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The speed of the prime mover should match with the synchronous speed of the grid frequency. Monitor the following parameters a Cold and Hot gas temperatures. If drop in gas pressure is abnormal Max.
However, the terminal voltage shall be reduced to The generator breaker will trip on reverse Power Protection. If not the rotor should be turned by degrees periodically, say twice in an Hr to avoid thermal deflection of rotor.
The operation of the generator shall be governed by the capability diagram given by the manufacturers. However, the performance of the generator with frequency variation is limited by the turbine. For the turbine, the LP turbine blades are very sensitive of frequency variation. Operation of the TG set above Temperature of the Coolants and Winding: a Hydrogen If the temperature of the cold gas increases beyond the rated value of 45 deg.
C, generator has to be unloaded suitably as recommended by manufacturers. The operation of the generator with cold gas temperature more than 55 deg. C is not permitted. Similarly, operation of the generator with a cold gas temperature below 20 deg. C is also not recommended. Operation of the generator in Air medium is not allowed. Over loading of Generator: Under abnormal conditions, the generator can be overloaded for short duration.
Permissible values of short time overloads in terms of stator and rotor currents and corresponding duration are given below: Stator Current in K. Amps Amps 5. At the same time, current in maximum loaded phase should not exceed the permissible value for given conditions of the operation of the turbo-generator under unbalanced loads. Unsymmetrical Short Circuit: The duration of the unsymmetrical short circuit should be such that the product of square of negative sequence component of current I2 expressed in terms of per unit value of stator current and its duration in seconds does not exceed.
The permissible values of negative sequence currents and the corresponding duration are given below: Sl. Asynchronous Operation: Asynchronous induction Generator operation of the generator on field failure is allowed depending upon the permissible degree of voltage dip and acceptability of the system from the stability point of view. As the above process could not be carried out in practice, in NCTPS for loss of excitation generator trip is connected.
Motoring Action: In case of sudden closure of ESVs and IVs and control valves, stopping the entire steam flow to turbine, if the generator breaker is not getting tripped on relay protection, then motoring of the TG set will take place, taking power from the grid for meeting the losses. However, steam less regime operation is not allowed for turbine. Hence, in case the generator breaker has not tripped on protection, the same has to be tripped from UCB or from switchyard manually.
If it is not possible, the KV bus to which it is connected, has to be made dead by tripping the outgoing feeders and bus section breakers immediately to avoid damage to generator. Class — A Relay No. Generator Differential Protection 87 G Dead Machine Relay 61 B Class — B Relay No. Loss of Excitation Stage - I 40 G1 Generator Winding Temp. Very High 49 GTW Generator Oil Temp. Very High 49 GTO Class — C Relay No. Generator Backup Impedance Protection 21 G Generator Pole Slip Protection 78 G Bus bar protection 96 B Class — B.
Any abnormality in these seals or the associated seal oil system may lead to hydrogen escape from the machine, and may even cause an explosion in the worst case. Therefore, it is very essential that the utmost care is paid while operating and maintaining this system. These seals are supplied with pressurized oil from an exclusive closed loop oil system to prevent hydrogen escape at the shaft and ingress of air into generator.
The oil in the seal oil system is the same as that used in TG bearings and turbine governing system. During normal operation, AC seal oil pump draws the seal oil from the seal oil tank and feeds to the shaft seals through coolers and filters. The seal oil supplied to the shaft seals is drained towards hydrogen and airside through the annular gap between the shaft and the seal ring. The airside seal oil is returned directly into the seal oil tank through a float valve.
The oil drained on the hydrogen side, first flows into the pre-chambers, and then flows into the intermediate oil tank, before returning into seal oil tank. The seal oil in the seal oil tank is kept under vacuum to prevent deterioration of hydrogen purity in the generator casing. The gases entrapped in the seal oil are removed, and the seal oil pumps draw only degassed oil.
Upon failure of normal AC seal oil pump due to mechanical or electrical fault, the standby DC seal oil pump automatically takes over the supply. Upon failure of both the pumps, the seal oil system is taken over by the turbine governing oil system without any interruption of oil supply. The vacuum pump is kept in operation when either of the seal oil pumps is running. The seal oil is kept at a higher pressure than the gas pressure at the generator seal rings by a specified differential pressure for reliable functioning of shaft seals.
With the seal oil pumps in operation, the seal oil pressure is controlled by differential pressure regulating valve DPRV -A. Depending on the differential pressure setting, and the signal oil and gas pressures prevailing, a larger or smaller amount of oil is returned into the seal oil tank, so that the required seal oil pressure is established at the shaft seals.
