed and carries the fault current is(t). The relay protection senses the fault and initiates a circuit breaker trip. FIG. 3 shows the behavior of the short circuit current is(t), through the circuit breaker and the voltage across the circuit breaker ucb(t). At a point in time, t1, the circuit breaker contacts begin to part and arcing occurs across the contacts. The arc is extinguished by the particular circuit breaker arc quenching mechanisms used and involves stretching the arc and rapid cooling.
In modern SF6 or vacuum circuit breakers the current is interrupted at the next or next but one current zero (2 cycle breakers) at time t2. Older, oil or air circuit breakers take slightly longer (typically 4 cycles) before the arc is extinguished. The arc duration in modern breakers is therefore relatively short (B10 ms) and this coupled with the low arc voltage leads to low energy dissipation during the circuit breaker operating process. However, for the UK transmission system (between 132 kV and 400 kV) breakers are tested for longer arcing times (arcing windows) characteristically #20 ms to cover for the conditions brought about by earth faults.
FIG. 3 Short circuit, is(t) through the circuit breaker and characteristic
waveform for recovery voltage, ucb(t) across circuit breaker upon fault
clearance.
FIG. 4 Determination of making and breaking current, and of percentage
DC component.
The characteristic waveform of the recovery voltage is shown in FIG. 3. A high frequency voltage oscillation, known as the 'transient recovery voltage' (TRV), fluctuates about the power frequency recovery voltage waveform. Its behavior is determined by the circuit parameters and the associated rapid redistribution of energy between the network component electric and magnetic fields. If the power factor of the faulted circuit is high (i.e. resistance is a significant proportion of the total fault impedance) then the circuit or power source voltage at current zero will be low. At low power factors (predominantly inductive or capacitive circuits) the circuit voltage at current zero will be high and result in a tendency for the arc to re-strike. This is the basic reason why inductive and capacitive circuits are more difficult to interrupt than resistive circuits. The circuit breaker must, therefore, be designed to withstand the transient recovery voltage. Whether or not the arc extinguishes after the first current zero depends upon establishing adequate dielectric strength across the circuit breaker contacts faster than the rate of rise of TRV and the peak TRV involved. Repeated dielectric or thermal breakdown of the circuit breaker insulating medium between the contacts is also reduced by efficient and rapid thermal quenching.
The short circuit current is characterized by a degree of asymmetry resulting from an AC component (contained in envelope AA /BB ) and a decaying DC component (line CC ) as shown in FIG. 4. The exact response depends upon the instant at which switching of the AC waveform takes place and the relative R, L and C circuit parameters involved. The response may be calculated by solving the differential equations for the network involved and the solution for the current response i(t) takes the form:
i t = u cos ?t1 d2f 2cos d2f e2t=t
R2 1X2 p
where i(t) =circuit breaker short circuit current
R =resistance
X =reactance
u(t)=source voltage (u ˆ=peak source voltage)
d =closing angle related to voltage across circuit breaker=0
phi=phase angle
t =time constant=L/R=BX/?R
FIG. 5 Percentage DC component in relation to time t (ms) and different
circuit component time constants t (ms).
3.1.2 DC Component
The exponential decay time constant of the DC component, t, is often taken as 45 ms and is a typically representative value in IEC 62271-100 based on a power factor of 0.07 (but special time constants 120 ms ,52 kV, 60 ms 72.5 400 kV and 75 ms 550 kV and above are also provided for, and high DC components are now being experienced in UK especially around London and on 132 kV system). Ranges of time constant, t, for cables, high-voltage transmission lines and generators are shown in FIG. 5.
3.1.3 AC Component
The AC component itself may, or may not, be subject to decay. This depends upon whether or not the sub-transient or transient reactances of source generators form a significant part of the total impedance of the overall fault circuit.
For short circuits on a distribution system where transformers whose kVA rating is low in relation to the capacity of the system are interposed between the short circuit and sources of generation, the AC component decay is negligible.
Where the short circuit is close to sources of generation the sub-transient and transient reactances of the machines will form a significant part of the total fault circuit impedance. The AC component delay will therefore be more appreciable. Consider a generator circuit breaker located on the high-voltage side of a large (say, 1,000 MVA) power station generator transformer.
