AMAZON multi-meters discounts AMAZON oscilloscope discounts
5. OPERATING MECHANISMS
5.1 Closing and Opening
Off-load or off-circuit disconnectors and associated earthing switches may be hand-operated or motor driven through mechanical linkages with the required mechanical advantage to ensure satisfactory operation.
For circuit breakers it is essential to use a more positive operating mechanism that does not rely upon operator strength or technique. Manual or motor-driven operating mechanisms which compress a spring for energy storage are used at medium voltages for bulk oil, SOV and SF6 switchgear.
Vacuum switchgear generally needs lower energy mechanisms for the smaller travel distances involved. The sizing of the DC supply necessary to control an MV switchboard is described in Section 4.
At higher voltage and short circuit levels pneumatic- or hydraulic-driven mechanisms are used to provide the necessary power to overcome the circuit breaker operating restraining forces. Individual supply systems involve independent hydraulic or compressed air installations in each circuit breaker.
Spring operating mechanisms are also available to the highest voltages, normally single pole design mechanisms, one per phase.
Group systems are often specified to feed a group of air blast circuit breakers from the same (usually duplicated) compressed air source. The schematic for a decentralized compressed air group supply system is shown in FIG. 19. The air receivers should be equipped with renewable type air filters, safety valves, and blow down valves. Air driers may be used but are not always necessary, depending on the pressure reduction ratio and the ambient temperature variation. Compressed air should be fed in to the HP storage tanks at the bottom of the tank and extracted from the top. The air in the tanks will always be 100% humid and the system should be designed to allow water droplets in the air to settle to the bottom of the tank before use.
The pressure reduction will dry the air sufficiently for use in the breaker. A lock-out feature should be incorporated into the design such that if air pres sure in the receiver falls below that suitable for reliable circuit breaker operation closing or opening is prevented and an alarm raised. The design capacity of such a plant is based on the number of circuit breakers in the group, the number of realistic switching cycles being considered (usually based on three complete close and trip operations unless there is an auto reclose requirement), the air quantity used by the circuit breaker mechanism and arc extinction process together with an estimate for pipeline and circuit breaker system leakage losses. It is important to consider the necessity of good compressed air system maintenance. The author has visited several compressed air installations in developing countries where compressors are continually running until failure occurs because of excessive leakages due to a lack of spare parts.
The closing spring type of mechanism is specified for automatic spring recompression after each circuit breaker closing operation. It is therefore immediately available for the next time it is required. Should the motor drive supply fail, a handle is supplied with the switchgear so that the spring mechanism may be charged by hand. The closing spring may be released either locally by a hand-operated latch or remotely via an electromagnetic latch powered from a reliable AC or DC supply used during the closing action.
The opening spring is normally arranged to be charged during the closing operation. In this way the breaker is always ready for circuit breaking duties even under auxiliary supply failure. FIG. 20 shows the closing and opening spring mechanisms on a YSF type Yorkshire Switchgear SF6, 24 kV, 400 A circuit breaker. The meter shown in the photograph is monitoring the SF6 gas pressure. The opening spring is automatically unlatched by an indirect shunt trip coil which is in turn energized via the circuit breaker protection scheme. Built-in direct release schemes are also found on LVAC air circuit breakers.
FIG. 19 Schematic showing decentralized, duplicated compressed air installation
feeding a set of four air blast circuit breakers.
[Isolation valve Pressure-reducing valve Pressure-relief valve]
FIG. 20 24 kV, 400 A SF6 circuit breaker operating mechanism (courtesy
of Yorkshire Switchgear).
5.2 Interlocking
Since disconnectors must not be operated on load, interlocks between circuit breakers and the associated disconnectors must be incorporated into the over all substation design. For example, disconnectors should be so interlocked that they cannot be operated unless the associated circuit breaker is open. In a duplicate busbar system the interlocking must prevent the simultaneous closing of two busbar disconnectors unless the busbars are already electrically connected through the bus coupler disconnectors and associated bus coupler circuit breaker (if installed). Similarly, circuit breakers must be interlocked so that except under maintenance conditions it is not possible to close the breaker unless the selected busbar and circuit disconnectors are already closed. Such interlocks ensure safe operation of equipment under all service conditions by detecting and logically processing the switching status of all the switchgear involved. Interlocking may be achieved by the use of mechanical key exchange box or linkage systems which enforce the correct sequence of switching operations. Alternatively, electromagnetic bolt systems may be employed which inhibit disconnector movement. Electrical interlocks should function so as to interrupt the operating supply.
