RECLOSER OF POWER SYSTEM CIRCUITS BASIC INFORMATION

What Are Reclosers? What Is Its Purpose and How Recloser Works?

The increasing electrical loads on distribution lines caused by increasing demand, particularly in the suburbs, have caused utilities to raise their operating voltages. Voltages are now being distributed at 13.8, 23, and 34.5 kV and higher .

This higher voltage has led to the formation of smaller service regions or more sectionalizing to\ minimize the impact of an electrical outage in parts of each region. Ironically, the probability of fault occurrence has increased as operating voltages have increased because of the combination of higher voltages and longer distribution lines.

These have made the lines more susceptible to outages on lower-voltage, shorter lines because of the higher probability of transformer bushing flashovers, falling tree limbs, lightning strikes, and other causes.

Early in the last century conventional disconnect switches met the requirements for sectionalizing, but this is no longer true. The switching capability of a disconnect, while marginal at 2.4 to 4.8 kV, is completely inadequate at 13.8 kV and higher.

To isolate a section of distribution line by opening a disconnect, the entire feeder must first be dropped, and this adds to the extent of the outage. Moreover, during emergency conditions the probability of the occurrence of a disconnect caused by operator error increases proportionally.

Many different kinds of switches are now available to meet a wide variety of applications economically. The single-pole switch and side-break switch are intended for pole-top installation on distribution feeders, while the vertical-break switch was designed for distribution substations or feeders.

These switches perform all of their switching duties without causing external arcing, and they also provide the reliable isolation of a visible air gap. A few examples of their versatility and use are the following.

# During emergency situations requiring fast response, a modern interrupter switch can drop the load without complicated circuit breaker and switch sequencing.

# There is no need to drop individual loads because the switch can drop the entire load.

# Lines can be extended and additional load accommodated (within the rating of the switch) without affecting switching ability.

# A loaded circuit can be dropped inadvertently (through an error or misunderstanding) with no hazard to the operator or to the system.

# Interlocking is not required between the primary switch and the secondary breaker in transformer operation.

Because of the no-external-arc feature of most modern interrupter switches, phase conductor spacing can be much less than that established for the older horn-gap switch. On the secondary side of the substation there are more feeders and more heavily loaded and longer transmission lines.

TYPES OF POWER SYSTEM CIRCUIT BREAKERS BASIC INFORMATION

The five general types of high-voltage circuit breakers are as follows.

1 Oil circuit breakers use standard transformer oil, an effective medium for quenching the arc and providing an open break after current has dropped to zero. There are two general types of oil circuit breakers: dead-tank for the higher voltage ranges and live-tank for lower voltages.

Oil circuit breakers have been improved by adding such features as oil-tight joints, vents, and separate chambers to prevent the escape of oil. Also, improved operating mechanisms prevent gas pressure from reclosing the contacts, making them reliable for system voltages up to 362 kV.

However, above 230 kV, oil-less breakers are more economical.

2 Air-blast circuit breakers were developed as alternatives to oil circuit breakers as voltages increased. They depend on the good insulating and arc-quenching properties of dry and clean compressed air injected into the contact region.

3 Magnetic-air circuit breakers use a combination of strong magnetic field with a special arc chute to lengthen the arc until the system voltage is unable to maintain the arc any longer. They are used principally in power distribution systems.

4 Gas circuit breakers take advantage of the excellent arc-quenching and insulating properties of sulfur hexafluoride (SF6) gas. These outdoor breakers can interrupt system voltages up to 800 kV.

These circuit breakers are typically included in gas insulated substations (GISs) that offer space-saving and environmental advantages over conventional outdoor substations. Gas (SF6) circuit breakers are made with ratings up to 800 kV and continuous cur rent up to 4000 A.

They are alternatives to oil and vacuum breakers for metal-clad and metal-enclosed switchgear up to 38 kV.

5 Vacuum circuit breakers, more accurately termed vacuum-bottle interrupters, are generally used for voltages up to 38 kV and continuous current ratings to 3000 A. They are used for higher system voltage, current, and interrupting ratings, and are typically specified for metal-clad and metal-enclosed switchgear in distribution systems.

EQUIPMENT AND TOOL REQUIREMENTS IN GAS INSULATED SUBSTATION CONSTRUCTION BASIC INFORMATION AND TUTORIALS

Cranes or hoists having adequate lifting capacities should be available for handling material during installation. Nylon web slings provide an ideal means for lifting equipment without damaging it.

Gas is handled through commercially available gas-processing trailers that contain vacuum pumping equipment, gas storage tanks, compressors, filters, and dryers. The size of the individual gas compartments and the evacuating and storage capacity of the gas-handling equipment is especially important in large stations.

Suitable evacuating equipment and a heat source to counteract the chilling effect of the expanding gas may permit filling directly from gas cylinders or gas-handling equipment. High-voltage test equipment is required for checking the quality of the insulation after installation.

Adapters for high voltage testing may be required. These include a suitable entrance bushing for connecting the high voltage to the gas insulated conductor and a termination for closing off the end of the equipment when the entire assembly has not been completed. In many cases, it may be possible to use an entrance bushing that is a part of the installation.