Theoretically the circuit breaker could experience an asymmetrical short circuit current which decays more rapidly than the DC component. During the initial decay period, when current asymmetry is a maximum, it is possible for no current zeros to occur and short circuit interruption to be delayed as a result. In practice, the arc resistance at the fault and across the circuit breaker contacts will reduce the DC time constant and result in a faster DC component decay period. Generator circuit breakers located on the low voltage side of the generator transformer may be presented with an even more severe case of slow DC decay in comparison with the AC component. The attenuating effect of the series connected low L/R transformer impedance ratio is not present and the fault levels will be at least an order of magnitude higher without the limiting effect of the transformer reactance. It is therefore very important to specify circuit breakers for such duties carefully. IEEE Standard C37.013 1993, 'IEEE Standard for AC High-Voltage Generator Circuit Breakers Rated on a Symmetrical Current' gives very useful guidance. Generally generator circuit breakers for the larger generators are isolated phase design. Faults will thereby mostly be phase earth not phase-phase and this can assist interruption as there will be two 'healthy' phases with no DC component.
TABLE 3 Co-ordination Table of Rated Values for Circuit Breakers, 3.6 72.5 kV [coming soon]
3.1.4 Circuit Breaker Short Circuit Current Ratings
The 'rated short circuit breaking current' is the highest short circuit current which the circuit breaker is capable of breaking and is specified in terms of the AC and DC components. The AC component is termed the 'rated short circuit current' and is expressed in kA rms. The DC component (unless the breaker is non-standard and subject to special agreements between manufacturer and purchaser) is characterized in accordance with the IEC 62271-100 negligible AC component decrement and short circuit power factor of 0.07.
Traditionally the sub-transient reactances of the source generators contributing to the fault have been used to determine the fault current. By ignoring the decrement of the AC component which occurs after the sub-transient stage, this correctly leads to a conservative selection of the circuit breaker rated short circuit current. Tables 3 and 4 give typical circuit breaker short circuit ratings ranging from 10 to 50 kA and normal current ratings ranging from 400 to 4,000 A. The short circuit currents impose large electro mechanical forces on the switchgear busbars and contacts. The circuit breaker mechanism has to be designed to be able to close onto the peak value of short circuit current with full asymmetry and carry the fault current for either 1 or 3 s without the contacts overheating, parting or damage occur ring. Mechanisms are usually of the stored energy or externally fed power operated type using pneumatic, hydraulic, spring or solenoid systems. Current practice tends to solenoid plus permanent magnets [5]. Because it is necessary to overcome the large forces present when closing onto a fault, manual-operated circuit breakers, where the closing force is dependent upon positive operation by the operator, have generally been discontinued except at the lowest voltage and short circuit levels.
TABLE 4 Co-ordination Table of Rated Values for Circuit Breakers, 123 765 kV [coming soon]
If the operating time of the breaker from the instant of trip initiation to the instant of contact separation is known (the minimum opening time), it is possible to determine the 'actual rated short circuit breaking current'. From fault inception IEC 62271-100 allows 10 ms relay operating time followed by breaker opening time say 22 35 ms and then the first major loop after contact separation. Generally breaker opening times are 22 35 ms, arcing times 10 23 ms and therefore total break times of 32 58 ms. So consider a circuit breaker with 35 ms minimum opening time which has a rated rms short circuit current of 25 kA and auxiliary tripping power supply. The mini mum time interval from the instant of the fault to the instant when the arcing contacts have separated in all three poles will be the relay operating time, 10 ms, plus the minimum opening time to total 45 ms.
Therefore, in FIG. 4:
EE =45 ms
at iac =peak value of the AC components at instant EE =25U
??? 25x5.35 kA
iac= __/2=rms value of the AC component (which corresponds to the rated short circuit current of 25 kA)
idc =DC component of current at instant EE’
From FIG. 5, using a delay time constant of t =45 ms, after 45 ms: idc idc/iac 100%=35%.
Therefore, idc =iac * 0.35= (25 * __/2) * 0.35x12.37 kA.
Now the actual rms value of the asymmetric current characterized by idc and iac
=27.89 kA rms
Thus, whilst the circuit breaker would be offered by the manufacturer as having a rated short circuit current of 25 kA rms, it would actually have a rated short circuit breaking current of 27.89 kA rms and 47.72 kA peak (idc+iac).
The rated short circuit current is often referred to by the manufacturers as 'symmetrical breaking capacity' and the rated short circuit breaking current as the 'asymmetrical breaking capacity'.
In addition to the breaking short circuit current capability, the circuit breaker is also called upon to 'make' short circuit current, that is to close onto a short circuit. In these circumstances the circuit breaker must be able to latch successfully whilst subject to the magnetic forces associated with the peak value of the first half cycle of fault current. The first short circuit current peak, Imax, is given by Imax =Ik __/2 (1+e ^ [-t/tu] where Ik is the rms value of the symmetrical short circuit current. For full asymmetry some 10 ms after the short circuit begins and using the 45 ms time constant, Imax =Ik __/2 (1+e^-t/tau) Ik __/2 (1+e^-10/45) =2.55Ik.