The gas pressure and the signal oil pressure act in opposite direction in the valve actuator, and the valve stem is moved upwards or downwards depending on the pressure prevailing. The valve cone is so arranged that the downward movement of the valve stem closes the valve further resulting in a rise of the seal oil pressure at the shaft seals by reducing the flow to the seal oil tank. The setting of the desired differential pressure to be maintained by the valve is carried out by corresponding preloading of the main bellows through a compression spring.
The seal oil flow can be changed over from one cooler to the other by operation of the associated isolating valves, even during unit in service. By means of change over valve assembly provided at the filters, any one filter can be taken out of service for cleaning, without interruption of the oil flow to shaft seals.
From the shaft seals, the oil drains out in two parts, viz. The oil drained towards the hydrogen side is at first passed through the pre-chambers, at both ends.
These pre- chambers serve for calming down the oil, permitting the escape of entrained gas bubbles, and de-foaming of oil. At the down stream of pre-chambers, they combine together, and flow into the intermediate oil tank IOT. The oil from the IOT is continuously returned into the seal oil tank together with the oil drained in the air side through float valves. The float valve provided on the seal oil tank permits the inflow of oil so that the level of oil does not go above high level.
Any surplus oil which is not accepted by the seal oil tank, is returned to the seal oil storage tank, and finally to the drain line to turbine main oil tank. In the case of any short fall in oil level in the seal oil tank, the oil flows from the seal oil storage tank automatically and maintains the required constant level. The seal oil tank is kept under vacuum for removing dissolved gases by the vacuum pump.
When the shaft seal oil supply is obtained from the governing oil system, the pressure is regulated by means of DPRV-B.
The valve DPRV-B opens at a downward movement of valve stem occurs at falling oil pressure in the seal oil system. The regulated oil further takes the same path to the shaft seals through the coolers and filters. Since the oil is not drawn from the SOT the float valve of the seal oil tank will not open and the drain oil will flow towards seal oil storage tank, from where it further flows into the main turbine oil tank In this case, a slow deterioration of hydrogen purity in the generator will take place, necessitating the scavenging of hydrogen to improve its purity.
Moreover, additional extractor is also provided on turbine oil tank. To ensure the free floating condition of sealing ring, in the seal body, even at high machine gas pressures, the shaft seals are provided with ring relief oil, obtained from governing oil supply line through a simplex filter, and is admitted on the side of both shaft seals.
Pressure of ring relief oil above seal 0. Pressure of oil from governing oil 7. C SOP D. Inlet pressure of oil to cooler CW pressure Cm Diff. Pressure operating 0 - 3. Rotational speed rpm Motor rating 0. After that, the seal oil pump can remain in operation.
The quantity of oil that flows towards Hydrogen side of shaft seals fills the IOT when there is no gas pressure in the generator, the oil level rises above level gauge LG-1 b In case the lub oil system can not be brought in operation, alternative method of filling the seal oil storage tank, and the system through seal oil storage tank may be adopted.
Note: Differential pressure of 2. Cm includes the static head value of 0. Normally DPRV-A remains in operation and in case of failure of pumps and as soon as the differential pressure at generator shaft seals drops to 1. DPRV-B is set at a value less by 0.
Close stop valve V-3 on seal oil unit. The oil level in the generator pre-chamber rises. Open the stop valve V-3 immediately, the oil level drops and the alarm gets reset. Replace the hexagonal plug ensuring that a gas tight seal is obtained.
The system is charged and the normal routine can be started now. Stop the pumps immediately and close the stop valve V Tighten the flanges after draining. Draining of the seal oil system is completed. The same has to be checked for closed condition. The isolation valve V-3 can be closed suitably and maintain level in IOT.
The isolation valve V can be closed till the level gets normalized. Now gradually open the valve, so that the level is maintained at normal. The float valve has to be attended at the earliest opportunity. Normalize the valve position so that the SOT is connected to vacuum or to atmosphere. As a temporary measure, the level can be controlled through the bypass valve till the float valve is attended. Check up the operation and correction may be done, if necessary.
However, it is having the property of forming an explosion mixture when mixes with air. The hydrogen gas system performs the following functions: i Provides means for safety filling of hydrogen gas into or purging out of the machine.
The hydrogen supply for the generator is obtained from a hydrogen gas distributor where 8 Nos. The pressure has to be reduced before admission to the generator casing.
This pressure is further reduced to generator casing pressure by two pressure regulators available in the gas unit. The safety relief valves are inbuilt with pressure regulators on low pressure as well as high pressure headers. Because of two parallel pressure regulators, large quantities of hydrogen can be handled during hydrogen filling operation, whenever necessary by making use of both of them at a time.
