PAPER CLIP MOTOR EXPERIMENT TUTORIALS


How To Make A Paper Clip Motor - Experiment

Building something with our own hands often provides a new quality of insight, not to mention fun. With a few inexpensive materials, you can build your own d.c. electric motor.

The process of fiddling with your motor to get it to work well illustrates the principles of physics as no textbook description can, and watching it actually spin gives tremendous satisfaction. Putting your paper clip motor together takes only a few minutes, and it is worth it!

Materials Needed
2 paper clips
1 small, strong magnet (from Radio Shack; most refrigerator magnets are too weak)
1 C or D battery
1 yard of 20-gauge (AWG 20) coated copper wire
2 rubber bands or tape
1 small piece of sandpaper

Make a tidy wire coil by wrapping it 10 times or so around the battery. Leave a few inches of wire at both ends. Tighten the ends around the coil on opposite sides with an inch or more of wire sticking out straight from the coil to form an axle on which the coil will spin (see figure below).

Attach the magnet to the side of the battery. It may stick by itself, or you may want to secure it with a rubber band or tape. The magnet’s north or south pole should point directly away from the battery (this is the way the magnet naturally wants to go).

Bend the two paper clips and attach them with a rubber band or tape to both ends of the battery so as to form bearings on which the axle rests. The clips need to be shaped so that they make good electrical contact with the battery terminals, allow enough room for the coil to spin in front of the magnet, and keep the axle in place with a minimum of friction.

After checking the fit of the axle on the bearings, use the sandpaper to remove the red insulation coating on ONE end of the wire so that it can make electrical contact with the paper clip. At the other end, remove the coating on only HALF the wire by laying the wire coil flat down on a table and sanding only the top side.

This will interrupt the electrical contact during half the coil’s rotation, which is a crude way to reproduce the effect of commutator brushes. (Ideally, the direction of current flow through the coil should be reversed with every rotation, which would then deliver a steady torque on the coil in one direction; this is what commutator brushes do.

If direct current were allowed to flow continuously, the direction of the torque on the coil from the changing magnetic flux would reverse with every half-turn of the coil. Simply interrupting the current for half a turn interrupts the torque during just that period when it would be pulling the wrong way.

Once the spinning coil has enough momentum, it will just coast through the half-turn without power until it meets the correct torque again on the other side.)

When you place the coil on the bearings with the contact side down and current flowing, you feel it being pulled in one direction by the interaction of the fields of the permanent magnet and the coil (the “armature reaction”). Now give the coil a little shove with your finger and watch it spin.

Many thanks http://www.motors.ceresoft.org

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.

SINGLE BUS SUBSTATION SCHEME – BASIC INFORMATION AND TUTORIALS


Single Bus Scheme In Substation
The single-bus scheme is not normally used for major substations. Dependence on one main bus can cause a serious outage in the event of breaker or bus failure without the use of mobile equipment.

  
This arrangement involves one main bus with all circuits connected directly to the bus. The reliability of this type of an arrangement is very low. When properly protected by relaying, a single failure to the main bus or any circuit section between its circuit breaker and the main bus will cause an outage of the
entire system.

In addition, maintenance of devices on this system requires the de-energizing of the line connected to the device. Maintenance of the bus would require the outage of the total system, use of standby generation, or switching to adjacent station, if available.

The station must be deenergized in order to carry out bus maintenance or add bus extensions. Although the protective relaying is relatively simple for this scheme, the single-bus scheme is considered inflexible and subject to complete outages of extended duration.

Since the single bus arrangement is low in reliability, it is not recommended for heavily loaded substations or substations having a high availability requirement. Reliability of this arrangement can be improved by the addition of a bus tiebreaker to minimize the effect of a main bus failure.

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.

CLASSIFICATION OF MOTORS BY SPEED AND SERVICE


Speed classification of motor. Each electric motor possesses an inherent speed characteristic by which it can be classified in one of several groups. The following classification of speed characteristics is that adopted by the National Electrical Manufacturers Association (NEMA).

1. A constant-speed motor is one in which the speed of normal operation is constant or practically constant; for example, a synchronous motor, an induction motor with small slip, or a direct-current shunt-wound motor.