For readers interested in mathematics it is worth analyzing the circuit shown in FIG. 2 by hand using Laplace transforms or by computer using a numerical analysis program with short time steps.
Where concentrations of induction motors exist (such as in refineries or in a petrochemical complex) their contribution on a system to the fault levels may be introduced into computer aided network analysis in order to determine more accurately the required circuit breaker fault rating characteristics. Normally induction motors only form part of the network load and it should be noted that such motor time constants are relatively short. Consequently there is a rapid decay in their fault current contribution and it is not normally necessary to increase circuit breaker interrupting capacity. The motor contribution is more important when determining the required making capacity of the circuit breaker and there may be a case for increasing the ratio of 2.5 between Imax and iac / __/2 . The manufacturer's advice may be sought in such cases since their standard breaker may well be able to comply with such making capacity requirements. Alternatively, a circuit breaker may be selected with slightly higher than necessary interrupting capacity in order to obtain the required making capacity.
3.2 Special Switching Cases
3.2.1 Current Chopping
Extinction of the arc can normally only occur at current zero. There was a tendency in some circuit breakers (notably MV vacuum and air blast types) in the 1970s to have such good dielectric strength that at low current levels they were capable of extinguishing the arc before current zero occurred. In reactive circuits this can lead to very serious high-voltage spikes which can be several per unit system peak power frequency voltage as the energy transfer takes place ( FIG. 6). These temporary overvoltages can cause the breakdown of insulation. This might especially be the case if such circuit breakers are used in conjunction with older equipment such as transformers with relatively poor insulation whilst switching magnetizing currents or when switching line charging (capacitive) currents. Surge suppression devices may be fitted on the load side of the circuit breaker to mitigate the problem.
With higher voltage SF6 switchgear the circuit breaker contact arc voltage is normally constant at higher currents and the arc energy is removed by rapid convection cooling effects. At lower inductive currents the arc tends to be extinguished by arc extension and by turbulence within the circuit breaker contact chamber. The arc current can become unstable as energy is exchanged between source and load reactances such that a high frequency voltage oscillation occurs. The oscillation may be such as to allow the rapidly oscillating current waveform to pass through a current zero before its natural power frequency zero occurs. Again this may lead to a current chopping phenomena.
The interruption of capacitive currents (such as when disconnecting open circuit cables, capacitor banks or long, lightly loaded overhead lines) may also lead to current chopping. Considerable efforts have been made by switchgear manufacturers to provide designs suitable for re-strike-free operation.
SF6 transmission breakers are designed to be re-strike-free and IEC 62271-100 now includes a test for line charging current and capacitor bank interruption that does not allow any re-strikes.
FIG. 6 Overvoltages caused by current chopping before natural current
zero.
TABLE 4a First Pole-to-Clear Factors for Different Fault Conditions [coming soon]
3.2.2 Pole Factors
A three pole circuit breaker will not trip all three phases simultaneously. The first pole to clear will experience the highest transient recovery voltage and the associated power frequency recovery voltage for this first phase will begin to appear after the second pole has interrupted the current flow as shown in Fig. 19.2, Section 19. During this interval the transient recovery voltage (TRV) waveform contains high-voltage spikes. The severity of the voltage transient is a function of the network earthing and sequence impedances. For most systems (depending upon the earthing practice) the ratio of X0/X1 varies approximately between 0.6 and 3 with average values in the range 1.5 2. The pole factor is the ratio of the power frequency recovery voltage to the corresponding phase voltage after the current interruption. In solidly earthed systems the highest first pole-to-clear factors occur with three phase faults. First pole-to-clear factors for different fault conditions are listed in TABLE 4a.
3.2.3 Overvoltages on High-Voltage Overhead Line Energization
The exchange of energy between source and load impedances during switching is of particular significance on systems at voltages above 245 kV (IEC Range II). In addition, it should be noted that on long unloaded transmission lines the Ferranti effect may cause the power frequency receiving end voltage to be higher than the sending end voltage such that switching over voltages occur throughout the system. Such switching overvoltages, which may be as high as 3 per unit, consist of a power frequency and transient high frequency component. The latest IEC insulation co-ordination recommendations are based on switching impulse levels greater than 2 per unit. They may be minimized and reduced to this level by:
1. Inductive reactor compensation connected between phase and earth at the sending and receiving ends to compensate for capacitive charging cur rents and reduce power frequency surges.
2. Use of inductive voltage transformers (rather than CVTs) connected at the ends of line or cable circuits. These have the effect of helping to discharge the line or cable capacitive currents.