The low pressure header is maintained at constant pressure, as one of the gas cylinders remains open during generator operation for routine make up. The filling line is connected to the perforated pipe header inside generator extending along the casing at the top. In both cases, the generator must be scavenged with an inert gas such as carbon dioxide for the purpose. The carbon dioxide gas is obtained in steel cylinders and it is in a liquid state in the cylinder due to pressure.
The cylinders should be of siphon type to ensure complete emptying of the cylinders as well as to avoid evaporation of liquid carbon dioxide in cylinder itself, which may result in carbon dioxide snow formation and consequent choking of cylinder valve and reduced supply.
The arrangement of carbon dioxide distribution is similar to that of hydrogen distribution. The carbon dioxide leaves the cylinder in liquid state and is evaporated and expanded in the carbon dioxide vapouriser. The necessary heat for vapourisation and expansion is supplied to the vapouriser by the electrical heaters. A thermostat is provided in the carbon dioxide vapouriser to ensure the desired temperature so that freezing of carbon dioxide in the pipe is prevented as well as the heat transfer liquid does not change its characteristics or composition by high temperature.
A safety valve each on high and low pressure sides of the vapouriser protects the pipe system against high pressure. An expansion orifice after vapouriser is provided for controlling carbon dioxide pressure being fed during carbon dioxide filling operation. Carbon dioxide is fed to the bottom of the generator casing through a three way valve.
Being a heavy gas, it will displace the lighter gas like hydrogen or air from the top of the generator casing, as the carbon dioxide fills up from bottom. Instrument air is used for this purpose. Under all conditions of operation, except for carbon dioxide purging with air, the compressed air hose arranged between the filter and the generator pipe system should be kept disconnected. It is to ensure that no air can be admitted into the generator filled with hydrogen.
Hydrogen is then admitted at the top of the casing through hydrogen feed pipe and the carbon dioxide is discharged to atmosphere through carbon dioxide feed pipe. Hydrogen feeding to the casing is continued until required pressure of 3. Hydrogen is purged out of the generator by admitting carbon- dioxide.
The hydrogen pressure is first reduced to 0. After achieving this, air filling is started to expel the carbon dioxide out of the machine. For convenience of operation and to simplify erection, all necessary equipments, instruments, and valves required during gas filling, purging and normal operation of turbo-generator are mounted on a gas unit.
This is assembled and tested in works and is only required to be piped up-to generator, Hydrogen and Carbon dioxide distributors at site. To facilitate the operation of various valves during different operations, gas unit is provided with a mimic diagram.
The gas driers contain silica gel as absorbent and are provided with electrically heated regeneration facility. For regeneration of the drier, close the inlet and outlet valves of the drier, and open the drain valve and release hydrogen to atmosphere. Switch on the heater, which is provided in a separate chamber of the gas drier.
The moisture evaporated from saturated silica gel pink color will be vented out to atmosphere. The regeneration will be completed when the temperature of the silica gel reaches oC, indicated by the tripping of the heater by the thermostat provided in the drier.
After regeneration, the color of the silica gel will turn blue. The drier is ready for reuse now. It is connected to drain line from the bottom of the generator casing.
This device actuates the magnetic switch float and operates an alarm. There are two other LLDs provided one each from the end shield positions in order to monitor the performance of hydrogen seals. They are connected for alarm, whenever liquid collection, mostly seal oil is sensed.
The gas required for measurements is taken from the generator or from the filter cum pressure regulator and discharged to the atmosphere-outside machine hall. A safety relief valve HC-5, is provided on the low pressure side of the pressure regulator to avoid excessive pressure in the gas analyser.
The purity of hydrogen gas during normal operation is monitored by gas analyser indicator. A gas analyser indicating recorder is provided in UCB for monitoring hydrogen purity during normal operation of generator.
A terminal connection for collecting gas sample for chemical analysis in the lab, is provided in the gas unit. The gas analyser consists of a wheat-stone bridge each arm of which contains a fine glass coated platinum wire.
One pair or parallel arms are sealed in a reference gas of well known thermal conductivity and the other pair is exposed to the sample gas. A constant current is passed through the bridge network. When the thermal equilibrium is achieved, due to heat generated by the current in the gas medium the temperature of the surrounding gas and hence the resistance of the wire is a function of thermal conductivity the unbalance created in the bridge due to difference between the thermal conductivity of the reference gas and sample gas, will give the indication, directly the purity of Hydrogen in percentage.