When tools and alignment templates not readily available on the open market are required for installation and maintenance of the equipment, one set should be furnished, by the supplier, with the equipment when it is delivered.

The following materials should be on hand before the bus is opened:

a) Gas-processing equipment with adequate storage capacity

b) Electrolytic or electronic hygrometer or comparable equipment for measuring moisture levels

c) Insulating gas leak detector (Where double “O” rings are used, a manometer can sometimes be connected at the sensing hole to measure any increase in pressure between the “O” rings. Commercial high-viscosity, noncorrosive solutions may be used to locate larger leaks at a sensing hole, at welds, or at bolted flanges.)

d) Dry air

e) Clean plastic gloves and work uniforms

f) Lint-free cloths and manufacturer-recommended solvents

g) Temporary plastic bags or covers for sealing openings after components have been removed

h) Commercial-type vacuum cleaner with high efficiency particulate air (HEPA) filters and nonmetallic

accessories

i) Tools supplied and recommended by the manufacturer

j) Ventilating equipment

k) Handling and lifting equipment

l) Maintenance manual and erection drawings

m) Ladders and platforms as required

PARTS OF CIRCUIT SWITCHER AND ITS GENERAL CONSTRUCTION BASIC INFORMATION AND TUTORIALS

Live-tank SF6 gas puffer-type interrupters are utilized by most circuit switchers today. In the closed position, the contacts are surrounded by a flow guide and piston assembly which is ready to mechanically generate a “puff” of SF6 to cool and deionize the arc that is established prior to circuit interruption.

The moving cylinder attached to the contact assembly is driven by the main opening spring, causing the gas to be pressurized by the stationary piston. The stationary contact “follows” the moving contact as the piston assembly achieves the prepressurized gas condition.

When the contacts (which are hollow tubes) part, an arc is established and the gas flow divides into two parts and flows down the stationary and moving contact tubes. The alternating nature of the arc current waveform results in two current zeros every cycle. As long as the arc is sufficiently “hot” or conductive through the SF6 dielectric medium, the current will reestablish.

At the first current zero where the SF6 density is sufficient to stop the arc from reestablishing itself and to provide necessary dielectric strength, the arc is interrupted. This entire process from trip signal initiation to current interruption requires from 3 to 8 cycles or 50 to 133 ms in modern circuit switchers.

Figure above illustrates a typical “blade-disconnect model” circuit switcher with the interrupter and blade connected in series. For opening, the trip device, called a “shunt trip,” receives a trip signal when the relay system detects an abnormal condition within the specified range or when the operator desires a high-speed circuit opening. By discharging its operating spring, the shunt trip rotates the insulator above it at high speed, thus tripping and discharging the opening spring in the driver mechanism.

This actuates the interrupter to open the circuit. If the insulator above the shunt trip continues to rotate, by motor or manual actuation of the drive train controls, the blade opens to achieve visible isolation. The blade-hinge mechanism is actuated directly by the rotating insulator through the driver mechanism.

Continued rotation of the insulator after the blade is open will “toggle” the drive train controls to lock the blade in its open position. For closing, the reverse rotation of the insulator first releases drive train toggle and allows the blade to begin closing.

The shunt-trip units have already recharged during the opening operation. As the blade closes, the closing springs are charged in the driver. The last few degrees of closing rotation lock the blade in position and release the closing springs in the driver, thus closing the interrupter.

The opening springs are charged as the closing springs discharge. If the unit has closed into a circuit condition that provides a trip signal to the shunt trip units, the opening process may immediately proceed since all springs are charged and all controls are ready.

The closing operation may be achieved in other designs by closing the interrupter during the opening stroke of the blade. When a close operation is called for, all that is necessary is to close the blade, because the interrupter is already closed. Because of the arc established in air for this type of closing, high-speed operation of the blade is necessary to minimize damage to contacts and prevent flashovers.

Both methods of closing are proven over many years of field use. Bladeless circuit switchers operate exactly the same as blade models, except that on opening, the insulator rotation is used only for driver and interrupter actuation. Models that depend on high-speed blade operation for closing are available in bladeless nondisconnect configuration, but circuit closing must be accomplished by other means.

For models without shunt trip, opening is accomplished by rotating the insulator to the point where the driver opening spring would normally be tripped by the shunt trip’s rotation. This configuration is used where protection duty is not a function of the circuit switcher.

CIRCUIT SWITCHERS BASIC INFORMATION AND TUTORIALS

What Are Circuit Switchers?

Circuit switchers are mechanical switching devices suitable for frequent operation; not necessarily capable of high-speed reclosing; capable of making, carrying, and breaking currents under normal circuit conditions; capable of making, and carrying for a specified time, currents under specified abnormal conditions; and capable of breaking currents under certain other specified abnormal circuit conditions.

They may include an integral isolating device. Circuit switchers available today use SF6 as an interrupting medium and may be equipped with a trip device connected to a relay to open the circuit switcher automatically under specified abnormal conditions, such as overcurrent or faults.

A circuit switcher, like a circuit breaker, must carry normal load currents within a specified temperature range to prevent damage to key components such as contacts, linkage, terminals, and isolating device parts.