3. Cancellation of the trapped charge effect by using control circuitry such that the circuit breaker only closes during that half cycle of the supply voltage which has the same polarity as the trapped line charge.
4. Energizing the line by initially switching with a series resistance at time t1 and then short circuiting the resistor out in one (or more) stages some 6 10 ms later at time t2 ( FIG. 7).
3.3 Switches and Disconnectors
Switches are capable of load breaking, that is interrupting currents up to their continuously rated current value. Disconnectors have negligible current interrupting capability and are only used in the off-load condition.
LV switches (,1,000 V) are normally air insulated, and MV types air, oil or SF6 insulated. Switches have spring tripping to ensure fast action. Both switches and disconnectors must be designed to be thermally stable and suitable (i.e. a specific temperature rise must not be exceeded) for their continuous current rating and for short time (1 or 3 s) through-fault current rating conditions. FIG. 8 shows a 4,000 A, 52 kV disconnector undergoing temperature rise tests in the factory before release to site. The numerous small wires are attached to thermocouples mounted on the disconnector.
The long copper busbar connections between the disconnector assembly and the current injection cables assist in the thermal isolation between the source current and the disconnector assembly under test.
Figures 9a-d show various types of open terminal disconnector for transmission and distribution applications.
Switches must also be capable of fault making. This is essentially a mechanical design problem. When closing onto a short circuit the device is subjected to the maximum peak value of short circuit current occurring in the first half cycle after fault initiation. Electromagnetic forces are then at their maximum and the switch must reliably close under these conditions.
IEC standards assume the peak value of making current to be 2.5 times the rms value of rated short circuit current for MV switches and between 1.7 and 2.2 times for LV switches.
Tables 5 - 7 provide details of the major technical particulars and guarantees that need to be specified for the following substation components:
TABLE 5 Disconnectors and earthing switches. [coming soon]
TABLE 6 Busbars (see also Section 18). [coming soon]
TABLE 7 Post-type insulators (see also Section 6). [coming soon]
FIG. 9a Distribution 'rocking arc' disconnector-pole-mounted applications
up to 36 kV for sectionalizing and isolating apparatus in rural electrification
schemes. Fixed contact and moving blades are designed for smooth operation.
Contact material is hard drawn high conductivity copper, silver plated
over the contact area. The units are designed to break line charging or
load currents within specified limits (Hawker Siddeley Switchgear).
3.4 Contactors
A contactor is designed for frequent load switching but not for short circuit interruption. It has a relatively light operating mechanism intended for many thousands of reliable operations between maintenance inspections. In com parison a circuit breaker is designed to make and interrupt short circuit currents and has a powerful fast acting operating mechanism. Contactors, when used in conjunction with series fuses, give excellent short circuit protection and switching performance. Low-voltage contactors are normally air break types, and MV contactors air, oil or SF6 insulated. Contactor ratings are based on a number of parameters as described in TABLE 8.
Vacuum contactors have been commercially available since the mid-1960s and SF6 since the late 1970s. The advantages over air break contactors are smaller physical size, less floor space and floor loading, and their long-term reliability and reduced maintenance. Vacuum, SF6 and air break contactors with series fuses (corrugated elements) are available for duties in terms of motor size:
- 3.6 kV up to B2,000 kW.
- 7.2 kV up to B4,000 kW.
- 12 kV up to B2,000 kW.
FIG. 9b Rotating double or single break disconnectors to 72.5 kV (traditional
UK open terminal substation designs). The units may incorporate earth switches,
manual or power operation, use cap and pin or solid core insulators, have
facilities for padlocks, mechanical key type or electrical interlocks and
removable interrupter heads (Hawker Siddley Switchgear).
For larger motor sizes and at higher voltages it is necessary to use a circuit breaker for direct on-line (DOL) starting.
When designing contactor control circuits care must be taken to ensure that repeated closing/tripping (pumping) of the contactor is avoided. All control contacts in the 'hold in' circuits should have a positive action with a definite make/break differential in such devices as pressure switches, level switches, etc. A detail not to be overlooked is the circuitry surrounding an economy resistor used to reduce the current consumption of the contactor coil once closed. This resistor can be bridged by a normally closed contactor auxiliary contact. If the economy resistor should then fail (become open circuit) the contactor closing command could then set up a 'hunting' action.
The contactor closes and is then immediately opened as the resistor bridging contact opens, this action being repeated rapidly. A latching feature with DC tripping should be considered.
FIG. 9c Double break disconnectors.
FIG. 9d Pantograph disconnector.