2. An adjustable-speed motor is one in which the speed can be controlled over a defined range, but when once adjusted remains practically unaffected by the load. Examples of adjustable-speed motors are: a direct-current shunt-wound motor with field resistance control designed for a considerable range of speed adjustments, or an alternating current motor controlled by an adjustable frequency power supply.

3. A multispeed motor is one which can be operated at any one of two or more definite speeds, each being practically independent of the load; for example, a direct-current motor with two armature windings or an induction motor with windings capable of various pole groupings. In the case of multispeed permanent-split capacitor and shadedpole motors, the speeds are dependent upon the load.

4. A varying-speed motor is one in which the speed varies with the load, ordinarily decreasing when the load increases, such as a series-wound or repulsion motor.

5. An adjustable varying-speed motor is one in which the speed can be adjusted gradually, but when once adjusted for a given load, will vary in considerable degree with change in load, such as a direct current compound-wound motor adjusted by field control or a wound-rotor induction motor with rheostatic speed control.

6. The base speed of an adjustable-speed motor is the lowest-rated speed obtained at rated load and rated voltage at the temperature rise specified in the rating.

Service classification of motors. Electric motors are classified into two groups, depending upon the type of service for which they are designed. General-purpose motors are those motors designed for general use without restriction to a particular application.

They meet certain specifications as standardized by NEMA. A definite-purpose motor is one which is designed in standard ratings and with standard operating characteristics for use under service conditions other than usual or for use on a particular type of application.

A special-purpose motor is one with special operating characteristics or special mechanical construction, or both, which is designed for a particular application and which does not meet the definition of a general-purpose or a definite-purpose motor.

TYPES OF ELECTRIC MOTORS BASIC INFORMATION AND TUTORIALS


Types of electric motors. Electric motors are manufactured in a number of different types. They may be divided into three main groups, depending upon the type of electric system from which they are designed to operate: dc, single-phase ac, and polyphase ac.

There are several types of motors in each one of these groups, constructed so that they produce different starting and running characteristics. The principal types of electric motors follow:

Direct-current
Shunt-wound
Straight shunt-wound
Stabilized shunt-wound
Series-wound
Compound-wound
Permanent magnet
Polyphase alternating-current

Induction
Squirrel-cage
Normal-torque, normal-starting-current
Normal-torque, low-starting-current
High-torque, low-starting-current
Low-torque, low-starting current
High-resistance-rotor
Automatic-start
Multispeed
Wound-rotor
Commutator, brush-shifting
Synchronous
Direct-current excited
Permanent-magnet
Reluctance
Single-phase alternating-current
Repulsion
Induction
Shading-pole–starting
Inductively split-phase–starting
Capacitor-type
Capacitor start
Permanent-split capacitor
Two-value capacitor
Repulsion-start, induction-run
Repulsion-induction
Series
Universal
Series-wound
Compensated series-wound

STATOR AND ROTOR LAMINATION ANNEALING BASIC INFORMATION


Stator Lamination Annealing
Semiprocessed lamination sheet is received from the producing mill in the heavily temper-rolled condition. This condition enhances the punchability of the sheet and provides energy for the metallurgical process of grain growth that takes place during the annealing treatment.Annealing of the laminations is done for several reasons. Among them are the following.

Cleaning. Punched laminations carry some of the punching lubricant on their surfaces. This can be a water-based or a petroleum-based lubricant. It must be removed before the laminations enter the high temperature zone of the annealing furnace to avoid sticking and carburization problems. This is done by preheating the laminations in an air or open-flame atmosphere to 260 to 427°C (500 to 800°F).

Carbon Control. Carbon in solution in steel can form iron carbides during mill processing, annealing, and electromagnetic device service. These carbides have several effects on properties—all detrimental. They affect metallurgical processing in the producing mill, degrading permeability and, to some extent, core loss.

They pin grain boundaries during annealing, slowing grain growth.They pin magnetic domain walls in devices, inhibiting magnetization and thus increasing core losses and magnetizing current. If the carbides precipitate during device use, the process is called aging.

Because of these problems, the amount of carbon is kept as low as is practical during mill processing. The best lamination steels are produced to carbon contents of less than 50 ppm. Steels of lesser quality can be produced with up to 600-ppm carbon, but in the United States, 400 ppm is presently a practical upper limit.Laminated cores cannot run efficiently with these high carbon contents, so the carbon is removed by decarburization during annealing.