Principal designating parameters of a circuit switcher are maximum operating voltage, BIL, rated load current, interrupting current, whether an isolator is required, whether a trip device is required, and whether manual or motorized operation is required.

A circuit switcher essentially combines the functions of a circuit breaker (without reclosing capability) and a disconnecting switch (by providing visible isolation, but not necessarily meeting the safety requirements of all users).

A circuit switcher provides a cost-effective alternative means of transformer protection and switching, line and loop switching, capacitor or reactor switching, and load management, with protection in most instances.

Evolution of the circuit switcher concept provides a more in-depth understanding of its application versatility and its limitations.

History of Circuit-Switcher Development

After World War II, the drive to electrify the remaining rural and sparsely populated areas of the United States was renewed. Providing fully rated circuit breakers for switching loaded circuits was frequently beyond budget limitations. This created a need for new transmission and subtransmission voltage circuit-switching devices.

One such device could be described as a load interrupter. It appeared in a wide variety of forms. Most were attachments to disconnect switches.

Initially, most of these devices used low-volume oil as an interrupting medium. Ablative gas generating devices and later vacuum displaced oil. With rare exceptions, these devices had deficiencies. In the mid-1950s, SF6 was first employed as an interrupting medium. The application was an interrupter attachment for disconnect switches.

Whereas ablative devices and vacuum bottles are limited to approximately 30-kV recovery voltage per gap, this single-gap SF6 device was readily applied on 138-kV systems for up to 600 A load switching.

Most of these vacuum, ablative, and SF6 devices were shunted into the circuit during the disconnect switch opening process. As the 1960s approached, the circuit switcher was born. It appeared as an in line device. While the first version employed a number of ablative devices in series, it soon evolved into the use of SF6 as a medium.

Because of the unfavorable experience with the earlier devices, the general acceptance of the circuit switcher took much effort and considerable time. A typical installation is shown below.

Applications for circuit switchers have been primarily for transformer protection. The circuit switcher provides load-switching capability and mainly protection for faults that originate on the secondary side of the substation transformer.

The zone of protection for circuit switchers in this location is typically from the current transformers inside the transformer on the high-voltage bushings to the secondary feeder breakers. There is generally shorter strike distance on the secondary bus and more exposure to flashover from wildlife and other causes.

Therefore, circuit switchers are specifically tested to interrupt the higher transient recovery voltages (TRVs) associated with faults initiated on the secondary of the transformer and cleared by the high-side protective device. For application where the available high-side short-circuit current exceeds the device’s capability, blocking relays can be used. However, in most applications this is not necessary.

AUTOMATED SWITCHES USED IN POWER SYSTEM BASIC INFORMATION AND TUTORIALS

A key part of an automated feeder switching system is the automated switch. The term “automated” in this context means the switch is designed for use on an automated or SCADA system.

In order to be automated, existing switches may be retrofitted with motor operators, current and voltage sensors, RTUs and communication devices to allow the remote operation necessary to realize the benefits available with automated feeder switching systems.

However, switches designed for occasional, manual operation may not be entirely suitable for operation on an automated distribution circuit feeder. Manual switches are typically not designed to be operated the hundreds of times required by a fully automated system over the life of a typical switch.

Nor are they ordinarily designed for duty cycle fault-closing to allow the system operator to inadvertently close into a fault from the SCADA master station—and still leave the switch in an operable condition.

More recently, switches designed specifically for automation have appeared in the market like the one below.

Such switches incorporate design features that make them particularly applicable for use in an automated feeder switching system:

1. Duty-cycle fault-closing allows the switch to be closed into a typical fault several times before experiencing damage severe enough to render the switch inoperable.

2. Integrated voltage and current sensors provide the ability to monitor voltages, currents, and loads that are in turn used as inputs to algorithms to effect automated switching for fault isolation and restoration and for shifting loads for circuit optimization.

3. Integrated operating mechanisms enable the switches to be operated remotely via computer commands. Integration with the switch ensures optimum operation without the need for cumbersome ground-to-switch linkages.

4. Integrated load interrupters should be designed to allow operation under any weather conditions since it will not be possible to visibly inspect the switch for ice or other problems prior to operation.

5. Integrated control power sources eliminate the need to rely on locally available control power sources—or to install such power sources.

6. Integrated visible air-gap isolation provides the visible air gap when needed for certain types of line work.

In addition, an associated control package should include switch-operating controls, a local/remote switch, backup power for dead-line SCADA operation, a remote-terminal unit, and data communication devices. The entire package should be assembled and tested for proper operation by a single supplier to eliminate the need for the utility to perform the integration.

The control box should be separately located from the switch to allow access by technicians who are not qualified in high-voltage operations. In underground switchgear applications, the control should be isolated from the high-voltage compartments of the switchgear.

ADVANTAGES AND DISADVANTAGES OF DIFFERENT SUBSTATION SCHEMES COMPARISON OF CONFIGURATIONS

Below is a summary of comparison of switching schemes for substations.