4. ARC QUENCHING MEDIA
4.1 Introduction
Modern open terminal high-voltage switchgear is primarily based on the SF6 gas circuit breaker interrupting medium. Vacuum and small oil volume (SOV) switchgear designs are also available and economic up to about 145 kV. Air blast circuit breakers are no longer produced by any major manufacturers.
The options available for indoor equipment at the medium-voltage level consist of metal-enclosed equipment employing phase-segregated small oil volume, vacuum and SF6 circuit breakers. Medium-voltage bulk oil circuit breakers based on designs perfected in the 1950s are still produced and have a very satisfactory history of reliable use. However, the additional regular maintenance costs, weight and need to incorporate oil catchment and fire detection/suppression systems carefully into the building and civil services designs has reduced their popularity.
TABLE 5 Open Terminal Disconnector and Earthing Switch Technical Particulars and Guarantees Checklist [coming soon]
Three phase or phase-segregated gas insulated switchgear (GIS) is now used over the complete medium and high-voltage spectrum. Layouts employing such GIS equipment may occupy only one-ninth the volume of an open terminal equipped outdoor substation site.
Detailed switchgear design studies and choice of interrupting medium should give consideration to circuit breaker duties including capacitive and inductive switching, short circuit transient recovery voltage (TRV), rate of rise of recovery voltage (RRRV) and any special needs associated with sys tem parameters. The circuit breaker specifications should also consider the methods of isolation and earthing in order to ensure these are compatible with the particular electricity supply utility operations and maintenance practice. A comparison of circuit breakers with different arc quenching mediums is given in TABLE 9.
TABLE 6 Busbar Technical Particulars and Guarantees Checklist [coming soon]
TABLE 7 Post-type Insulator Technical Particulars and Guarantees Checklist [coming soon]
TABLE 8 Contactor Ratings and Parameters [coming soon]
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Rated voltage
Includes rated operating voltage and insulation voltage level.
Rated current
The rated thermal current is the maximum current the contactor can carry for 8 h without exceeding temperature rise limits.
Rated frequency (of supply) Normally 50 or 60 Hz.
Rated duty
This defines the number of duty cycles ranging from uninterrupted duty (contactor closed for an indefinite period) to an intermittent duty of 1,200 operating cycles per hour.
Making and breaking capacities
The rated making/breaking capacity defines the value of current under steady state conditions which the contactor can make/break without welding or undue erosion of the contacts and is defined in accordance with the contactor utilization category.
Utilization category
The utilization category depends upon switching requirements.
Four categories AC-1 to AC-4 are available. An onerous duty (AC-4) would be switching off motors during starting (plugging) conditions. A typical duty (AC-3) would be for the starting and switching off squirrel cage induction motors during running conditions. The AC-3 category allows for making and breaking capability of 83 the rated operational current at 0.35 power factor (pf) and, under conditions of specified electrical endurance (see below), a making capacity of 63 breaking capacity 13 rated operational current at 0.35 pf.
Mechanical and electrical endurance
These define the conditions under which a contactor shall make a number of specified operating cycles without repairs or replacements. For LV contactors such minimum requirements might be specified as:
- Mechanical endurance (i.e. off load) 13106 operating cycles;
- Electrical endurance (i.e. on load) AC-3 or AC-4 operating cycles.
For MV contactors such minimum requirements might be specified as:
- Mechanical endurance (i.e. off load) 25,000 operating cycles;
- Electrical endurance (i.e. on load) 5,000 operating cycles.
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TABLE 9 Circuit Breaker Comparison
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Small Oil Volume (SOV) --- SF6 (GIS, Open Terminal) --- Vacuum --- Air Blast --- Bulk Oil (Indoor Metal-Clad or Enclosed) --- GIS (Indoor Metal-Clad or Enclosed)--- Vacuum (Indoor Metal-Clad or Enclosed)
Maintenance
Advantages
Can be economic at low interrupting capacities up to approximately 145 kV.
Low maintenance.
Considerable choice from many manufacturers.
Low maintenance.
Vacuum 'bottles' easy to replace.
Relatively simple to maintain circuit breaker itself.
Still found in installations built up to late 1970s at the highest voltage levels.
Available up to36kV for use in extending existing switchboards or where equipment is a supply utility standard. Obsolescent for outdoor open terminal installations.
Low-cost SOV equipment remains available.
Low maintenance.
Compact, small site area, available up to highest voltage levels. At distribution voltage levels below 36 kV many designs considered 'maintenance free' for life time of equipment.
Low maintenance.
Vacuum 'bottles' easy to replace.
Popular up to 36 kV and especially at 12 kV. Lightweight and compact designs available.
Vertical or horizontal housing.
Disadvantages
Maintenance after fault clearance.
