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1.1 Background

Visual inspection of the transformer exterior reveals important condition information. For example, valves positioned incorrectly, plugged radiators, stuck temperature indicators and level gauges, and noisy oil pumps or fans. Oil leaks can often be seen which indicate a potential for oil contamination, loss of insulation, or environmental problems. Physical inspection requires staff experienced in these techniques.

1.2 Temperature Indicators Online
Winding temperature indicator

Winding temperature indicator

Check all temperature indicators while the transformer is online. The winding temperature indicator should be reading approximately 15 degrees above the top oil temperature. If this is not the case, one or both temperature indicators are malfunctioning. Check the top oil temperature next to the top oil indicator’s thermowell with an infrared camera.

Compare the readings with the top oil indicator. Reset all maximum indicator hands on the temperatures indicating devices after recording the old maximum temperature readings.

High temperature may mean overloading, cooling problems, or problems with windings, core, or connections.

1.3 Temperature Indicators Offline

When the transformer is offline and has cooled to ambient temperature, check the top oil and winding temperature indicators; both should be reading the same. If not, one or both temperature indicators are malfunctioning. Check the calibration according to the proper procedure. Also compare these readings with the indicated temperature on the conservator oil level indicator; all three should agree.

1.4 Conservator
Figure 1.—Conservator Oil Level

Figure 1.—Conservator Oil Level

Check the oil level gauge on the conservator. See figure 1 at right. This gauge indicates oil level by displaying a temperature. Compare the indicated temperature on the conservator level gauge with the top oil temperature indicator. They should be approximately the same.

Calibrate or replace the conservator oil level indicator if needed, but only after checking the top oil temperature indicator as shown in the above section. Reference also IEEE 62-1995™ [11], section 6.6.2. If atmospheric gases (nitrogen, oxygen, carbon dioxide) and perhaps moisture increase suddenly in the DGA, a leak may have developed in the conservator diaphragm or bladder. With the transformer offline and under clearance, open the inspection port on top of the conservator and look inside with a flashlight. If there is a leak, oil will be visible on top of the diaphragm or inside the bladder. Reclose the conservator and replace the bladder or diaphragm at the first opportunity by scheduling an outage. If there is no gas inside the Buchholz Relay, the transformer may be re-energized after bleeding the air out of the bladder failure relay.

A DGA should be taken immediately to check for O2, N2, and moisture. However, the transformer may be operated until a new bladder is installed, keeping a close eye on the DGAs. It is recommended that DGAs be performed every 3 months until the new bladder is installed. After the bladder installation, the oil may need to be de-gassed if O2 exceeds 10,000 ppm. Also, carefully check the moisture level in the DGAs to ensure it is below recommended levels for the particular transformer voltage. Check the desiccant in the breather often; never let more than two-thirds become discolored before renewing the desiccant. All efforts should be made to keep the oxygen level below 2,000 ppm and moisture as low as possible.

1.5 Conservator Breather
Figure 2.—Conservator Breather

Figure 2.—Conservator Breather

Check the dehydrating (desiccant) breather for proper oil level if it is an oil type unit. Check the color of the desiccant and replace it when approximately one-third remains with the proper color. See figure 2 for a modern oil type desiccant breather. Notice the pink desiccant at the bottom of the blue indicating that this portion is water saturated. Notice also that oil is visible in the very bottom 1-inch or so of the unit.

Many times, the oil is clear, and the oil level will not be readily apparent. Normally, there is a thin line around the breather near the bottom of the glass; this indicates where the oil level should be.

Compare the oil level with the level indicator line and refill, if necessary. Note the 1¼-inch pipe going from the breather to the conservator. Small tubing (½ inch or so) is not large enough to admit air quickly when the transformer is de-energized in winter. A transformer can cool so quickly that a vacuum can be created from oil shrinkage with enough force to puncture a bladder. When this happens, the bladder is destroyed; and air is pulled into the conservator making a large bubble.

1.6 Nitrogen

If the transformer has a nitrogen blanket, check the pressure gauge for proper pressure. Look at the operators recording of pressures from the pressure gauge. If this does not change, the gauge is probably defective. Check the nitrogen bottle to insure the nitrogen is the proper quality (see PEB No. 5 [20]). Check for any increased usage of nitrogen which indicates a leak. Smaller transformers such as station service or smaller generator-step-up transformers may not have nitrogen bottles attached to replace lost nitrogen. Be especially watchful of the pressure gauge and the operator’s records of pressures with these.