The mechanical hydrogen purity metering system utilizes the physical relationship between the hydrogen generator casing pressure and the differential fan pressure, which in turn depends upon the fan speed and the specific gravity of the medium handled by fan. Since generator speed is almost constant during normal operation of the machine and the gas pressure in the generator casing is kept at a predetermined level a variation of the differential fan pressure is therefore indicative of change in gas purity.
The carbon dioxide vaporizer consists of a cylindrical housing closed by flanges at both ends. At one end, the electrical heating elements are fixed and on the other flange, the inlet and outlet to the coiled copper pipe of the vaporizer are fixed. The horizontally arranged housing is filled with heat transfer liquid to ensure a better heat transfer to the copper pipe coil and thus to the carbon dioxide flowing through the pipe coil.
For protection against excessive heating, thermostat is installed in the housing. For protection against possible high pressures relief valves one at the inlet and another at the outlet of the vapouriser are provided.
The orifice at the carbon dioxide outlet of the copper coil provides for an expansion of the carbon dioxide obtained from the cylinders to a pressure of 0. This is assembled and tested at works and is only required to be piped upto generator, Hydrogen and Carbon dioxide distributors at site. To facilitate operation of various valves during different operations, gas unit is provided with mimic diagram.
Description Unit No Rated hydrogen pressure inside generator casing 3. Maximum H2 pressure at which signal is initiated 3. This was supported by the fact that vacuum circuit breakers require less maintenance than their oil-filled equivalents. These resulted in a brief return to isolatable devices but based on non-oil switchgear. Most manufacturers now offer nonisolatable switchgear for primary substations, and a typical example is shown in Figure 4.
In recent years, MV switchgear has been built to withstand internal arcing, which may be caused by failure of insulation within the switchgear. Most designs use a pressure relief system whereby the explosive overpressure resulting from the internal arc is safely discharged through some form of ventilator to the open atmosphere. Although this has been shown to work well, it generally means that the substation building has to incorporate the overpressure relief system.
For distribution substations, tests have shown that a lifting, but tethered, onepiece glass reinforced plastic GRP roof can be effectively used to vent internal arc products.
The venting takes place at the joint between the walls and roof of the substation and so is at a high enough level to eliminate risk to persons nearby. An alternative to controlled pressure relief is to stop the internal arc from developing beyond the initial discharge.
In much the same way that a high rupturing capacity fuse operates before the first current peak, it is possible to eliminate an arcing fault between a conductor and earth by shorting that conductor to earth in a very short time period.
Shorting the conductor will depress the voltage on the affected phase, hence extinguishing the arc, and also start the tripping of conventional protection. Although the protection may take approximately m to operate, a small vacuum circuit breaker acting as an arc eliminator can eliminate the arc in approximately 5 m. If the switchgear enclosure is not light proof, then the sensor should be interlocked with a current transformer CT to confirm that fault current is flowing before the eliminator operates.
Without this precaution, photographic flashguns can trip out complete substations. A number of switchgear designs exist whereby an existing isolatable oil circuit breaker and its truck can be replaced by a equivalent truck consisting of a vacuum or SF6 circuit breaker. Depending on the physical arrangement, they may also provide a visual indication that an item of equipment, e.
A primary substation, as in the example, may have a switching device on the incoming side of the transformer. Depending on the protection requirements, that switching device may be a circuit breaker or it may be a disconnector. Some utilities would not use a switching device but would connect the incoming cable or overhead line directly to the transformer.
This type of disconnector could be a single break type, a double break type, a vertical break type or a pantograph type. Disconnectors can be of single- or double-pole operation, operated manually or via a motor drive, and SCADA controlled disconnectors have become increasingly popular.
Disconnectors are designed not to be opened when any amount of load current is flowing through them. They are normally capable of closing on to a line where the charging current is small, or to energize a small transformer. On the outgoing typically 20 kV side of a primary substation, there is usually a need for some form of disconnector as already discussed for fixed circuit breakers.
For full withdrawable circuit breakers, the action of physically removing the breaker is sufficient to achieve disconnection of the breaker for maintenance and, after applying circuit main grounds, for safe working on the immediately connected MV network. The switchgear in these substations is supplied as indoor gear for installation in building basements and small specially built buildings in the case of compact substations of weatherproof gear that is closely coupled to the transformer through an integral throat.
The switchgear assemblies come in both extensible and nonextensible configurations, the simplest nonextensible configuration being the ring main unit RMU. A feeder from a primary substation could connect to a number of ground-mounted distribution substations or a number of structure-mounted distribution substations or a combination of both.