The annealing atmosphere contains water vapor and carbon dioxide,which react with carbon in the steel to form carbon monoxide.The carbon monoxide is removed as a gas from the furnace.

This process works well for low-alloy steels, but for steels with appreciable amounts of silicon and aluminum, the same water vapor and carbon dioxide provide oxygen that diffuses into the steel, forming subsurface silicates and aluminates.

These subsurface oxides impede magnetic domain wall motion, lowering permeability and raising core loss.

Grain Growth. The grain diameter that minimizes losses in laminations driven at common power frequencies is 80 to 180 μm.As the driving frequency increases, this diameter will decrease. Presently, the temper-rolling percentage and the annealing time and temperature are designed to achieve grain diameters of 80 to 180 μm.

Coating. Laminations punched from semiprocessed steel are uncoated, while those punched from fully processed sheet are typically coated at the steel mill with a core plate coating. This coating insulates laminations from each other to reduce interlamination eddy currents, protects the steel from rust, reduces contact between laminations from burrs, and reduces die wear by acting as a lubricant during stamping.

The semiprocessed steel laminations are also improved by a coating, but economics precludes coating them at the steel mill. Instead, they are coated at the end of the annealing treatment when the laminations are cooling from 566°C to about 260°C (1050°F to about 500°F). The moisture content of the annealing atmosphere is controlled to form a surface oxide coating of magnetite.

This oxide of iron is very adherent and has a reasonably high insulating value. Therefore, it can be used for the same purposes as the relatively expensive core plate coating on the fully processed steel laminations. This magnetite coating is referred to as a blue coating or bluing because blue to blue-gray is its predominant color.

Rotor Lamination Annealing
Sometimes rotors are annealed with the stators, but often they are only given a rotor blue anneal.This is similar to the end of the stator anneal,mentioned previously.

The rotors are heated to about 371°C (700°F) in a steam-containing atmosphere to form a magnetite oxide on their surface. They are then die-cast with aluminum to form conductor bars and end rings. The magnetite oxide prevents adherence of the aluminum to the steel laminations and thereby reduces rotor losses.Stator Lamination Annealing
Semiprocessed lamination sheet is received from the producing mill in the heavily temper-rolled condition. This condition enhances the punchability of the sheet and provides energy for the metallurgical process of grain growth that takes place during the annealing treatment.Annealing of the laminations is done for several reasons. Among them are the following.

Cleaning. Punched laminations carry some of the punching lubricant on their surfaces. This can be a water-based or a petroleum-based lubricant. It must be removed before the laminations enter the high temperature zone of the annealing furnace to avoid sticking and carburization problems. This is done by preheating the laminations in an air or open-flame atmosphere to 260 to 427°C (500 to 800°F).

Carbon Control. Carbon in solution in steel can form iron carbides during mill processing, annealing, and electromagnetic device service. These carbides have several effects on properties—all detrimental. They affect metallurgical processing in the producing mill, degrading permeability and, to some extent, core loss.

They pin grain boundaries during annealing, slowing grain growth.They pin magnetic domain walls in devices, inhibiting magnetization and thus increasing core losses and magnetizing current. If the carbides precipitate during device use, the process is called aging.

Because of these problems, the amount of carbon is kept as low as is practical during mill processing. The best lamination steels are produced to carbon contents of less than 50 ppm. Steels of lesser quality can be produced with up to 600-ppm carbon, but in the United States, 400 ppm is presently a practical upper limit.Laminated cores cannot run efficiently with these high carbon contents, so the carbon is removed by decarburization during annealing.

The annealing atmosphere contains water vapor and carbon dioxide,which react with carbon in the steel to form carbon monoxide.The carbon monoxide is removed as a gas from the furnace.

This process works well for low-alloy steels, but for steels with appreciable amounts of silicon and aluminum, the same water vapor and carbon dioxide provide oxygen that diffuses into the steel, forming subsurface silicates and aluminates.

These subsurface oxides impede magnetic domain wall motion, lowering permeability and raising core loss.

Grain Growth. The grain diameter that minimizes losses in laminations driven at common power frequencies is 80 to 180 μm.As the driving frequency increases, this diameter will decrease. Presently, the temper-rolling percentage and the annealing time and temperature are designed to achieve grain diameters of 80 to 180 μm.