The pressure gauge can be defective for years, and no one will notice. The gauge will read nearly the same and will not vary much over winter and summer or night and day. Meanwhile, a nitrogen leak can develop; and all the N2 will be lost. This allows air with oxygen and moisture to enter and deteriorate the oil and insulation. Watch for increased oxygen and moisture in the DGA. An ultrasonic and sonic leak detection instrument (P-2000) is used for locating N2 leaks.

1.7 Oil Leaks
Oil Leaks

Oil Leaks

Check the entire transformer for oil leaks. Leaks develop due to gaskets wearing out, ultraviolet exposure, taking a “set,” or from expansion and contraction, especially after transformers have cooled, due to thermal shrinkage of gaskets and flanges. Many leaks can be repaired by applying an epoxy or other patch.

Flange leaks may be stopped with these methods using rubberized epoxy forced into the flange under pressure. Very small leaks in welds and tanks may be stopped by peening with a ball-peen hammer, cleaning with the proper solvent, and applying a “patch” of the correct epoxy.

Experienced leak mitigation contractors whose work is guaranteed may also be employed. Some leaks may have to be welded. Welding may be done with oil in the transformer if an experienced, qualified, and knowledgeable welder is available. If welding with oil in the tank is the method chosen, oil samples must be taken for DGA both before and after welding. Welding may cause gases to appear in the DGA and it must be determined what gases are attributed to welding and which ones to transformer operation.

1.8 Pressure Relief Device

With the transformer under clearance, check the pressure relief device indicating arm on top of the Figure 3.— Pressure Relief Device. transformer to see if it has operated. If it has operated, the arm will be in the up (vertical) position, and alarm and shutdown relays should have activated.

Figure 3.— Pressure Relief Device

Figure 3.— Pressure Relief Device

CAUTION:
Do not re-energize a transformer after this device has operated and relays have de-energized the transformer, until extensive testing to determine and correct the cause has been undertaken. Explosive, catastrophic failure could be the result of energization after this device has operated.

1.9 Oil Pumps

If the transformer has oil pumps, check flow indicators and pump isolation valves to ensure oil is circulating properly. Pump motor(s) may also have reversed rotation, and flow indicators may still show that oil is flowing. To ensure motors are turning in the proper direction, use an ammeter to check the motor current. Compare results with the full-load-current indicated on the motor nameplate. If the motor is reversed, the current will be much less than the nameplate full-load-current.  Check oil pumps with a vibration analyzer if they develop unusual noises.

Have the DGA lab check for dissolved metals in the oil and run a metal particle count for metals if the bearings are suspect. This should be done immediately, as soon as a bearing becomes suspect; bad oil-pump bearings can put enough metal particles into the oil to threaten transformer insulation and cause flashover inside the tank. An explosive catastrophic failure of the transformer tank could be the result.

1.10 Fans and Radiators

Inspect all isolation valves at the tops and bottoms of radiators to ensure they are open. Inspect cooling fans and radiators for cleanliness and fans for proper rotation. Check for dirty or damaged fan blades or partially blocked radiators. Fans are much more efficient if the blades are clean and rotating in cool air. Normally, fans blow cool air through the radiators; they should not be pulling air through. Check to see if fans are reversed electrically (i.e., pulling air first through the radiators and then through the fan blades). This means the blades are rotating in warm air after it passes through the radiator which is much less efficient. Place a hand on the radiator opposite the fans; air should be coming out of the radiator against your hand.

Watch the blades as they rotate slowly when they are starting or stopping to determine which way they should be rotating and correct the rotation if necessary.

1.11 Buchholz Relay
Figure 4.—Buchholz Relay

Figure 4.—Buchholz Relay

Inspect the isolation valve on the Buchholz relay to ensure it is open. With the transformer offline and under clearance, examine the Buchholz relay by lifting the window cover (center in figure 4 at right) and looking inside. If there is gas inside, the oil will be displaced, and the gas will be evident as a space on top the oil. If sufficient gas is found to displace the upper float, the alarm should be activated. The small valve at the top left is to bleed the gas off and reset the relay. If a small amount of gas is found in this relay when the transformer is new (a few months after startup), it is probably just air that has been trapped in the transformer structure and is now escaping; there is little cause for concern.