The feeder may be designed as a purely radial feeder or as an open loop feeder. In either case, the ground-mounted transformer needs to be connected to the feeder using a protective device, usually a circuit breaker or a switchfuse see Figure 4. Now, if a fault occurs on the feeder, the source circuit breaker will trip, leaving the feeder and all its connected load off supply. If the location of the fault is known, then, if the feeder has a number of sectioning switches, the faulted section can be disconnected and healthy sections restored to supply.
In the radial feeder, any load connected beyond the faulted section cannot be restored to supply, but in the open loop feeder, any load connected beyond the faulted section can be restored to supply by using the alternative supply beyond the normally open point.
It follows, therefore, that at the distribution substation, switches for sectioning the feeder can be added to the local transformer protection to form a three-way switching system. This is often called a ring main unit because ring main is another term for an open loop feeder. The particular ring main unit shown in Figure 4. Both cable switches in Figure 4. In fact, protection devices are coded as T because they are generally used for transformer protection. There are subdivisions, F for a switchfuse and V for a vacuum circuit breaker.
At the top of the diagram, the fuse elements are in series with a disconnector which, like the cable switch, can be earthed. Also, there is an earthing switch between the fuse and the transformer. These two switching devices enable the transformer to be disconnected when required, also for a ruptured fuse to be changed safely.
Ring main units are also available with a circuit breaker, instead of switchfuse, for the tee off connection to the transformer.
Very often, this circuit breaker is rated at amps, which is sufficient for transformer or direct load connection. Some network design engineers have asked for a three-way ring main unit with a amp circuit breaker that can be used as part of the medium-voltage cable ring, which is not possible with a amp circuit breaker. What is needed is a three-panel ring main unit-type CFV with one cable switch for the incoming circuit , a switchfuse for local transformer protection and a amp circuit breaker for the outgoing circuit.
The sectioning switches are normally live operated, fault making and load breaking switches driven by a common mechanism operating all three phases at once. However, this is not always the case; for example, many utilities employ a load break elbow in the function of a disconnector. The majority of modern switchgear operated at medium voltage will use a standard bushing in the cable connecting area. However, other users will join the MV cable onto the bushing using a preformed elbow that, under certain circumstances, can be disconnected.
A typical elbow is shown in Figure 4. This elbow is a load break elbow; that is, it can be operated to make and break small currents. However, many elbows are deadbreak, which means that they can only be connected to or disconnected from a bushing if the bushing and elbow are disconnected from all sources of supply. An important point is that, if designed correctly, the disconnected elbow can provide the operator with the same function as the more conventional disconnector already described.
In fact, the disconnectable elbow could be described as a form of slow operating disconnector that is manually operated, one phase at a time.
A major advantage of the standard bushing is the interchange of products that it permits. Another common standard is IEEE , which covers amp deadbreak elbows. IEEE also covers amp load break elbows, which are elbows that can be used live to switch loads up to amps. The simplest ring main unit might comprise two three-phase sets of deadbreak elbows, one for the incoming cable connection and one for the outgoing cable connection.
Pad-mount substations can be very easily upgraded to load break elbows, giving a form of switching up to amps. They can also be upgraded to provide a fused connection using in line fuses but, in Figure 4.
They can also be upgraded to give a full switch or circuit breaker, which may be remote controlled if required by the utility. Most new units are SF6 where the switches are contained in one sealed enclosure, which is limited by design to a maximum number of switches typically five. The number of switches must be specified before manufacture. Again, this provision is only made during manufacture, and thus if provision for an extension is required, it must be specified in advance.
These measures are necessary to keep the cost of ring main units to an absolute minimum. Typically, larger switching assemblies are available and a code has been developed, described above, to describe all the possible configurations.
Another combination might be CCFF, which would be a four-panel switchboard with two cable switches and two fused transformer protections; similarly, CCCF would be a four-panel switchboard with three cable switches and one transformer protection. Typical coded configurations are shown in Figure 4. In these applications, D is shown as having an integral earthing switch, but this could be omitted. The widening use of remote control has shown that traditional air-insulated switches may not be as reliable in adverse environmental conditions such as climates with extreme icing, see Figure 4.
Switch moving parts are encapsulated in a stainless steel sealed housing filled with SF6 gas as shown in Figure 4. Temperature compensated gas density gauges with the facility for switch lock-out at low pressures are included in switchgear designs to ensure that any leak can be detected and safe operation safeguarded.
The gas is used as the insulating and arc-quenching medium. The switches are thus oil and maintenance free with a long life potential. Although operation can be achieved manually with a hook stick, most switches are installed for remote control. Operating mechanisms are manual, operator independent, quick close, quick open combined with a geared motor closing and opening mechanism.