For withdrawable switchgear such interlocks would involve:
1. The circuit breaker cannot be inserted into the switchgear cubicle housing unless the 'isolated' position has been selected.
2. The circuit breaker cannot be closed unless it is in the fully 'engaged' or 'isolated' position.
3. The circuit breaker assembly cannot be coupled to or decoupled from the cubicle busbar and feeder circuits unless it is in the 'open' position.
4. The circuit breaker cannot be inserted into any position other than that selected on the selector mechanism (busbar earth, feeder earth, normal service).
5. The busbar shutters.
FIG. 21a Cross section through an 11 kV, 400 A vertical isolator, horizontal
withdrawal circuit breaker. The circuit breaker carriage is shown for connection
between the circuit and busbars. The carriage may be moved to different
positions for the integral earthing through the circuit breaker of either
the circuit or busbars.
FIG. 21b Cross section through a 24 kV 1250 A non-withdrawable SF6 circuit
breaker, with SF6 insulated busbars and integral earthing switch (courtesy
of ABB).
[
1. Density sensor
2. Circuit-breaker operating mechanism
3. Multifunction protection and switchgear control unit
REG542 plus
4. 3-position switch operating mechanism
5. 3-position switch
6. Busbar
7. Pressure relief disk
8. Pressure relief duct (optional)
9. Ring type current transformer
10. Cable plug
11. Cable socket
12. Measuring sockets for capacitive voltage indicator system
Test socket
14. Circuit breaker
SF6 gas
]
5.3 Integral Earthing
A useful maintenance feature for indoor MV withdrawable switchgear is to use the circuit breaker switch itself to earth either the circuit or busbars. The switch may be moved into different positions within the cubicle to achieve this as shown in FIG. 21a. An alternative to this, used by most European manufacturers in both withdrawable and fixed breaker design switchgear, is to use fixed fault making earthing switches mounted in the cubicles, as illustrated in FIG. 21b. This ABB switchgear incorporates the REF542plus control unit, which not only provides inbuilt solid-state system protection (overcurrent, earth fault and distance protection, if required) but also a programmable logic to prevent switch maloperation. Mechanical interlocking is available as an option, and some utilities still prefer this, in view of the difficulty of ensuring compliance with IEC 61508.
6. EQUIPMENT SPECIFICATIONS
6.1 12 kV Metal-clad Indoor Switchboard Example
6.1.1 Scope of the Work
This is a practical example of MV switchboard definition. Drawing 16218 10-EE0001 ( FIG. 22) is the key 132/11 kV system single line diagram.
The work involves connecting a large pharmaceutical production complex, with its own combined heat and power (CHP) generation, into the electrical supply utility 132 kV grid system. The total work for this project involves double circuit overhead line tee connections and a small two transformer 132/11 kV substation. The substation includes the design, supply installation, testing and commissioning of a new 11 kV, 9 panel switchboard which is covered in this example.
6.1.2 System Parameters
In order to specify the equipment correctly it is first essential to determine and accurately define the environmental and electrical system requirements.
These are detailed in Tables 11 and 12 with appropriate explanations.
Note that it is very important to consider standardization issues when defining parameters for new equipment. For example the 30 V DC tripping supply meets with that already used elsewhere on the large pharmaceutical site by the purchaser. In a similar way there are great advantages in using similar switchgear, relays, etc. in order to minimize spares holdings and ensure maintenance crews are not confronted with a wide variety of equipment.
6.1.3 Fault Level and Current Ratings
Maximum and minimum fault level at the interconnection point should be specified in writing by the electrical supply utility. Even without this information the high impedance (30%) 132/11 kV transformer impedance will greatly reduce the fault contribution from the electrical supply utility.