If the transformer has been on line for some time (service aged), and gas is found in the Buchholz, oil samples must be sent to the lab for DGA and extensive testing. Consult with the manufacturer and other transformer experts. A definite cause of the gas bubbles must be determined and corrected before re-energization of the transformer.

1.12 Sudden Pressure Relay
Figure 5.—Sudden Pressure Relay

Figure 5.—Sudden Pressure Relay

An example relay is shown in figure 5 at the left. The purpose of this relay is to alarm if there is a sudden pressure rise inside the tank. This relay is very sensitive and will operate if the pressure rises only a little. If a very small pressure change occurs caused by a small electrical fault inside the tank, this relay will alarm. In contrast, the pressure relief device (shown above in figure 5) operates if a large pressure builds inside the tank caused by heavy arcing and heating causing the oil to boil and bubble. Inspect the isolation valve to ensure it is open.

With the transformer offline and under clearance, functionally test the sudden pressure relay by slowly closing the isolating valve. Leave it closed for a few seconds and reopen the valve very suddenly; this should activate the alarm. If the alarm does not activate, test the relay, and replace it with a new one if it fails to function.

1.13 Bladder Failure Relay

On newer transformers, a bladder failure relay may be found on or near the conservator top on the oil side of the bladder. This relay is near the highest point of the transformer. Its purpose is to alarm if the bladder fails and admits air bubbles into the oil.

The relay will also serve as a backup to the Buchholz relay. If the Buchholz relay overfills with gas and fails to activate an alarm or shutdown, gas will bypass the Buchholz and migrate up into the conservator, eventually to the bladder failure relay. See figure 6. Of course, these gases should also show up in the DGA. However, DGAs are normally taken only once per year, and a problem may not be discovered before these alarms are activated.

Figure 6.—Bladder Failure Relay

Figure 6.—Bladder Failure Relay

If the bladder failure alarm is activated, place the transformer under clearance and check the Buchholz for gas as mentioned in section 1.10. Open the conservator inspection port and look inside with a flashlight to check for oil inside the bladder. Bleed the air/gas from the conservator using the bleed valve on top of the conservator. If the transformer is new and has been in service for only a few months, the problem most likely is air escaping from the structure as mentioned in section 1.11.

With the transformer under clearance, open the inspection port on top of the conservator and look inside the bladder with a flashlight. If oil is found inside the bladder, it has developed a leak; a new one must be ordered and installed.

SOURCE: Transformer Diagnostics, Fascilities Instructions, Standards And Techniques

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Related articles

Maintenance Of Meduim Voltage Circuit Breakers

Maintenance Of Meduim Voltage Circuit Breakers

Medium-voltage circuit breakers rated between 1 and 72 kV may be assembled into metal-enclosed switchgear line ups for indoor use, or may be individual components installed outdoors in a substation. Air-break circuit breakers replaced oil-filled units for indoor applications, but are now themselves being replaced by vacuum circuit breakers (up to about 35 kV).

Medium voltage circuit breakers which operate in the range of 600 to 15,000 volts should be inspected and maintained annually or after every 2,000 operations, whichever comes first.

The above maintenance schedule is recommended by the applicable standards to achieve required performance from the breakers.
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Safety Practices

Maintenance procedures include the safety practices indicated in the ROMSS (Reclamation Operation & Maintenance Safety Standards) and following points that require special attention.

  • Be sure the circuit breaker and its mechanism are disconnected from all electric power, both high voltage and control voltage, before it is inspected or repaired.
  • Exhaust the pressure from air receiver of any compressed air circuit breaker before it is inspected or re­paired.
  • After the circuit breaker has been disconnected from the electrical power, attach the grounding leads properly before touching any of the circuit breaker parts.
  • Do no lay tools down on the equipment while working on it as they may be forgotten when the equipment is placed back in service.
    .

Maintenance Procedures For Medium Voltage Air Circuit Breakers

The following suggestions are for use in conjunction with manufacturer’s instruction books for the maintenance of medium voltage air circuit breakers:

  1. Clean the insulating parts including the bushings.
  2. Check the alignment and condition of movable and stationary contacts and adjust them per the manufacturer’s data.
  3. See that bolts, nuts, washers, cotter pins, and all terminal connections are in place and tight.
  4. Check arc chutes for damage and replace damaged parts.
  5. Clean and lubricate the operating mechanism and adjust it as described in the instruction book. If the operat­ing mechanism cannot be brought into specified tolerances, it will usually indicate excessive wear and the need for a complete overhaul.
  6. Check, after servicing, circuit breaker to verify that contacts move to the fully opened and fully closed positions, that there is an absence of friction or binding, and that electrical operation is functional.
    .