Special care in handling SF6.
Limited availability.
May be found for open terminal designs up to 72.5 kV. Were used in conjunction with SF6 insulation systems. Spare vacuum 'bottle' holding required.
Main and standby compressor systems required.
Regular oil maintenance required. Civil and building services requirements to be considered in overall installation costs.
Special care in handling SF6.
Eventual 'bottle' replacement.
Operations
Advantages
Overhead connections possible for most circuit configurations. Low cost in good environmental conditions.
Substation extensions independent of particular switchgear manufacturer.
Overhead connections possible for most circuit configurations.
Economic in good environmental conditions.
Substation extensions independent of particular switchgear manufacturer.
Overhead connections possible for most circuit configurations. Low energy, lightweight operating mechanisms.
Substation extensions independent of particular Switchgear manufacturer.
Good performance independent of atmospheric pollution when properly housed.
Available in phase segregated and non phase-segregated form. Full protection against live parts.
Good performance independent of atmospheric pollution when properly housed.
Full protection against live parts.
Disadvantages
Large outdoor switchyard site areas. Extensive civil trench and foundation works.
Large outdoor switchyard site areas. Extensive civil trench and foundation works.
Large outdoor switchyard site areas. Extensive civil trench and foundation works.
Bulk oil now largely obsolete. SOV equipment requires regular oil checks.
Special cable connections or bus duct/through wall bushings may be required at higher voltages. Simple modular housing recommended.
Insulation co ordination more difficult.
Not available at highest voltages.
Simple modular housing recommended.
Check switching transient performance.
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FIG. 10 SF6 air, and oil dielectric breakdown strength as a function
of pressure.
4.2 Sulphur Hexafluoride (SF6)
SF6 gas is stable and inert up to about 500 C, it is incombustible, non-toxic, odorless and colorless. FIG. 10 gives a comparison of the dielectric breakdown strength of SF6 gas with both air and transformer oil as a function of gas pressure. SF6 gas possesses excellent insulating properties when pressurized in the range 2 6 bar and has a dielectric strength some 2.5 3 times that of air at the same pressure. The gas is about 5 times heavier than air with a molecular weight of 146 and specific gravity of 6.14 g/l. At normal densities the gas is unlikely to liquefy except at very low operating temperatures less than 240 C and equipment may be fitted with heaters if this is likely to be a problem, or, as an alternative to heaters, mixed gases are also used below 240 C (SF6 1N2 or SF6 1CF4). Industrial SF6 gas used in circuit breakers and bus systems is specified with a purity of 99.9% by weight and has impurities of SF6 (0.05%), air (0.05% O2 plus N2), 15 ppm moisture, and 1 ppm HF. Absorbed moisture leaving the switchgear housing and insulator walls leads to the moisture content of the SF6 gas stabilizing at between 20 and 100 ppm by weight.
Gases at normal temperatures are good insulators but the molecules tend to dissociate at the elevated arc plasma temperatures (B20,000 K) found during the circuit breaking process and become good conductors. SF6 gas also dissociates during the arcing process and is transformed into an electrically conductive plasma which maintains the current until the next or next but one natural power frequency current zero. SF6 gas has proven to be an excellent arc quenching medium. This arises not only from its stability and dielectric strength but also its high specific heat, good thermal conductivity and ability to trap free electrons. It cools very rapidly (few µs) and the sulphur and fluorine ions quickly recombine to form stable insulating SF6. Such properties all assist in the removal of energy from the arc during the circuit breaking process.
At voltage levels below 36 kV the equipment is often of a 'sealed for life' variety. Higher voltage equipment may be opened for inspection and maintenance after several thousand switching or tens of short circuit operations. SF6 leakage rates from high-voltage GIS should be less than 0.5% per annum. Secondary dissociation products formed during the arcing process may remain in a gaseous state (mainly SOF2 but also SO2F2 and HF) in very small concentrations. Non-conductive fluorides and sulphides (e.g. WF6 and CuF formed from the reaction with circuit breaker contact materials) may also be re-condensed in very small quantities on the walls of the equipment and form a dust deposit. Standard health and safety precautions (gloves, dust mask, goggles, well-ventilated room, etc.) must therefore be executed when carrying out such maintenance procedures.
FIG. 11 (a) Arc motion in a magnetic field. The arc has been extended
towards the coil axis by transverse movement of the contact bar. It is
shown after transfer to the arcing tube and consequent production of the
magnetic field. It is thus in the best plane to commence rotation. (b)
Development of a spiral arc. The arc is motivated to move sideways but this
tendency is limited by the shape of the electrodes and it develops quickly
into a spiral with each element tending to move sideways as shown by the arrows.