Motorized actuators are mounted at switch level with direct connection to the switch shaft or in the pole-mounted control cabinet near ground level. In the latter case, the actuator is connected to the switch with a rigid mechanical transmission rod.
The motor mechanism is developed specifically to meet the requirements of automation and will operate with dead line conditions, giving opening times of approximately 0. Switch position indicators are rigidly connected to the main switch shaft to fulfill the standards IEC A2 and NF C Measurements for fault location are provided by sensors integrated into the switch bushings or through CTs externally mounted around the bushings and individual polemounted voltage transformers VTs.
North American systems tend to consider the option to operate individual phases separately even if operated as a three-phase bank, whereas European system design only considered operation of all three phases simultaneously. North American recloser configuration usually has three separate poles, whereas European reclosers are of the single-tank design. There is no reason why the individual pole design cannot be used for both system types, and they are thus seeing increased acceptance in Europe.
These devices mounted the three interrupters in a sealed steel container. The original reclosers relied on oil for insulation and arc interruption.
The control mechanism was hydraulic with a wide tolerance on the setting making coordination difficult. The advantages of vacuum interruption and SF6 soon obsoleted the oil recloser, and now all manufacturers supply single-tank designs with vacuum interrupted in a sealed gasfilled stainless container as shown in Figure 4.
The single-tank recloser is most popular in countries with European-type three-phase networks where simultaneous ganged operation of the three phases is required. The three-pole assemblies shown in Figure 4. This solid pole assembly is free of gas and oil. This approach provides certain modularity. A typical solid pole assembly shown in Figure 4. Most assemblies include integrally molded current sensors, and some manufacturers also include capacitive voltage dividers.
If the three individual interrupters are mechanically separate mechanically unganged in each phase, they can be controlled independently to provide greater protection flexibility for single-phase networks, increasing reliability. All reclosers are controlled by specialized protection relays mounted in a control cabinet at the base of the pole. Two configurations are most commonly used by the industry, a vertical break and a horizontal side break see Figure 4.
The selection of switch configuration is dependent on the line conductor spacing and geometry. The vertical break is most common because phase spacing is maintained, provided there are no lines above the switch, whereas the horizontal break will require increasing the horizontal conductor spacing around the switch location.
Traditionally, all disconnectors have been manually operated using a hook stick, a lever at the bottom of the pole secured with a padlock or a mechanism within a locked control cabinet.
These switches can be remote controlled by adding a motor actuator and an IED. In the simplest form, air break disconnectors interrupt small currents e. An additional arcing chamber see Figure 4. This type of mechanism is common for pole-mounted switchgear and, historically, for ground-mounted switchgear.
Failure to close the switch in a rapid and decisive manner can lead to electrical failure. Independent manual, where the position of the contacts depends on the energy from mechanical springs that are charged by the action of the switching operator.
The operating handle charges the springs, and once there is sufficient energy stored, the electrical contacts move rapidly, overcoming the risk of the throw-off forces leading to electrical failure.
This type of mechanism is fitted to the majority of groundmounted switchgear. Solenoid mechanism, where a powerful electrical solenoid is used to directly operate the switchgear, normally in conjunction with the spring charge mechanism of the independent manual category. This type of mechanism is mainly used on large substation circuit breakers and is unusual on distribution switchgear. Motor wound spring, where an electric motor is used, replacing the manual operating handle, to charge up springs that are then released either as soon as there is sufficient stored energy or when an electrical release is operated.
Although an actuator for the original switchgear will normally be provided by the original switchgear manufacturer, an add-on can be provided by any suitable manufacturer. Courtesy of W. Lucy Switchgear Ltd. To the left can be seen the indicator window to show the position of the switch. The right-hand switch has been equipped for remote operation by the addition of an actuator, another of which could be fitted to the left-hand switch if required.
The motor is contained in the dark colored enclosure that then operates, via a worm gear, the horizontal drive shaft, which in turn connects with a small adaptor plate onto the spring mechanism. The motor is operated from the local DC supply and controlled by the local remote terminal unit or by local electrical pushbuttons. On the outside of the horizontal drive can be seen two auxiliary limit switches, which are used to indicate the position of the switchgear main contacts and stop the actuator when the switch has completed its operation.
Although perhaps it would be ideal for the auxiliary switches to indicate the position of the switchgear contacts rather than the position of the actuator mechanism, there is a considerable cost penalty for this option because it would be necessary to open the switchgear to gain access to the main contact drive shaft. Because this would prevent the simple addition of the actuator to live switchgear, the practice of using external auxiliary contacts has become widely accepted.