Maintenance Procedures For Medium Voltage Oil Circuit Breakers

The following suggestions are for use in conjunction with the manufacturer’s instruction books for the maintenance of medium-voltage oil circuit breakers:

  1. Check the condition, alignment, and adjustment of the contacts.
  2. Thoroughly clean the tank and other parts which have been in con­ tact with the oil.
  3. Test the dielectric strength of the oil and filter or replace the oil if the dielectric strength is less than 22 kV. The oil should be filtered or replaced whenever a visual inspection shows an excessive amount of carbon, even if the dielectric strength is satisfactory.
  4. Check breaker and operating mechanisms for loose hardware and missing or broken cotter pins, retain­ ing rings, etc.
  5. Adjust breaker as indicated in instruction book.
  6. Clean and lubricate operating mechanism.
  7. Before replacing the tank, check to see there is no friction or binding that would hinder the breaker’s operation. Also check the electrical operation. Avoid operating the breaker any more than necessary without oil in the tank as it is designed to operate in oil and mechanical damage can result from excessive operation without it.
  8. When replacing the tank and refilling it with oil, be sure the gaskets are undamaged and all nuts and valves are tightened properly to prevent leak­ age.
    .

Maintenance Procedures For Medium Voltage Vacuum Circuit Breakers

Direct inspection of the primary contacts is not possible as they are enclosed in vacuum containers. The operating mechanisms are similar to the breakers discussed earlier and may be maintained in the same manner. The following two maintenance checks are suggested for the primary contacts:

  1. Measuring the change in external shaft position after a period of use can indicate extent of contact erosion. Consult the manufacturer’s instruction book.
  2. Condition of the vacuum can be checked by a hipot test. Consult the manufacturer’s instruction book.
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SOURCE: MAINTENANCE OF POWER CIRCUIT BREAKERS by HYDROELECTRIC RESEARCH AND TECHNICAL SERVICES GROUP

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Related articles

What to use? Vacuum or SF6 circuit breaker?

What CB to use? Vacuum or SF6 circuit breaker?

Until recently oil circuit breakers were used in large numbers for Medium voltage Distribution system in many medium voltage switchgears. There are number of disadvantages of using oil as quenching media in circuit breakers. Flammability and high maintenance cost are two such disadvantages! Manufacturers and Users were forced to search for different medium of quenching. Air blast and Magnetic air circuit breakers were developed but could not sustain in the market due to other disadvantages associated with such circuit breakers. These new types of breakers are bulky and cumbersome. Further research were done and simultaneously two types of breakers were developed with SF6 as quenching media in one type and Vacuum as quenching media in the other. These two new types of breakgasers will ultimately replace the other previous types completely shortly. There are a few disadvantages in this type of breakers also. One major problem is that the user of the breakers are biased in favour of old fashioned oil circuit breakers and many of the users always have a step motherly attitude to the new generations of the breakers. However in due course of time this attitude will disappear and the new  type of breakers will get its acceptance among the users and ultimately they will completely replace the oil circuit breakers. An attempt is made to make a comparison between the SF6 type and vacuum type circuit breakers with a view to find out as to which of the two types is superior to the other. We will now study in detail each type separately before we compare them directly.

Vacuum Circuit Breaker
Evolis Circuit Breaker

Evolis MV Circuit Breaker

In a Vacuum circuit breaker, vacuum interrupters are used for breaking and making load and fault currents. When the contacts in vacuum interrupter separate, the current to be interrupted  initiates a metal vapour arc discharge and flows through the plasma until the next current zero. The arc is then extinguished and the conductive metal vapour condenses on the metal surfaces within a matter of micro seconds. As a result the dielectric strength in the breaker builds up very rapidly.

The properties of a vacuum interrupter depend largely on the material and form of the contacts. Over the period of their development, various types of contact material have been used. At the moment it is accepted that an oxygen free copper chromium alloy is the best material for High voltage circuit breaker. In this alloy , chromium is distributed through copper in the form of fine grains. This material combines good arc extinguishing characteristic with a reduced tendency to contact welding and low chopping current when switching inductive current. The use of this special material is that the current chopping is limited to 4 to 5 Amps.