A. SINGLE BUS SCHEME

Advantages

1. Lowest cost.

Disadvantages

1. Failure of bus or any circuit breaker results in shutdown of entire substation.

2. Difficult to do any maintenance.

3. Bus cannot be extended without completely deenergizing substation.

4. Can be used only where loads can be interrupted or have other supply arrangements.

B. DOUBLE BUS DOUBLE BREAKER SCHEME

Advantages

1. Each circuit has two dedicated breakers.

2. Has flexibility in permitting feeder circuits to be connected to either bus.

3. Any breaker can be taken out of service for maintenance.

4. High reliability.

Disadvantages

1. Most expensive.

2. Would lose half of the circuits for breaker failure if circuits are not connected to both buses.

C. MAIN AND TRANSFER BUS SCHEME

Advantages

1. Low initial and ultimate cost.

2. Any breaker can be taken out of service for maintenance.

3. Potential devices may be used on the main bus for relaying.

Disadvantages

1. Requires one extra breaker for the bus tie.

2. Switching is somewhat complicated when maintaining a breaker.

3. Failure of bus or any circuit breaker results in shutdown of entire substation.

D. DOUBLE BUS, SINGLE BREAKER SCHEME

Advantages

1. Permits some flexibility with two operating buses.

2. Either main bus may be isolated for maintenance.

3. Circuit can be transferred readily from one bus to the other by use of bus-tie breaker and bus selector disconnect switches.

Disadvantages

1. One extra breaker is required for the bus tie.

2. Four switches are required per circuit.

3. Bus protection scheme may cause loss of substation when it operates if all circuits are connected to that bus.

4. High exposure to bus faults.

5. Line breaker failure takes all circuits connected to that bus out of service.

6. Bus-tie breaker failure takes entire substation out of service.

E. RING BUS SCHEME

Advantages

1. Low initial and ultimate cost.

2. Flexible operation for breaker maintenance.

3. Any breaker can be removed for maintenance without interrupting load.

4. Requires only one breaker per circuit.

5. Does not use main bus.

6. Each circuit is fed by two breakers.

7. All switching is done with breakers.

Disadvantages

1. If a fault occurs during a breaker maintenance period, the ring can be separated into two sections.

2. Automatic reclosing and protective relaying circuitry rather complex.

3. If a single set of relays is used, the circuit must be taken out of service to maintain the relays. (Common on all schemes.)

4. Requires potential devices on all circuits since there is no definite potential reference point. These devices may be required in all cases for synchronizing, live line, or voltage indication.

5. Breaker failure during a fault on one of the circuits causes loss of one additional circuit owing to operation of breaker-failure relaying.

F. BREAKER AND A HALF SCHEME

Advantages

1. Most flexible operation.

2. High reliability.

3. Breaker failure of bus side breakers removes only one circuit from service.

4. All switching is done with breakers.

5. Simple operation; no disconnect switching required for normal operation.

6. Either main bus can be taken out of service at any time for maintenance.

7. Bus failure does not remove any feeder circuits from service.

Disadvantages

1. 1 1/2 breakers per circuit.

2. Relaying and automatic reclosing are somewhat involved since the middle breaker must be responsive to either of its associated circuits.

BREAKER AND A HALF SUBSTATION SCHEME – BASIC INFORMATION AND TUTORIALS

The breaker-and-a-half scheme can be developed from a ring bus arrangement as the number of circuits increases. In this scheme, each circuit is between two circuit breakers, and there are two main buses.

The breaker-and-a half scheme, sometimes called the three-switch scheme, has three breakers in series between two main buses. Two circuits are connected between the three breakers, hence the term breaker and a half. This pattern is repeated along the main buses so that one and a half breakers are used for each circuit.

Under normal operating conditions, all breakers are closed, and both buses are energized. A circuit is tripped by opening the two associated circuit breakers. Tiebreaker failure will trip one additional circuit, but no additional circuit is lost if a line trip involves failure of a bus breaker.

  

Either bus may be taken out of service at any time with no loss of service. With sources connected opposite to loads, it is possible to operate with both buses out of service. Breaker maintenance can be done with no loss of service, no relay changes, and simple operation of the breaker disconnects.

The failure of a circuit will trip the two adjacent breakers and not interrupt any other circuit. With the three breaker arrangement for each bay, a center breaker failure will cause the loss of the two adjacent circuits.

However, a breaker failure of the breaker adjacent to the bus will only interrupt one circuit. Maintenance of a breaker on this scheme can be performed without an outage to any circuit.

Furthermore, either bus can be taken out of service with no interruption to the service. This is one of the most reliable arrangements, and it can continue to be expanded as required. Relaying is more involved than some schemes previously discussed. This scheme will require more area and is costly due to the additional components.

The breaker-and-a-half arrangement is more expensive than the other schemes, with the exception of the double breaker, double-bus scheme, and protective relaying and automatic reclosing schemes are more complex than for other schemes. However, the breaker-and-a half scheme is superior in flexibility, reliability, and safety.

RING BUS SUBSTATION SCHEME – BASIC INFORMATION AND TUTORIALS

In this scheme, as indicated by the name, all breakers are arranged in a ring with circuits tapped between breakers. For a failure on a circuit, the two adjacent breakers will trip without affecting the rest of the system.  