It can be seen that the complete actuator drive can be disconnected if needed. A number of manufacturers use compressed gas as their energy storage instead of mechanical energy stored in a spring, and this is more common in pole-mounted switchgear. It has the advantage of possibly being a relatively cheap option but has the disadvantage that the gas bottles need to be replenished or replaced by a suitably qualified person.
The magnetic actuator see Figure 4. It is much simpler than the traditional stored energy mechanisms and solenoid-based designs. The magnetic actuator has only one moving part. The magnetic actuator is virtually maintenancefree, allowing thousands of operations without scheduled maintenance. A powerful neodymium iron boron NdFeB magnet provides the required force to hold the recloser in the closed position.
The magnetic actuator is a bistable device, meaning that it does not require energy to keep it in the open or closed position but it does need energy to enable a change of state to be made. When an open or close command is initiated, a current pulse energizes the coil for a very small period of time, enabling the required motion. When the coil is energized with current in the proper polarity, the flux produced works together with the flux generated by the permanent magnet and drives the armature to the closed position compressing the opening spring.
Once closed, the coil is de-energized and the armature is held in position via the flux generated by the permanent magnet. In the closed position, the armature is against the top plate of the actuator, forming a low reluctance path for the magnetic flux.
The static latching force of several hundred pounds is provided by the permanent magnet alone. The coil energization is not required.
The magnet itself is mounted on a metal ring to prevent damage from contact with the armature as the armature assembly moves back and forth. When the coil is momentarily energized with current in the reverse polarity, the flux produced opposes the flux generated by the permanent magnet. When this occurs, the opening spring moves the armature away from the top plate. As the gap increases, the holding force falls off very rapidly, and the opening spring drives the armature to the open position and holds it there without the coil being energized.
The nonmagnetic spacer prevents the armature from latching to the bottom plate with the same force as exists in the closed position by inserting an air gap in the flux path. The relative simplicity of design of magnetic actuators gives the same level of maintenance-free duty as the vacuum interrupter they operate. Although instrument transformers with magnetic cores have traditionally been accepted as standard for providing this function, new smaller and less costly sensing devices without the saturation characteristics of iron are being introduced as an alternative.
The long-term trend in MV switchgear design has been towards smaller size. This was incompatible with the space requirements of conventional current transformers and voltage transformers, which take up a significant volume of the cubicle. Overhead outdoor equipment is also trending towards smaller, less heavy devices with increased measurement functionality.
However, the low power output of these new devices has still allowed traditional CTs to remain as the preferred option for outdoor pole-mounted equipment. Selection of conventional CTs and VTs requires in advance the specification of load current and its future trend, rated voltage, secondary burden and accuracy classes if metering is required. In practice, the variety of different combinations means that instrument transformers are manufactured on demand and the effort to standardize the production of the physical cubicle that can be parameterized later is not possible.
The trend for configurable and standardized switchgear with shortened delivery times is not met with conventional instrumentation, particularly for indoor gear. New sensing technology offers the possibility to cover a very wide linear range, which for currents is typically 40— A and for rated voltage 7.
Table 4. The International Electrotechnical Vocabulary defines an instrument transformer as a transformer intended to supply measuring instruments, meters, relays and other similar apparatus. Specifically: 1. CTs can be subdivided into the protective CT, which is intended to supply protective relays, and the measuring CT, which is intended to supply indicating instruments, integrating meters and similar apparatus.
A voltage transformer is an instrument transformer in which the secondary voltage, in normal conditions of use, is substantially proportional to the primary voltage and differs in phase from it by an angle which is approximately zero for the appropriate direction of the connections.
Instrument transformers are given a value for burden, which is the impedance of the secondary circuit in ohms at a given power factor. However, by convention, burden is normally expressed as the apparent power VA at the specified power factor and the rated secondary current.
It is most important to maintain the loads connected to the instrument transformer within the specified burden. ZL is the impedance of the secondary winding. ZB is the impedance of the burden typically a protective relay. Unfortunately, because of the current that circulates in the magnetizing circuit, the output of the magnetic CT is not directly proportional to the input current, and hence, some errors occur in terms of both magnitude and phase.
Looking at the equivalent circuit, it can be seen that the voltage across the magnetizing circuit Xm paralleled with Rm is directly proportional to the secondary current.
It follows that, when the primary current, and hence the secondary current, is increased, the magnetizing current increases to the point that the core saturates and the magnetizing current is large enough to produce a significant error, and this is clarified in Figure 4.