At current under 10KA, the Vacuum arc burns as a diffuse discharge. At high values of current the arc changes to a constricted form with an anode spot. A  constricted arc that remain on one spot for too long can thermically over stress the contacts to such a degree that the deionization of the contact zone at current zero can no longer be guaranteed . To overcome this problem the arc root must be made to move over the contact surface. In order to achieve this, contacts are so shaped that the current flow through them results in a magnetic field being established which is at right angles to the arc axis. This radial field causes the arc root to rotate rapidly around the contact resulting in a uniform distribution of the heat over its surface. Contacts of this type are called radial magnetic field electrodes and they are used in the majority of circuit breakers for medium voltage application.

A new design has come in Vacuum interrupter, in which switching over the arc from diffusion to constricted state by subjecting the arc to an axial magnetic field. Such a field can be provided by leading the arc current through a coil suitably arranged outside the vacuum chamber. Alternatively the field can be provided by designing the contact to give the required contact path. Such contacts are called axial magnetic field electrodes. This principle has advantages when the short circuit current is in excess of 31.5 KA.

SF6 Gas Circuit Breaker
SF6 circuit breakers

SF6 circuit breakers

In an SF6 circuit-breaker, the current continues to flow after contact separation through the arc whose plasma consists of ionized SF6 gas. For, as long as it is burning, the arc is subjected to a constant flow of gas which extracts heat from it. The arc is extinguished at a current zero, when the heat is extracted by the falling current. The continuing flow of gas finally de-ionises the contact gap and establishes the dielectric strength required to prevent a re-strike.

The direction of the gas flow, i.e., whether it is parallel to or across the axis of the arc, has a decisive influence on the efficiency of the arc interruption process. Research has shown that an axial flow of gas creates a turbulence which causes an intensive and continuous interaction between the gas and the plasma as the current approaches zero. Cross-gas-flow cooling of the arc is generally achieved in practice by making the arc move in the stationary gas. This interruption process can however, lead to arc instability and resulting great fluctuations in the interrupting capability of the circuit breaker.

In order to achieve a flow of gas axially to the arc a pressure differential must be created along the arc. The first generation of the SF6 circuit breakers used the two-pressure principle of the air-blast circuit-breaker. Here a certain quantity of gas was kept stored at a high pressure and released into the arcing chamber. At the moment high pressure gas and the associated compressor was eliminated by the second generation design. Here the pressure differential was created by a piston attached to the moving contacts which compresses the gas in a small cylinder as the contact opens. A disadvantage is that this puffer system requires a relatively powerful operating mechanism.

Neither of the two types of circuit breakers described was able to compete with the oil circuit breakers price wise. A major cost component of the puffer circuit-breaker is the operating mechanism; consequently developments followed which were aimed at reducing or eliminating this additional cost factor. These developments concentrated on employing the arc energy itself to create directly the pressure-differential needed. This research led to the development of the self-pressuring circuit-breaker in which the over – pressure is created by using the arc energy to heat the gas under controlled conditions. During the initial stages of development, an auxiliary piston was included in the interrupting mechanism, in order to ensure the satisfactory breaking of small currents. Subsequent improvements in this technology have eliminated this requirement and in the latest designs the operating mechanism must only provide the energy needed to move the contacts.

Parallel to the development of the self-pressuring design, other work resulted in the rotating – arc SF6 gas circuit breaker. In this design the arc is caused to move through, in effect the stationery gas. The relative movement between the arc and the gas is no longer axial but radial, i.e., it is a cross-flow mechanism. The operating energy required by circuit breakers of this design is also minimal.

Table 1. Characteristics of the SF6 and vacuum current interrupting technologies.