(c) An actual high speed photograph taken through a porthole. The direction
of rotation is in line with that shown in (a) and (b) but as seen from the
opposite side of the field coil. A typical speed of rotation is 3,000 revolutions
per second depending upon the value of arcing current.
FIG. 12 SF6 puffer principle of operation (a) Interruption components
in CLOSED position; (b) quenching process as arc is gas-blasted; (c) OPEN
position.
FIG. 12d Auto puffer circuit breaker interruption method (courtesy of
ABB).
FIG. 13 Constructional features of the 11 kV vacuum interrupter 'bottle'.
At voltages up to about 15 kV and for lower breaking currents both circuit breakers and contactors can use the rotating arc principle. Instead of moving cold gas (air, SF6 or oil gas bubble) into the arc, the arc is made to rotate under the action of a magnetic field produced by the load or short circuit current. This stretches and moves the arc in the gas to create cooling and eventual arc extinction. Puffer type SF6 circuit breakers employ a piston attached to the moving contact to force cool gas into the arc in order to cool and extinguish it. The advantages of these types of SF6 circuit breaker may be summarized as:
1. Complete isolation of the interrupter from atmosphere and contaminants.
2. Absence of oil minimizes fire risk.
3. Generally, up to 36 kV the interrupter is considered sealed for life and maintenance free.
4. Overall maintenance requirements are low and involve attention to the mechanism.
5. The equipment does not require a heavy operating mechanism, dead and live weight is low. The equipment therefore tends to be compact. This offers civil works savings for indoor metal-enclosed or GIS designs.
Figures 11 and 12a c show SF6 circuit breaker interruption methods using arc rotation and puffer principles. The latter are gradually being replaced by auto puffer designs see FIG. 12d.
4.3 Vacuum
Vacuum interrupter tubes or 'bottles' with ceramic and metal casings are evacuatedtopressuresofsome1026 1029 bar to achieve high dielectric strength. The contact separation required at such low pressures is only some 0 20 mm and low energy mechanisms may be used to operate the contacts through expandable bellows. FIG. 13 shows a cutaway view of such a device. The engineering technology required to make a reliable vacuum interrupter revolves around the contact design. Interruption of a short circuit current involves the initial formation of a conductive path between the contacts which very rapidly becomes a high grade insulator normally after the first current zero. The conductive path consists of con tact metal vapor. The arc is extinguished when the current falls to zero.
Conducting metal vapor condenses on metallic screens or sputter shields inside the vacuum tube walls within a few µs and the dielectric strength is restored to form an open circuit. The shields prevent metal vapor deposits from reducing the overall dielectric strength of the insulated vacuum interrupter casing. Arcing times are of the order of half a cycle (10 ms at 50 Hz). To avoid overheating the contact system must be designed to allow the arcing to move to different points over the contact surface area by utilizing its own magnetic field and by using special contact materials. In this way current chopping and the associated transient overvoltages are avoided except at the lowest levels of current interruption (a few amps). The life time of such devices is very long (typically 20,000 switching and a hundred short circuit operations) before replacement is required. The upper voltage range for vacuum interrupters is extended in some designs by surrounding the vacuum bottles and busbars with SF6.
The advantages of the vacuum circuit breaker or contactor are:
1. Complete isolation of the interrupter from atmosphere and contaminants.
2. Absence of oil minimizes fire risk.
3. Maintenance requirements are low and involve attention to the operating mechanism.
4. Very compact metal-enclosed designs are available. Where necessary the designs may incorporate a series fuse to improve short circuit capability and still render the units safe should the contact surfaces weld under loss of vacuum conditions.
TABLE 10 Details of Some Insulating Oils [coming soon]
4.4 Oil
Mineral oil has good dielectric strength and thermal conductive properties.
Its insulation level is, however, dependent upon the level of impurities.
Therefore regular checks on oil quality are necessary in order to ensure satisfactory circuit breaker or oil-immersed switch performance. Carbon deposits form in the oil (especially after heavy short circuit interrupting duties) as a result of decomposition under the arcing process. Oil oxygen instability, characterized by the formation of acids and sludge, must be minimized if cooling properties are to be maintained. Insulation strength is particularly dependent upon oil moisture content. The oil should be carefully dried and filtered before use. Oil has a coefficient of expansion of about 0.0008 per C and care must be taken to ensure correct equipment oil levels. The physical properties of some switchgear and transformer insulating oils available from the Shell Company are listed in TABLE 10.