In the ring-bus scheme, the breakers are arranged in a ring with circuits connected between breakers. There are the same number of circuits as there are breakers.

During normal operation, all breakers are closed. For a circuit fault, two breakers are tripped, and in the event that one of the breakers fails to operate to clear the fault, an additional circuit will be tripped by operation of breaker-failure backup relays. During breaker maintenance, the ring is broken, but all lines remain in service.

Similarly, a single bus failure will only affect the adjacent breakers and allow the rest of the system to remain energized. However, a breaker failure or breakers that fail to trip will require adjacent breakers to be tripped to isolate the fault.

Maintenance on a circuit breaker in this scheme can be accomplished without interrupting any circuit, including the two circuits adjacent to the breaker being maintained. The breaker to be maintained is taken out of service by tripping the breaker, then opening its isolation switches.

Since the other breakers adjacent to the breaker being maintained are in service, they will continue to supply the circuits.

The circuits connected to the ring are arranged so that sources are alternated with loads. For an extended circuit outage, the line-disconnect switch may be opened, and the ring can be closed. No changes to protective relays are required for any of the various operating conditions or during maintenance.

In order to gain the highest reliability with a ring bus scheme, load and source circuits should be alternated when connecting to the scheme. Arranging the scheme in this manner will minimize the potential for the loss of the supply to the ring bus due to a breaker failure.

Relaying is more complex in this scheme than some previously identified. Since there is only one bus in this scheme, the area required to develop this scheme is less than some of the previously discussed schemes. However, expansion of a ring bus is limited, due to the practical arrangement of circuits.

The ring-bus scheme is relatively economical in cost, has good reliability, is flexible, and is normally considered suitable for important substations up to a limit of five circuits. Protective relaying and automatic reclosing are more complex than for previously described schemes.

It is common practice to build major substations initially as a ring bus; for more than five outgoing circuits, the ring bus is usually converted to the breaker-and-a-half scheme.  

DOUBLE BUS DOUBLE-BREAKER SUBSTATION SCHEME – BASIC INFORMATION AND TUTORIALS

Double Bus, Double Breaker.

The double bus, double breaker scheme requires two circuit breakers for each feeder circuit. Normally, each circuit is connected to both buses. In some cases, half the circuits operate on each bus.

This scheme provides a very high level of reliability by having two separate breakers available to each circuit. In addition, with two separate buses, failure of a single bus will not impact either line.

For these cases, a bus or breaker failure would cause loss of only half the circuits, which could be rapidly corrected through switching. The physical location of the two main buses must be selected in relation to each other to minimize the possibility of faults spreading to both buses.

The use of two breakers per circuit makes this scheme expensive; however, it does represent a high degree of reliability.

Maintenance of a bus or a circuit breaker in this arrangement can be accomplished without interrupting either of the circuits.

This arrangement allows various operating options as additional lines are added to the arrangement; loading on the system can be shifted by connecting lines to only one bus.

A double bus, double breaker scheme is a high-cost arrangement, since each line has two breakers and requires a larger area for the substation to accommodate the additional equipment. This is especially true in a low profile configuration.

The protection scheme is also more involved than a single bus scheme.

Below is the diagram of a double bus double breaker substation scheme:

DOUBLE BUS SINGLE-BREAKER SUBSTATION SCHEME – BASIC INFORMATION AND TUTORIALS

This scheme uses two main buses, and each circuit includes two bus selector disconnect switches. A bus-tie circuit connects to the two main buses and, when closed, allows transfer of a feeder from one bus to the other bus without deenergizing the feeder circuit by operating the bus selector disconnect switches.  

This arrangement allows the operation of the circuits from either bus. In this arrangement, a failure on one bus will not affect the other bus. However, a bus tie breaker failure will cause the outage of the entire system.

The circuits may all operate from either the no. 1 or no. 2 main bus, or half the circuits may be operated off either bus. In the first case, the station will be out of service for bus or breaker failure. In the second case, half the circuits will be lost for bus or breaker failure.

Operating the bus tie breaker in the normally open position defeats the advantages of the two main buses. It arranges the system into two single bus systems, which as described previously, has very low reliability.

Relay protection for this scheme can be complex, depending on the system requirements, flexibility, and needs. With two buses and a bus tie available, there is some ease in doing maintenance, but maintenance on line breakers and switches would still require outside the substation switching to avoid outages.

In some cases circuits operate from both the no. 1 and no. 2 bus, and the bus-tie breaker is normally operated closed. For this type of operation, a very selective bus-protective relaying scheme is required to prevent complete loss of the station for a fault on either bus.

Disconnect-switch operation becomes quite involved, with the possibility of operator error, injury, and possible outage. The double-bus, single-breaker scheme is relatively poor in reliability and is not normally used for important substations.

MAIN AND TRANSFER BUS SUBSTATION SCHEME – BASIC INFORMATION AND TUTORIALS

The main- and transfer-bus scheme adds a transfer bus to the single-bus scheme. An extra bus-tie circuit breaker is provided to tie the main and transfer buses together.

This scheme is arranged with all circuits connected between a main (operating) bus and a transfer bus (also referred to as an inspection bus). Some arrangements include a bus tie breaker that is connected between both buses with no circuits connected to it.