SF6 Circuit BreakersVacuum Circuit Breakers
CriteriaPuffer Circuit BreakerSelf-pressuring circuit-breakerContact material-Chrome-Copper
Operating energy requirementsOperating Energy requirements are high, because the mechanism must supply the energy needed to compress the gas.Operating Energy requirements are low, because the mechanism must move only relatively small masses at moderate speed, over short distances. The mechanism does not have to provide the energy to create the gas flowOperating energy requirements are low, because the mechanism must move only relatively small masses at moderate speed, over very short distances.
Arc EnergyBecause of the high conductivity of the arc in the SF6 gas, the arc energy is low. (arc voltage is between 150 and 200V.)Because of the very low voltage across the metal vapour arc, energy is very low. (Arc voltage is between 50 and 100V.)
Contact ErosionDue to the low energy the contact erosion is small.Due to the very low arc energy, the rapid movement of the arc root over the contact and to the fact that most of the metal vapour re-condenses on the contact, contact erosion is extremely small.
Arc extinguishing mediaThe gaseous medium SF6 possesses excellent dielectric and arc quenching properties. After arc extinction, the dissociated gas molecules recombine almost completely to reform SF6. This means that practically no loss/consumption of the quenching medium occurs. The gas pressure can be very simply and permanently supervised. This function is not needed where the interrupters are sealed for life.No additional extinguishing medium is required. A vacuum at a pressure of 10-7 bar or less is an almost ideal extinguishing medium. The interrupters are ‘sealed for life’ so that supervision of the vacuum is not required.
Switching behavior in relation to current choppingThe pressure build-up and therefore the flow of gas is independent of the value of the current. Large or small currents are cooled with the same intensity. Only small values of high frequency, transient currents, if any, will be interrupted. The de-ionization of the contact gap proceeds very rapidly, due to the electro-negative characteristic of the SF6 gas and the arc products.The pressure build-up and therefore the flow of gas is dependent upon the value of the current to be interrupted. Large currents are cooled intensely, small currents gently. High frequency transient currents will not, in general, be interrupted. The de-ionization of the contact gap proceeds very rapidly due to the electro-negative characteristic of the SF6 gas and the products.No flow of an ‘extinguishing’ medium needed to extinguish the vacuum arc. An extremely rapid de-ionization of the contact gap, ensures the interruption of all currents whether large or small. High frequency transient currents can be interrupted. The value of the chopped current is determined by the type of contact material used. The presence of chrome in the contact alloy with vacuum also.
No. of short-circuit operation10—5010—5030—100
No. full load operation5000—100005000—1000010000—20000
No. of mechanical operation5000—200005000—2000010000—30000

Comparison of the SF6 And Vacuum Technologies

The most important characteristics of the SF6 gas and vacuum-circuit breakers, i.e., of SF6 gas and vacuum as arc-extinguishing media are summarized in Table-1.

In the case of the SF6 circuit-breaker, interrupters which have reached the limiting number of operations can be overhauled and restored to ‘as new’ condition. However, practical experience has shown that under normal service conditions the SF6 interrupter never requires servicing throughout its lifetime. For this reason, some manufacturers no longer provide facilities for the user to overhaul the circuit-breaker, but have adopted a ‘sealed for life’ design as for the vacuum-circuit breaker.

The operating mechanisms of all types of circuit-breakers require servicing, some more frequently than others depending mainly on the amount of energy they have to provide. For the vacuum-circuit breaker the service interval lies between 10,000 and 20,000 operations. For the SF6 designs the value varies between 5,000 and 20,000 whereby, the lower value applies to the puffer circuit-breaker for whose operation, the mechanism must deliver much more energy.

The actual maintenance requirements of the circuit-breaker depend upon its service duty, i.e. on the number of operations over a given period of time and the value of current interrupted. Based on the number of operations given in the previous section, it is obvious that SF6 and vacuum circuit-breakers used in public supply and /or industrial distribution systems will, under normal circumstances, never reach the limits of their summated breaking current value. Therefore, the need for the repair or replacement of an interrupter will be a rare exception and in this sense these circuit-breakers can be considered maintenance-free. Service or maintenance requirements are therefore restricted to routine cleaning of external surfaces and the checking and lubrication of the mechanism, including the trip-linkages and auxiliary switches. In applications which require a very high number of circuit-breaker operations e.g. for arc furnace duty or frequently over the SF6 design, due to its higher summated-breaking current capability. In such cases it is to be recommended that the estimation of circuit-breaker maintenance costs be given some consideration and that these be included in the evaluation along with the initial, capital costs.

Reliability

In practice, an aspect of the utmost importance in the choice of a circuit-breaker is reliability.

The reliability of a piece of equipment is defined by its mean time to failure (MTF), i.e. the average interval of time between failures. Today, the SF6 and vacuum circuit-breakers made use of the same operating mechanisms, so in this regard they can be considered identical.