Assuming a negligible source impedance the fault level, FMVA on the 132/ 11 kV transformer secondary side on a 100 MVA base will be:
FMVA 5 1003S Z% where S5MVA rating of equipment FMVA 5three phase fault level in MVA on the secondary side of one transformer
FIG. 22 12 kV metal-clad indoor switchgear example single line diagram.
TABLE 11 Climatic Conditions [coming soon]
TABLE 12 Electrical System Parameters [coming soon]
Z%=% impedance expressed as a percentage at a stated MVA rating S%
FMVA = 100x30 MVA/30 %
=100 MVA
For two transformers in parallel the effective fault limiting impedance halves and the maximum possible fault level contribution from the electrical supply utility becomes 200 MVA=200 / __/3 * 11 kA=10.5 kA.
In addition to this the local generation contribution must be added.
Further, since this is a large industrial complex with many induction motors the short-term motor contribution must also be considered. A full study using computer analysis typically as described in Section 1 is worthwhile and gives an 11 kV switchboard fault level of 360 MVA or approximately 19 kA under maximum generation and electrical supply utility fault contribution conditions. In accordance with Tables 3 and 4 and allowing for some possible future fault level increases a standard switchboard-rated short circuit breaking current of 25 kA is selected.
The current rating of the incoming circuit breakers and busbars is matched to the transformer full load current with an allowance for possible future short-term overload. For the particular type of switchgear that the purchaser wishes to use, a 2,000 A busbar is available as a manufacturer's standard and is therefore specified. Ring feeder and interconnector circuit breaker current ratings are derived from requirements and load growth projections covered by system studies. The next greater standard rating is then specified.
6.1.4 General Requirements
TABLE 13a may now be completed as shown. The IP 34 enclosure rating is a manufacturer's normal protection and perfectly adequate for an indoor installation. The local controls are specified after discussion with the purchaser's maintenance and engineering staff.
6.1.5 Particular Requirements
After the system studies mentioned in SEC. 6.1.3, the Protection, Instrumentation and Metering Drawing 16218-10-EE-0003 ( FIG. 24) is prepared using the standard symbols shown in Drawing 16218-10-EE-0002 ( FIG. 23). The switchboard uses a relatively complex protection scheme which arises from the local generation and interconnection to the grid.
Another point of interest in this example is the use of Is limiters (see Section 11). The pharmaceutical complex has existing, older, 11 kV, 250 MVA fault-rated switchgear. Since the interconnection to the Grid increases the fault level to approximately 360 MVA this older switchgear must be protected or replaced. The use of the Is limiters (items IS1 and IS2 on drawing 16218-10-EE-0001) avoids expensive switchgear replacement costs. The switchgear particular technical requirements may then be tabulated and clearly defined as shown in TABLE 13b. Items such as cable termination detail spare parts and special tools should not be left to chance and may be specified and ordered with the switchgear.
TABLE 13a Typical MV Switchgear Accessories Enquiry Data Sheet General Requirements [coming soon]
During an open competitive enquiry for such switchgear a technical specification should accompany the tables and drawings of general and particular requirements. Such a specification would give background details to the manufacturer (site location, access and temporary storage facilities) and also request details on particular switchgear mounting arrangements, whether metal-enclosed/metal-clad equipment is required, any particular results arising from the system studies, the factory test requirements, etc. A useful proforma and checklist covering indoor switchgear is given in TABLE 14, Parts A and B.
6.2 Open Terminal 145 kV Switchgear Examples
6.2.1 System Analysis
It is essential to involve an element of system analysis performed by senior and experienced systems engineers before switchgear at the higher voltage levels can be correctly specified. This will need particularly to take into account the network earthing, any likely switching overvoltages and also to give more general attention to insulation co-ordination. This is particularly important when specifying ZnO surge arresters and insulation levels associated with GIS. The number of outage conditions to be considered makes computer-assisted load flow and fault level system analysis (also if applicable harmonic checks) almost essential. However, the simple sums explained in Sections 1 and 25 and in other Sections throughout this book are still important and may be used as a guide as to the order of magnitude expected from the computer generated results.