The measurement CT needs to measure, for example, the load current in a circuit, which may be of the order of amps and is near to the value for the rated primary current, typically amps. In this range, the CT must be as accurate as required by the user, but outside the range of load currents, its accuracy is of less importance. Conversely, whereas the rated primary current may still be amps, the protection CT is required to operate with the fault currents that may be found on the particular system in the region of many thousands of amps.
As long as the protection CT can detect the fault and cause protection to operate, it does not need to be as accurate as perhaps a measurement CT that is calculating the revenue flows for the customer.
Rated primary current, selected from the preferred range of 10, 15, 20, 30, 50, and 75 amps and the decimal multiples. Rated secondary current, selected from the range of 1, 2, or 5 amps, but the preferred value is 5 amps.
Rated output, selected from the standard values of 2. Accuracy class, which is different for protection CTs and for measuring CTs. Accuracy limit factor, selected from the range of 5, 10, 15, 20, and 30 but only applicable to protection CTs. In distribution systems, most VTs are inductive. For three phase VTs, the rated output should be the rated output per phase 4. The CTs that are required for the measurement of current depend on the accuracy of the measurement that is needed. If, for example, the customer needs to measure current to within 0.
When taking such measurements at new switchgear, it is clearly best to specify the correct CTs from the outset. However, there are cases when a customer needs only a broad indication of the current flowing, which may be the case at distribution substations. For example, the difference between perhaps and amps may not be material, whence the importance is to match the accuracy of the CT, and all connected equipment, to the permitted tolerance.
Some network operators may want to take current measurements using existing protection CTs, for example, fitted to circuit breakers and reclosers. If the installation of additional measurement CTs would mean the breaking down of gas-tight SF6 switchgear or the removal of pole-mounted switchgear, then significant savings could be made by using existing CTs. However, it is extremely important to note that the accuracy of the resulting measurement cannot be any higher than the error produced by the CT.
Of course, trying to drive a protection relay from a measurement CT would cause the CT to saturate and probably prevent the protection from working. Great care must be taken when using connecting cables to link CTs, whether existing or new, to a remote terminal unit under extended control.
A , , Molecular Switches; Wiley- Figure 1. Two ways Figure 2 of synthesizing donor- 10 a Doddi, G. Assuming , 70, For electron-rich biphenyls, see: For neurotransmitters Pure Appl.
Reddington, M. Stoddart, J. Supramolecular Chem. Nelson, A. Svenstrup, N. VCH: Weinheim, Flood, A. For early examples of a Stoddart, J. Mater Chem. Nature , , g Dietrich-Buchecker, C. Tetrahedron Since it has not been strictly proven that both rings While these disadvantages restrict the synthetic options, they form simultaneously during the course of this reaction, it is certainly do not eliminate them entirely.
Hence, reactions have possible that tandem heterocatenation still proceeds via a been sought after that employ neutral or mildly acidic , cyclization-templation-catenation cascade, but with the dif- oxidative, and nucleophile-free conditions. Both the click ference that either the donor or the acceptor can take on the reaction18 and Eglinton coupling19 were selected as promising role of the template with the outcome being identical.
This been confirmed experimentally,17 although this species is paper presents an examination of the scope and limitations of normally not isolated. Finally, dynamic 1H NMR spectroscopic investigations show the de- pendence of conformational and co-conformational freedom on the size and nature of the [2]catenanes and allow us to identify and quantify the barriers to several dynamic processes occurring in the new catenated compounds.
Alternative strategies in the template-directed synthesis of charged 18 a Rostovtsev, V. Alternative heterocatenation strategies are i threading Siemsen, P. For the original report, see: b Eglinton, G. London , See: a Meissner, U. Synthesis, , The SO dianion is virtually nonnucleophilic, while the AcO- anion has strain in the cyclophane facilitates nucleophilic attack at the weak nucleophilic character which did not present a significant problem benzylic positions, displacing the positively charged bipyri- in our experiments.
Finally, basic conditions appear to be equally J. Tetrahedron of the benzylic methylene group leads to a number of rearranged Lett. Heath, J. Asian J. Ven, V. So, find out if they are still suitable to use on your next float fishing adventure. When it comes to floating fishing, you may also use a Feeder Rod. It ranges from around 9 to 12 feet. However, a Feeder Rod uses a bait on the bottom without using floats.
It is contrary to what a float fishing is supposed to be. So, using a Feeder Rod for float fishing is a matter of personal preference. In buying a Feeder Rod, there are some factors that you should consider to get the best bad for your buck. Moreover, proper handling and use are essential to get the best results in catching fish. So, if you have plans on using Feeder Rods on your next angling trip, you must check these tips first.
Feeder Fishing Rods are notable for their quiver tips. They use baits on the bottom, which makes them ideal for carp fishing.
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