However, in relation to their interrupters the two circuit breakers exhibit a marked difference. The number of moving parts is higher for the SF6 circuit-breaker than that for the vacuum unit. However, a reliability comparison of the two technologies on the basis of an analysis of the number of components are completely different in regards design, material and function due to the different media. Reliability is dependent upon far too many factors, amongst others, dimensioning, design, base material, manufacturing methods, testing and quality control procedures, that it can be so simply analyzed.

In the meantime, sufficient service experience is available for both types of circuit-breakers to allow a valid practical comparison to be made. A review of the available data on failure rates confirms that there is no discernible difference in reliability between the two circuit-breaker types. More over, the data shows that both technologies exhibit a very high degree of reliability under normal and abnormal conditions.

Switching of fault currents

Today, all circuit-breakers from reputable manufacturers are designed and type-tested in conformance with recognized national or international standards (IEC56). This provides the assurance that these circuit-breakers will reliably interrupt all fault currents up to their maximum rating. Further, both types of circuit-breakers are basically capable of interrupting currents with high DC components; such currents can arise when short circuits occur close to a generator. Corresponding tests have indeed shown that individual circuit-breakers of both types are in fact, capable of interrupting fault currents with missing current zeros i.e. having a DC component greater than 100 per cent. Where such application is envisaged, it is always to be recommended that the manufacturer be contacted and given the information needed for a professional opinion.

As regards the recovery voltage which appears after the interruption of a fault current the vacuum-circuit breaker can, in general, handle voltages with RRV values of up to 5KV. SF6 circuit-breakers are more limited, the values being in the range from 1 to 2 KV. In individual applications, e.g. in installations with current limiting chokes or reactors, etc., With SF6 circuit-breakers it may be advisable or necessary to take steps to reduce that rate of rise of the transient recovery voltage.

Switching small inductive currents

The term, small inductive currents is here defined as those small values of almost pure inductive currents, such as occur with unloaded transformers, motor during the starting phase or running unloaded and reactor coils. When considering the behavior of a circuit-breaker interrupting such currents, it is necessary to distinguish between high frequency and medium frequency transient phenomena.

Medium frequency transients arise from, amongst other causes, the interruption of a current before it reaches its natural zero. All circuit-breakers can, when switching currents of the order of a few hundred amperes and, due to instability in the arc, chop the current immediately prior to a current zero.

This phenomenon is termed real current chopping. When it occurs, the energy stored in the load side inductances oscillates through the system line to earth capacitances (winding and cable capacitances) and causes an increase in the voltage. This amplitude of the resulting over voltage is a function of the value of the current chopped. The smaller the chopped current, the lower the value of the over voltage.

In addition to the type of circuit – breaker, the system parameters at the point of installation are factors which determine the height of the chopping current, in particular the system capacitance parallel to the circuit breaker is of importance. The chopping current of SF6 circuit-breakers is essentially determined by the type of circuit-breaker. The value of chopping current varies from 0.5A to 15A, whereby the behavior of the self – pressuring circuit-breaker is particularly good, its chopping current being less than 3A.This ‘soft’

Switching feature is attributable to the particular characteristics of the interrupting mechanism of the self-pressuring design and to the properties of the SF6 gas itself.

In the early years of the development of the vacuum circuit-breaker the switching of small inductive currents posed a major problem, largely due to the contact material in use at that time. The introduction of the chrome copper contacts brought a reduction of the chopping current to between 2 to 5A.The possibility of impermissible over voltages arising due to current chopping has been reduced to a negligible level.

High frequency transients arise due to pre- or re-striking of the arc across the open contact gap. If, during an opening operation, the rising voltage across the opening contacts, exceed the dielectric strength of the contact gap , a re-strike occurs. The high-frequency transient current arising from such a re-strike can create high frequency current zeros causing the circuit-breaker to, interrupt again. This process can cause a further rise in voltage and further re-strikes. Such an occurrence is termed as multiple restriking.

With circuit- breakers that can interrupt high frequency transient currents, re-striking can give rise to the phenomenon of virtual current chopping. Such an occurrence is possible when a re-strike in the first-phase-to-clear, induces high frequency transients in the other two phases, which are still carrying service frequency currents. The superimposition of this high frequency oscillation on the load current can cause an apparent current zero and an interruption by the circuit-breaker, although the value of load current may be quite high. This phenomenon is called virtual current chopping and can result in a circuit breaker ‘chopping’ very much higher values of current than it would under normal conditions. The results of virtual current chopping are over-voltages of very high values.