Since all circuits are connected to the single, main bus, reliability of this system is not very high. However, with the transfer bus available during maintenance, de-energizing of the circuit can be avoided. Some systems are operated with the transfer bus normally de-energized.

When a circuit breaker is removed from service for maintenance, the bus-tie circuit breaker is used to keep that circuit energized. Unless the protective relays are also transferred, the bus-tie relaying must be capable of protecting transmission lines or generation sources. This is considered rather unsatisfactory because relaying selectivity is poor.

A satisfactory alternative consists of connecting the line and bus relaying to current transformers located on the lines rather than on the breakers. For this arrangement, line and bus relaying need not be transferred when a circuit breaker is taken out of service for maintenance, with the bus-tie breaker used to keep the circuit energized.

When maintenance work is necessary, the transfer bus is energized by either closing the tie breaker, or when a tie breaker is not installed, closing the switches connected to the transfer bus. With these switches closed, the breaker to be maintained can be opened along with its isolation switches.

Then the breaker is taken out of service. The circuit breaker remaining in service will now be connected to both circuits through the transfer bus. This way, both circuits remain energized during maintenance.

Since each circuit may have a different circuit configuration, special relay settings may be used when operating in this abnormal arrangement. When a bus tie breaker is present, the bus tie breaker is the breaker used to replace the breaker being maintained, and the other breaker is not connected to the transfer bus.

A shortcoming of this scheme is that if the main bus is taken out of service, even though the circuits can remain energized through the transfer bus and its associated switches, there would be no relay protection for the circuits. Depending on the system arrangement, this concern can be minimized through the use of circuit protection devices (reclosure or fuses) on the lines outside the substation.

If the main bus is ever taken out of service for maintenance, no circuit breakers remain to protect

any of the feeder circuits. Failure of any breaker or failure of the main bus can cause complete loss

of service of the station.

Due to its relative complexity, disconnect-switch operation with the main- and transfer-bus

scheme can lead to operator error and a possible outage. Although this scheme is low in cost and

enjoys some popularity, it may not provide as high a degree of reliability and flexibility as required.

This arrangement is slightly more expensive than the single bus arrangement, but does provide more flexibility during maintenance. Protection of this scheme is similar to that of the single bus arrangement. The area required for a low profile substation with a main and transfer bus scheme is also greater than that of the single bus, due to the additional switches and bus.

TYPES OF SUBSTATION BUS SCHEMES BASIC INFORMATION AND TUTORIALS

Various factors affect the reliability of a substation or switchyard, one of which is the arrangement of the buses and switching devices. In addition to reliability, arrangement of the buses/switching devices will impact maintenance, protection, initial substation development, and cost.

The substation design or scheme selected determines the electrical and physical arrangement of the switching equipment.

Different bus schemes can be selected as emphasis is shifted between the factors of safety, reliability, economy, and simplicity dictated by the function and importance of the substation.

Some of these schemes may be modified by the addition of bus-tie breakers, bus sectionalizing devices, breaker bypass facilities, and extra transfer buses.

The substation bus schemes used most often are found below:

1. Single bus

2. Main and transfer bus

3. Double bus, single breaker

4. Double bus, double breaker

5. Ring bus

6. Breaker and a half

POWER SUBSTATION DESIGN CONSIDERATIONS BASIC AND TUTORIALS

Many factors influence the selection of the proper type of substation for a given application. This selection depends on such factors as voltage level, load capacity, environmental considerations, site space limitations, and transmission-line right-of-way requirements.

While also considering the cost of equipment, labor, and land, every effort must be made to select a substation type that will satisfy all requirements at minimum costs. The major substation costs are reflected in the number of power transformers, circuit breakers, and disconnecting switches and their associated structures and foundations.

Therefore, the bus layout and switching arrangement selected will determine the number of the devices that are required and in turn the overall cost. The choice of insulation levels and coordination practices also affects cost, especially at EHV. A drop of one level in basic insulation level (BIL) can reduce the cost of major electrical equipment by thousands of dollars.

A careful analysis of alternative switching schemes is essential and can result in considerable savings by choosing the minimum equipment necessary to satisfy system requirements. A number of factors must be considered in the selection of bus layouts and switching arrangements for a substation to meet system and station requirements.

A substation must be safe, reliable, economical, and as simple in design as possible. The design also should provide for further expansion, flexibility of operation, and low maintenance costs. The physical orientation of the transmission-line routes often dictates the substation’s location, orientation, and bus arrangement. This requires that the selected site allow for a convenient arrangement of the lines to be accomplished.

For reliability, the substation design should reduce the probability of a total substation outage caused by faults or equipment failure and should permit rapid restoration of service after a fault or failure occurs. The layout also should consider how future additions and extensions can be accomplished without interrupting service.

Traditional and Innovative Substation Design

Traditionally, high-voltage substations are engineered based on established layouts and concepts and conservative requirements. This approach can restrict the degree of freedom in introducing new solutions.

The most that can be achieved with this approach is the incorporation of new primary and secondary technology in preengineered standards. A more innovative approach is one that takes into account functional requirements such as system and customer requirements and develops alternative design solutions.