Coating. Laminations punched from semiprocessed steel are uncoated, while those punched from fully processed sheet are typically coated at the steel mill with a core plate coating. This coating insulates laminations from each other to reduce interlamination eddy currents, protects the steel from rust, reduces contact between laminations from burrs, and reduces die wear by acting as a lubricant during stamping.

The semiprocessed steel laminations are also improved by a coating, but economics precludes coating them at the steel mill. Instead, they are coated at the end of the annealing treatment when the laminations are cooling from 566°C to about 260°C (1050°F to about 500°F). The moisture content of the annealing atmosphere is controlled to form a surface oxide coating of magnetite.

This oxide of iron is very adherent and has a reasonably high insulating value. Therefore, it can be used for the same purposes as the relatively expensive core plate coating on the fully processed steel laminations. This magnetite coating is referred to as a blue coating or bluing because blue to blue-gray is its predominant color.

Rotor Lamination Annealing
Sometimes rotors are annealed with the stators, but often they are only given a rotor blue anneal.This is similar to the end of the stator anneal,mentioned previously.

The rotors are heated to about 371°C (700°F) in a steam-containing atmosphere to form a magnetite oxide on their surface. They are then die-cast with aluminum to form conductor bars and end rings. The magnetite oxide prevents adherence of the aluminum to the steel laminations and thereby reduces rotor losses.

MAGNETIC MOMENT IN ATOMS (BOHR MAGNETON) BASIC INFORMATION


The magnetic moment in various types of materials is a result of the following factors.

● Electron orbit. An electron in an orbit around a nucleus is analogous to a small current loop, in which the current is opposite to the direction of electron travel. This factor is significant only for diamagnetic and paramagnetic materials, where it is the same order of magnitude as the electron spin magnetic moment.

The magnetic properties of most materials (diamagnetic, paramagnetic, and antiferromagnetic) are so weak that they are commonly considered to be nonmagnetic.

● Electron spin. The electron cannot be accurately modeled as a small current loop. However, relativistic quantum theory predicts a value for the spin magnetic moment (or Bohr magneton b).

In an atom with many electrons, only the spin of electrons in shells which are not completely filled contribute to the magnetic moment. This factor is at least an order of magnitude larger than the electron orbit magnetic moment for ferromagnetic, antiferromagnetic, and superparamagnetic materials.

● Nuclear spin. This factor is insignificant relative to the overall magnetic properties of materials. However, it is the basis for nuclear magnetic resonance imaging (MRI).

● Exchange force. The exchange force is an interaction force (or coupling) between the spins of neighboring electrons. This is a quantum effect related to the indistinguishability of electrons, so that nothing changes if the two electrons change places.

The exchange force can be positive or negative, and in some materials the net spins of neighboring atoms are strongly coupled. Chromium and manganese (in which each atom is strongly magnetic) have a strong negative exchange coupling, which forces the electron spins of neighboring atoms to be in opposite directions and results in antiferromagnetic (very weak) magnetic properties.

Iron, cobalt, and nickel have unbalanced electron spins (so that each atom is strongly magnetic) and have a strong positive exchange coupling.

Therefore, the spins of neighboring atoms point in the same direction and produce a large macroscopic magnetization.This large-scale atomic cooperation is called ferromagnetism.

CAGE INDUCTION MOTOR BASIC INFORMATION AND TUTORIALS


This simplest form of ac induction motor or asynchronous motor is the basic, universal workhorse of industry. Its general construction is shown in Fig. 10.7. It is usually designed for fixed-speed operation, larger ratings having such features as deep rotor bars to limit

Direct on Line (DOL) starting currents. Electronic variable speed drive technology is able to provide the necessary variable voltage, current and frequency that the induction motor requires for efficient, dynamic and stable variable speed control.

Modern electronic control technology is able not only to render the ac induction motor satisfactory for many modern drive applications but also to extend greatly its application and enable users to take advantage of its low capital and maintenance costs. More striking still, microelectronic developments have made possible the highly dynamic operation of induction motors by the application of flux vector control.

The practical effect is that it is now possible to drive an ac induction motor in such a way as to obtain a dynamic performance in all respects better than could be obtained with a phase-controlled dc drive combination.