The earthing arrangements used throughout the network and values of positive, negative and zero sequence impedances will determine the ratio of fault current to three phase fault current. In highly interconnected solidly earthed systems the ratio of Z0/Z1 may be less than unity. The three phase symmetrical earth fault level may not therefore be the worst case fault condition. The ratio Z0/Z1 is therefore a measure of the 'effectiveness' of the sys tem earthing and may also vary over the system. For the calculation of modern circuit breaker breaking currents it is worthwhile taking the sub-transient values of generator reactance into account. For older oil circuit breakers and when determining the minimum currents available to operate protection relays it is more usual to consider transient reactances since the sub-transient reactance effects usually disappear before oil circuit breakers have operated.
When determining the circuit breaker making currents or the maximum through-fault current for protection purposes the sub-transient reactance values should be used. The mechanical forces associated with short circuits increase with the square of the current. In practice, most computer programs now allow both transient and sub-transient values to be entered. One should not get carried away with the idea that all the available computing power will in any way improve results since the raw input data may only be best estimates in the first place.
FIG. 25 shows a hand calculation of peak symmetrical fault current, peak asymmetrical fault current and maximum short circuit current based on contributions from the electrical supply utility grid, local generation and local industrial plant motors to determine the switchboard fault levels.
TABLE 13b Typical MV Switchgear Accessories Enquiry Data Sheet Particular Requirements [coming soon]
FIG. 23 12 kV metal-clad interior switchgear example symbols.
TABLE 14 Indoor Metal-enclosed/Metal-clad Switchgear Technical Particulars and Guarantees [coming soon]
6.2.2 Technical Particulars and Guarantees
FIG. 25 Hand calculation of peak symmetrical fault current, peak asymmetrical fault current and maximum short circuit current levels.
TABLE 15 Open Terminal Circuit Breaker Technical Particulars and Guarantees Checklist [coming soon]
Tables 15 and 16 are proforma checklists based on IEC 62271-100 and IEC 60044 for use when specifying open terminal circuit breakers and pedestal mounted CTs. They cover the items described in this Section, Sections 5 and 19. Note the special cases for rated out-of-phase breaking current, rated cable charging breaking current, rated capacitor breaking current and rated small inductive breaking current have all been included in the circuit breaker checklist. Since the manufacturer will match one of his standard items of equipment to the specification it is worth noting the statistics associated with different circuit breaker failure modes. When checking tenders it is important to give these areas emphasis and to seek advice from other users of the same switchgear.
TABLE 16 MV Circuit Breaker Failure Mode Statistics [coming soon]
6.3 Distribution System Switchgear Example
An MV fused contactor may be used to protect and control the switching of an MV/LV (6.6./0.38 kV) distribution transformer. This is a feasible and less expensive option than using a circuit breaker at this voltage level. The HRC fuse limits the prospective short circuit current and therefore the severity of the fault. Note that, as explained in Fig. 4.6 ( Section 4), the standby earth fault (SBEF) CT is located in the earth connection of the star point of the LV (low voltage, 0.38 kV) transformer winding. This is connected to an earth fault relay arranged to trip the contactor. The design takes advantage of the maximum LV fault current, when referred to the HV (high voltage, 6.6 kV) side of the transformer, being well within the interrupting capability of the contactor.
This is a result of the fault limiting effect of the transformer impedance.
A star point CT and earth fault relay are used because faults in the transformer LV winding and LV switchboard most often occur initially as earth faults. This is especially so in the case of LV switchboards with all insulated busbars. The SBEF relay is sensitive to the detection of earth faults well down into the LV transformer winding.
The 6.6 kV fuses provide effective protection against phase-to-phase and phase-to-earth faults occurring on the 6.6 kV HV side of the transformer.
The fuses also give 'coarse' protection against faults on the LV side of the transformer. Striker pins should be specified on the fuses in an arrangement whereby they initiate a contactor trip of all three phases.