System requirements include elements of rated voltage, rated frequency, system configuration present and future, connected loads, lines, generation, voltage tolerances (over and under), thermal limits, short-circuit levels, frequency tolerance (over and under), stability limits, critical fault clearing time, system expansion, and interconnection.

Customer requirements include environmental consideration (climatic, noise, aesthetic, spills, right-of way), space consideration, power quality, reliability, availability, national and international applicable standards, network security, expandability, and maintainability. Carefully selected design criteria could be developed to reflect the company philosophy.

This would enable consideration and incorporation of elements such as life-cycle cost, environmental impact, initial capital investment, etc. into the design process. Design solutions could then be evaluated based on established evaluation criteria that satisfy the company interests and policies.

POWER SUBSTATION BASIC INFORMATION AND TUTORIALS – WHAT YOU NEED TO KNOW ABOUT SUBSTATION

WHAT IS A SUBSTATION?

A substation is an integral part of the power system. In large, modern ac power systems, the transmission and distribution systems function to deliver bulk power from generating sources to users at the load centers.

Transmission systems generally include generation switchyards, interconnecting transmission lines, autotransformers, switching stations, and step-down transformers. Distribution systems include primary distribution lines or networks, transformer banks, and secondary lines or networks, all of which serve the load area.

The construction of new substations and the expansion of existing facilities are commonplace projects in electric utilities. However, due to the complexity, very few utility employees are familiar with the complete process that allows these projects to be successfully completed.

As an integral part of the transmission or distribution systems, the substation or switching station functions as a connection and switching point for generation sources, transmission or subtransmission lines, distribution feeders, and step-up and step-down transformers.

The design objective for the substation is to provide as high a level of reliability and flexibility as possible while satisfying system requirements and minimizing total investment costs.

WHAT ARE THE DIFFERENT TYPES OF SUBSTATIONS?

There are four major types of electric substations. The first type is the switchyard at a generating station. These facilities connect the generators to the utility grid and also provide off-site power to the plant.

Generator switchyards tend to be large installations that are typically engineered and constructed by the power plant designers and are subject to planning, finance, and construction efforts different from those of routine substation projects.

Another type of substation is typically known as the customer substation. This type of substation functions as the main source of electric power supply for one particular business customer. The technical requirements and the business case for this type of facility depend highly on the customer’s requirements, more so than on utility needs.

The third type of substation involves the transfer of bulk power across the network and is referred to as a switching station. These large stations typically serve as the end points for transmission lines originating from generating switchyards, and they provide the electrical power for circuits that feed distribution stations.

They are integral to the long-term reliability and integrity of the electric system and enable large blocks of energy to be moved from the generators to the load centers. Since these switching stations are strategic facilities and usually very expensive to construct and maintain.

The fourth type of substation is the distribution substation. These are the most common facilities in electric power systems and provide the distribution circuits that directly supply most electric customers. They are typically located close to the load centers, meaning that they are usually located in or near the neighborhoods that they supply, and are the stations most likely to be encountered by the customers.

BRIEF HISTORY OF THE ELECTRIC POWER SYSTEM – BASIC INFORMATION

Over the past century, the electric power industry continues to shape and contribute to the welfare, progress, and technological advances of the human race. The growth of electric energy consumption in the world has been nothing but phenomenal.

In the United States, for example, electric energy sales have grown to well over 400 times in the period between the turn of the century and the early 1970s. This growth rate was 50 times as much as the growth rate in all other energy forms used during the same period. It is estimated that the installed kW capacity per capita in the U.S. is close to 3 kW.

Edison Electric Illuminating Company of New York inaugurated the Pearl Street Station in 1881. The station had a capacity of four 250-hp boilers supplying steam to six engine-dynamo sets. Edison’s system used a 110-V dc underground distribution network with copper conductors insulated with a jute wrapping.

In 1882, the first water wheel-driven generator was installed in Appleton, Wisconsin. The low voltage of the circuits limited the service area of a central station, and consequently, central stations proliferated throughout metropolitan areas.

The invention of the transformer, then known as the “inductorium,” made ac systems possible. The first practical ac distribution system in the U.S. was installed by W. Stanley at Great Barrington, Massachusetts, in 1866 for Westinghouse, which acquired the American rights to the transformer from its British inventors Gaulard and Gibbs.

Early ac distribution utilized 1000-V overhead lines. The Nikola Tesla invention of the induction motor in 1888 helped replace dc motors and hastened the advance in use of ac systems. The first American single-phase ac system was installed in Oregon in 1889. Southern California Edison Company established the first three phase 2.3 kV system in 1893.

By 1895, Philadelphia had about twenty electric companies with distribution systems operating at 100 V and 500-V two-wire dc and 220-V three-wire dc, single-phase, two-phase, and three-phase ac, with frequencies of 60, 66, 125, and 133 cycles per second, and feeders at 1000-1200 V and 2000- 2400 V.

The subsequent consolidation of electric companies enabled the realization of economies of scale in generating facilities, the introduction of equipment standardization, and the utilization of the load diversity between areas. Generating unit sizes of up to 1300 MW are in service, an era that was started by the 1973 Cumberland Station of the Tennessee Valley Authority.