The stator winding of the standard industrial induction motor in the integral kilowatt range is three phase and is sinusoidally distributed. With a symmetrical three-phase supply connected to these windings, the resulting currents set up, in the air-gap between the stator and the rotor, a travelling wave magnetic field of constant magnitude and moving at synchronous speed.

The rotational speed of this field is f/p revolutions per second, where f is the supply frequency (hertz) and p is the number of pole pairs (a four-pole motor, for instance, having two pole pairs). It is more usual to express speed in revolutions per minute, as 60 f/p (rpm).

The emf generated in a rotor conductor is at a maximum in the region of maximum flux density and the emf generated in each single rotor conductor produces a current, the consequence being a force exerted on the rotor which tends to turn it in the direction of the flux rotation.

The higher the speed of the rotor, the lower the speed of the rotating stator flux field relative to the rotor winding, and therefore the smaller is the emf and the current generated in the rotor cage or winding.

The speed when the rotor turns at the same rate as that of the rotating field is known as synchronous speed and the rotor conductors are then stationary in relation to the rotating flux. This produces no emf and no rotor current and therefore no torque on the rotor.

Because of friction and windage the rotor cannot continue to rotate at synchronous speed; the speed must therefore fall and as it does so, rotor emf and current, and therefore torque, will increase until it matches that required by the losses and by any load on the motor shaft.

The difference in rotor speed relative to that of the rotating stator flux is known as the slip. It is usual to express slip as a percentage of the synchronous speed. Slip is closely proportional to torque from zero to full load.

The most popular squirrel cage induction motor is of a 4-pole design. Its synchronous speed with a 50 Hz supply is therefore 60 f/p, or 1500 rpm. For a full-load operating slip of 3 per cent, the speed will then be (1 – s)60 f/p, or 1455 rpm.

BRUSHLESS SERVOMOTORS BASIC INFORMATION


A synchronous machine with permanent magnets on the rotor is the heart of the modern brushless servomotor drive. The motor stays in synchronism with the frequency of supply, though there is a limit to the maximum torque which can be developed before the rotor is forced out of synchronism, pull-out torque being typically between 1.5 and 4 times the continuously rated torque.

The torque–speed curve is therefore simply a vertical line. The industrial application of brushless servomotors has grown significantly for the following reasons:

● reduction of price of power conversion products
● establishment of advanced control of PWM inverters
● development of new, more powerful and easier to use permanent magnet materials
● the developing need for highly accurate position control
● the manufacture of all these components in a very compact form

They are, in principle, easy to control because the torque is generated in proportion to the current. In addition, they have high efficiency, and high dynamic responses can be achieved.

Brushless servomotors are often called brushless dc servomotors because their structure is different from that of dc servomotors. They rectify current by means of transistor switching within the associated drive or amplifier, instead of a commutator as used in dc servomotors.

Confusingly, they are also called ac servomotors because brushless servomotors of the synchronous type (with a permanent magnet rotor) detect the position of the rotational magnetic field to control the three-phase current of the armature. It is now widely recognized that brushless ac refers to a motor with a sinusoidal stator winding distribution which is designed for use on a sinusoidal or PWM inverter supply voltage.

Brushless dc refers to a motor with a trapezoidal stator winding distribution which is designed for use on a square wave or block commutation inverter supply voltage.

The brushless servomotor lacks the commutator of the dc motor, and has a device (the drive, sometimes referred to as the amplifier) for making the current flow according to the rotor position. In the dc motor, increasing the number of commutator segments reduces torque variation.

In the brushless motor, torque variation is reduced by making the coil three-phase and, in the steady state, by controlling the current of each phase into a sine wave.

GENERATOR CLOSING UNTO DEAD BUS BASIC TUTORIALS


Closing onto a Dead Bus with Leading PF Load
It is possible to have a power system configuration where a bus might have capacitive loading.
• Static capacitors connected to it.
• Energizing a long high voltage transmission line. Note HV lines inherently appear like capacitors, which are able to supply MVARs.

In the capacitive loading situations the generator would have to absorb these MVARs. If the Automatic Voltage Regulator is in the Auto mode, the generator excitation is automatically decreased to cause the generator to take in the required MVARs and to hold the terminal voltage.

If the Automatic Voltage Regulator is in the manual mode, the excitation is constant and the leading power factor current which is required for the generator to take in MVARs could cause the generator terminal voltage to go very high.