This phenomenon is termed real current chopping. When it occurs, the energy Stored in the load side inductances oscillates through the system line to earth capacitances (winding and cable capacitances) and causes an increase in the voltage. This amplitude of the resulting over voltage is a function of the value of the current chopped. The smaller the chopped current, the lower the value of the over voltage.

In addition to the type of circuit – breaker, the system parameters at the point of installation are factors which determine the height of the chopping current, in particular the system capacitance parallel to the circuit breaker is of importance. The chopping current of SF6 circuit-breakers is essentially determined by the type of circuit-breaker. The value of chopping current varies from 0.5A to 15A, whereby the behaviour of the self – pressuring circuit-breaker is particularly good, its chopping current being less than 3A.This ‘soft’   Switching feature is attributable to the particular characteristics of the interrupting mechanism of the self-pressuring design and to the properties of the SF6 gas itself.

In the early years of the development of the vacuum circuit-breaker the switching of small inductive currents posed a major problem, largely due to the contact material in use at that time. The introduction of the chrome copper contacts brought a reduction of the chopping current to between 2 to 5A.The possibility of impermissible over voltages arising due to current chopping has been reduced to a negligible level.

High frequency transients arise due to pre- or re-striking of the arc across the open contact gap. If, during an opening operation, the rising voltage across the opening contacts exceeds the dielectric strength of the contact gap, a re-strike occurs. The high-frequency transient current arising from such a re-strike can create high frequency current zeros causing the circuit-breaker to, interrupt again. This process can cause a further rise in voltage and further re-strikes. Such an occurrence is termed as multiple re-striking.

With circuit- breakers that can interrupt high frequency transient currents, re-striking can give rise to the phenomenon of virtual current chopping. Such an occurrence is possible when a re-strike in the first-phase-to-clear, induces high frequency transients in the other two phases, which are still carrying service frequency currents. The superimposition of this high frequency oscillation on the load current can cause an apparent current zero and an interruption by the circuit-breaker, although the value of load current may be quite high. This phenomenon is called virtual current chopping and can result in a circuit breaker ‘chopping’ very much higher values of current than it would under normal conditions. The results of virtual current chopping are over-voltages of very high values

Table2. Comparison of the SF6 And Vacuum Technologies In Relation To Operational Aspects

CriteriaSF6 BreakerVacuum Circuit Breaker
Summated current cumulative10-50 times rated short circuit current30-100 times rated short circuit current
Breaking current capacity of interrupter5000-10000 times10000-20000 times
Mechanical operating life5000-20000 C-O operations10000-30000 C-O operations
No operation before maintenance5000-20000 C-O operations10000-30000 C-O operations
Time interval between servicing Mechanism5-10 years5-10 years
Outlay for maintenanceLabour cost High, Material cost LowLabour cost Low, Material cost High
ReliabilityHighHigh
Dielectric withstand strength of the contact gapHighVery high

Very extensive testing has shown that, because of its special characteristics the SF6 self-pressuring circuit-breaker possesses considerable advantages in handling high frequency transient phenomena, in comparison with both the puffer type SF6 and the vacuum circuit breakers. The past few years have seen a thorough investigation of the characteristics of vacuum circuit breakers in relation to phenomena such as multiple re-striking and virtual current chopping. These investigations have shown that the vacuum circuit-breaker can indeed cause more intense re-striking and hence more acute over voltages than other types. However, these arise only in quite special switching duties such as the tripping of motors during starting and even then only with a very low statistical probability. The over-voltages which are created in such cases can be reduced to safe levels by the use of metal oxide surge diverters.

Table3. Comparison of the SF6 And Vacuum Switching Technologies In Relation To Switching Applications

CriteriaSF6 Circuit BreakerVacuum Circuit Breaker
Switching of Short circuit current with High DC componentWell suitedWell suited
Switching of Short circuit current with High RRVWell suited under certain conditions (RRV>1-2 kV per Milli secondsVery well suited
Switching of transformersWell suited.Well suited
Switching of reactorsWell suitedWell suited. Steps to be taken when current <600A. to avoid over voltage due to current chopping
Switching of capacitorsWell suited. Re-strike freeWell suited. Re-strike free
Switching of capacitors back to backSuited. In some cases current limiting reactors required to limit inrush currentSuited. In some cases current limiting reactors required to limit inrush current
Switching of arc furnaceSuitable for limited operationWell suited. Steps to be taken to limit over voltage.

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