Careful co-ordination of the protection characteristics of the HV fuses, LV SBEF and LV switchboard outgoing circuit protection is necessary in order to ensure correct protection discrimination. In this example an extremely inverse IDMTL relay characteristic has been used to grade best with the HV transformer and LV switchboard fuse characteristics. Allowances must be made for the permissible tolerances in the operating characteristics of the fuses and relay and for the contactor tripping time.
The contactor should be specified as the latched type in order to ensure that it remains closed under conditions of system disturbances. The overall installation will therefore involve the specification of a suitable auxiliary DC supply (see Section 4).
The 0.38 kV switchboard has fuse switch units. MCBs could be specified after careful assessment of the required switching capability under short circuit conditions, their compatibility in the overall protection setting co-ordination, and whether they are required repeatedly to break short circuits without replacement (see IEC 60947-2). The larger outgoing circuits, other than motor circuits, must be provided with a means to detect earth faults and to switch off selectively.
FIG. 26 Ring main unit schematic.
FIG. 27 Type HFAU oil-filled switch fuse (above) and SF6 ring main unit
(below).
6.4 Distribution Ring Main Unit
Three phase low voltage (B400 V) supplies for domestic consumers are normally derived from distribution transformers (B100 1,000 kVA rating) which are fed via medium voltage (12 or 24 kV) ring main circuits from primary substations. The supply to the high-voltage side of the distribution transformer must be arranged:
- to give adequate protection;
- to cater for normal operational switching;
- to provide switching facilities to isolate faulty parts of the circuit and to allow normal maintenance, replacements, extensions and testing.
In order to meet these requirements it is usual to fit switches at each transformer tee-off point on the MV ring. Savings can be made by utilizing fault-make/load break ring main switches rather than circuit breakers in these positions, although this option is not applicable in high security networks where each cable section has unit protection. The transformer may be protected by a switch fuse, circuit breaker or contactor depending upon the protection philosophy adopted by the electricity supply utility. The arrangement is shown in Figs. 26 and 27.
The fundamental requirements of the ring main unit are as follows:
1. Ring main switches
- continuously carry ring full load current;
- make and break ring full load current;
_ carry the full system fault current for a 1 or 3 s design criteria;
- make onto a full system fault current.
2. Tee-off switches
_ continuously carry tee-off circuit full load current;
- make and break full load current of the tee-off circuit (including magnetizing inrush currents, motor starting overloads, etc.);
- make and break the full system fault current.
3. Environment
- The ring main units must be designed to match the environmental and any special pollution requirements. Often in the UK the units are out door types. On the continent such units are more often enclosed in packaged substation housings.
4. Impulse levels
- Normally an impulse level of 75 kV is sufficient. When connected to overhead line distribution circuits an impulse level of 95 kV may be specified depending upon impulse co-ordination design.
5. Insulation and earthing
- air, oil, SF6 or vacuum insulation may be adopted;
- in practice it is necessary to ensure that if fuses are used for trans former tee-off protection they are easily accessible for replacement;
- fuse access must only be possible after each side of the fuse has been isolated from the busbars and transformer;
- in addition, an auxiliary earth must also be applied to both sides of the fuse in order to discharge any static which may have built up on the fuse connections before any maintenance takes place;
- fuse changing must be arranged to be quick and simple and capable of being performed in all weathers even if the ring main unit is of the outdoor type.
6. Test facilities and interlocks
- provision should be made for access to the ring main cable terminations for test purposes;
- suitable interlocks and labeling must be incorporated to prevent maloperation.
7. Extensibility
- When required and specified the designs should allow for future extensions to the busbars.
It should be noted, however, that such extensibility is not a normal feature and unless specified at the outset a separate RMU switchboard will be required for any extra switches needed in the future.
8. Maintenance
- For maintenance the whole unit has to be shut down in one go, including incoming cables. In contrast a circuit breaker switchboard can have its individual breakers maintained on a circuit by circuit basis.
FIG. 27 shows a cutaway view of a typical switch fuse unit of which many thousands have been installed throughout the world with a very high reliability record. More modern SF6 insulated units follow the same layout principles. Heat shrink terminations would normally be used with XLPE cables.