Oil insulating properties may be assessed by measurement of electric strength, volume resistivity or loss angle. Bulk oil circuit breakers have given years of reliable service and it should be noted that oil is not a poor or less suitable extinction medium. However, oil circuit breakers for new installations may now be considered obsolete as a result of the maintenance burden necessary to keep the oil in good condition. In addition fire suppression/detection features must be included in the overall building services and civil engineering substation design when using oil circuit breakers.
Small oil volume circuit breakers are still available from European manufacturers at distribution voltage levels for relatively low short circuit duties and where short circuit breaking times are not critical to system stability.
They offer phase-segregated design thus eliminating the risk of inter phase faults within the interrupting chamber. The small oil volume also greatly reduces the fire risk.
The oil-assisted arc interruption process is difficult to model and the practical design of circuit breaker heads is complex because of the need to cope with the three liquid oil/gas/arc plasma phases. Oil viscosity varies greatly with temperature and gas bubble pressure evolution during short circuit interruption may vary between one and several hundred bar. In comparison, a similar-rated vacuum or SF6 circuit breaker does not require such a complex mechanical assembly. A typical small oil volume circuit breaker installation and head are shown in Figs. 13.14 and 13.15.
FIG. 14 66 kV open terminal substation in the Middle East showing oil-filled
cable sealing ends and pressure tanks, rotating post insulators and small
oil volume (SOV) circuit breakers.
FIG. 15 Arc extinction in a small oil content circuit breaker (T breaker).
FIG. 16 LVAC air circuit breaker arc extension across splitter plates.
4.5 Air
Air circuit breakers are normally only used at low voltage levels but are available with high current ratings up to 6,000 A and short circuit ratings up to 100 kA at 500 V. The physical size of such units, which contain large arc chutes, quickly makes them uneconomic as voltages increase above 3.6 kV.
Their simplicity stems from the fact that they use ambient air as the arc quenching medium. As the circuit breaker contacts open the arc is formed and encouraged by strong thermal convection effects and electromagnetic forces to stretch across splitter plates ( FIG. 16). The elongation assists cooling and deionization of the air/contact metallic vapor mixture. The long arc resistance also improves the arc power factor and therefore aids arc extinction at current zero as current and circuit breaker voltage are more in phase. Transient recovery voltage oscillations are also damped thus reducing overvoltages. Arc products must be carefully vented away from the main contact area and out of the switchgear enclosure. As explained in Section 11, many MCB and MCCB low-voltage current limiting devices are only designed to have a limited ability to repeatedly interrupt short circuit currents. Care must therefore be taken when specifying such devices.
FIG. 17 shows 400 V air circuit breaker with fully repeatable high short circuit capability as typically found in a primary substation auxiliary supply switchboard.
The air blast circuit breaker uses a blast of compressed air across the contacts to assist the interrupting process. Rapid fault clearance times (B2 cycles) largely independent of the short circuit current involved are possible because of the permanent availability of a given blast of compressed air through a nozzle formed in the main fixed contact. The arc is stretched by the air blast and heat removed by forced convection. It is important that the compressor supplies sufficient air to ensure that the arc extinction is still eventually achieved even if not at the first or second current zero. Current chopping when interrupting low currents is usually overcome by paralleling the arc with a resistance connected across the main contacts. Final interruption is then achieved by a fast acting switch in series with the main contacts.
Such breakers have high rated current and short circuit current capabilities.
They are reliable and reasonably maintenance free. However, they tend to be very noisy in operation (not good for use in substation sites adjacent to built up areas), require a reliable compressed air plant and have high dynamic loads. This will increase the maintenance burden in comparison with other types of arc interrupting circuit breakers. However, note that the actual operating mechanisms for many circuit breakers use compressed air.
A typical arrangement is shown in FIG. 18. Such breakers have been superseded by SF6 designs which are now available up to 800 kV.
FIG. 17 Withdrawable 400 V air circuit breaker (Brush Electrical Engineering
Co. Ltd.).
[ 1. Arc runner
2. Heat exchanger for rapid cooling of arc
3. Moving contact carrier
4. Insulating high-temperature refractory layer covering top half of deionization plates
5. Deionization plates
6. Arcing horns
7. Sintered arcing contacts
8. Main contacts (silver)
9. Current-transformer controlling tripping devices
10. Isolating contacts
11. Location pin of moving-contact assembly
12. Main operating shaft to closing mechanism
13. Insulating connecting rod (asbestos glass fiber)
14. Main trip rod
15. Trip pawl for tripping devices
16. Magnetic thermal tripping devices ]
FIG. 18 Air blast circuit breaker arcing process.
[ Blast tube Terminal Air flow High pressure Low pressure Terminal Arc probe Arc in initial and final positions Exhaust Moving contact Sliding contact Piston Nozzle]