Underground distribution at voltages up to 5 kV was made possible by the development of rubber-base insulated cables and paper-insulated, leadcovered cables in the early 1900s. Since then, higher distribution voltages have been necessitated by load growth that would otherwise overload low-voltage circuits and by the requirement to transmit large blocks of power over great distances. Common distribution voltages presently are in 5-, 15-, 25-, 35-, and 69-kV voltage classes.

The growth in size of power plants and in the higher voltage equipment was accompanied by interconnections of the generating facilities. These interconnections decreased the probability of service interruptions, made the utilization of the most economical units possible, and decreased the total reserve capacity required to meet equipment-forced outages.

This was accompanied by use of sophisticated analysis tools such as the network analyzer. Central control of the interconnected systems was introduced for reasons of economy and safety. The advent of the load dispatcher heralded the dawn of power systems engineering, an exciting area that strives to provide the best system to meet the load requirements reliably, safely, and economically, utilizing state of-the-art computer facilities.

Extra higher voltage (EHV) has become dominant in electric power transmission over great distances. By 1896, an 11-kv three-phase line was transmitting 10 MW from Niagara Falls to Buffalo over a distance of 20 miles. Today, transmission voltages of 230 kV, 287 kV, 345 kV, 500 kV, 735 kV, and 765 kV are commonplace, with the first 1100-kV line already energized in the early 1990s.

The trend is motivated by economy of scale due to the higher transmission capacities possible, more efficient use of right-of-way, lower transmission losses, and reduced environmental impact.

In 1954, the Swedish State Power Board energized the 60-mile, 100-kV dc submarine cable utilizing U. Lamm’s Mercury Arc valves at the sending and receiving ends of the world’s first high-voltage direct current (HVDC) link connecting the Baltic island of Gotland and the Swedish mainland. Currently, numerous installations with voltages up to 800-kV dc are in operation around the world.

In North America, the majority of electricity generation is produced by investor-owned utilities with a certain portion done by federally and provincially (in Canada) owned entities. In the United States, the Federal Energy Regulatory Commission (FERC) regulates the wholesale pricing of electricity and terms and conditions of service.

The North American transmission system is interconnected into a large power grid known as the North American Power Systems Interconnection. The grid is divided into several pools. The pools consist of several neighboring utilities which operate jointly to schedule generation in a cost-effective manner.

The electric power industry is undergoing fundamental changes since the deregulation of the telecommunication, gas, and other industries. The generation business is rapidly becoming market-driven. The power industry was, until the last decade, characterized by larger, vertically integrated entities.

The advent of open transmission access has resulted in wholesale and retail markets. Utilities may be divided into power generation, transmission, and retail segments. Generating companies (GENCO) sell directly to an independent system operator (ISO). The ISO is responsible for the operation of the grid and matching demand and generation dealing with transmission companies as well (TRANSCO).

This scenario is not the only possibility, as the power industry continues to evolve to create a more competitive environment for electricity markets to promote greater efficiency. The industry now faces new challenges and problems associated with the interaction of power system entities in their efforts to make crucial technical decisions while striving to achieve the highest level of human welfare.

POWER RECTIFIERS BASIC DEFINITION AND TUTORIALS

Virtually all power supplies use silicon rectifiers as the primary ac-to-dc converting device. Rectifier parameters generally are expressed in terms of reverse-voltage ratings and mean-forward-current ratings in a ½-wave rectifier circuit operating from a 60 Hz supply and feeding a purely resistive load.

The three primary reverse-voltage ratings are:

• Peak transient reverse voltage (Vrm)—the maximum value of any nonrecurrent surge voltage. This value must never be exceeded, even for a microsecond.

• Maximum repetitive reverse voltage [Vrm(rep)]—the maximum value of reverse voltage that can be applied recurrently (in every cycle of 60 Hz power). This includes oscillatory voltages that may appear on the sinusoidal supply.

• Working peak reverse voltage [Vrm(wkg)]—the crest value of the sinusoidal voltage of the ac supply at its maximum limit. Rectifier manufacturers generally recommend a value that has a significant safety margin, relative to the peak transient reverse voltage (Vrm), to allow for transient overvoltages on the supply lines.

There are three forward-current ratings of similar importance in the application of silicon rectifiers:

• Nonrecurrent surge current [Ifm(surge)]—the maximum device transient current that must not be exceeded at any time. Ifm(surge) is sometimes given as a single value, but often is presented in the form of a graph of permissible surge-current values vs. time. Because silicon diodes have a relatively small thermal mass, the
potential for short-term current overloads must be given careful consideration.

• Repetitive peak forward current [Ifm(rep)]—the maximum value of forward current reached in each cycle of the 60 Hz waveform. This value does not include random peaks caused by transient disturbances.

• Average forward current [Ifm(av)]—the upper limit for average load current through the device. This limit is always well below the repetitive peak forward current rating to ensure an adequate margin of safety.

Rectifier manufacturers generally supply curves of the instantaneous forward voltage vs. instantaneous forward current at one or more specific operating temperatures. These curves establish the forward-mode upper operating parameters of the device.