Closing onto a Dead Bus with Lagging PF Load
Inductive loading can take the form of:
• Connected power transformers
• Motor Loads

Inductive loading will cause a significant voltage drop when the generator breaker is closed, due to the load absorbing MVARS.

Closing onto a Faulted Bus
Closing the generator output breakers onto a bus, which has a short circuit fault, can cause generator damage because of high winding currents, stresses and possible pole slipping.

Closing onto a Dead Bus with no Connected Loads
This should not present a problem as long as the bus has been proven to be free of faults or working grounds.

GENERATOR LOADING
Closing onto a Finite vs Infinite System
When we enter into the topic of generator loading we must consider whether or not the connected electrical system is very large and hence strong or smaller and weaker. The first is classed as infinite and the second finite.

A generator connected to a very large (infinite bus) electrical system will have little or no effect on its voltage or frequency. In contrast, a generator connected to a finite bus does have a substantial effect on voltage and frequency.

It is normally assumed that when a generator has a capacity of greater than 5% of the system size, then with respect to this generator, the system does not behave as an infinite bus. For example, when an 800 MW generator is loaded onto a grid having a capacity of l0,000 MW, the system voltage and frequency can vary and the system will behave

FERRORESONANCE – POWER QUALITY ISSUE BASIC AND TUTORIALS


The term ferroresonance refers to a resonance that involves capacitance and iron-core inductance. The most common condition in which it causes disturbances in the power system is when the magnetizing impedance of a transformer is placed in series with a system capacitor due to an open-phase conductor.

Under controlled conditions, ferroresonance can be exploited for useful purpose such as in a constant voltage transformer. In practice, ferroresonance most commonly occurs when unloaded transformers become isolated on underground cables of a certain range of lengths.

The capacitance of overhead distribution lines is generally insufficient to yield the appropriate conditions. The minimum length of cable required to cause ferroresonance varies with system voltage level.

The capacitance of cables is nearly the same for all distribution voltage levels, varying from 40 to 100 nF per 1000 ft, depending on conductor size. However, the magnetizing reactance of a 35-kVclass distribution transformer is several times higher (curve is steeper) than a comparably-sized 15-kV-class transformer.

Therefore, damaging ferroresonance has been more common at the higher voltages. For delta connected transformers, ferroresonance can occur for less than 100 ft of cable.

For this reason, many utilities avoid this connection on cable-fed transformers. The grounded wyewye transformer has become the most commonly used connection in underground systems in North America.

It is more resistant, but not immune, to ferroresonance because most units use a three legged or five legged core design that couples the phases magnetically. It may require a minimum of several hundred feet of cable to provide enough capacitance to create a ferroresonant condition for this connection.

The most common events leading to ferroresonance are
• Manual switching of an unloaded, cable-fed, 3-phase transformer where only one phase is closed (Fig. 23-28a). Ferroresonance may be noted when the first phase is closed upon energization or before the last phase is opened on de-energization.

• Manual switching of an unloaded, cable-fed, 3-phase transformer where one of the phases is open (Fig. 23-28b). Again, this may happen during energization or de-energization.

• One or two riser-pole fuses may blow leaving a transformer with one or two phases open. Single phase reclosers may also cause this condition. Today, many modern commercial loads will have controls that transfer the load to backup systems when they sense this condition. Unfortunately, this leaves the transformer without any load to damp out the resonance.

• Phase of a cable connected to a wye-connected transformer.

FIGURE 23-28 Common system conditions where ferroresonance may occur: (a) one phase closed, (b) one phase open.

LOW SIDE SURGES BASIC INFORMATION AND TUTORIALS


Some utility and end-user problems with lightning impulses are closely related. One of the most significant ones is called the low-side surge problem by many utility engineers.

The name was coined by distribution transformer designers because it appears from the transformer’s perspective that a current surge is suddenly injected into the low-voltage side terminals. Utilities have not applied secondary arresters at low-voltage levels in great numbers.

From the customer’s point of view, it appears to be an impulse coming from the utility and is likely to be termed as “secondary surge.”

Both problems actually have different side effects of the same surge phenomenon—lightning current flowing from either the utility side or the customer side along the service cable neutral. Figure 23-26 shows one possible scenario.  

FIGURE 23-26 Primary arrester discharge current divides between pole and load ground.

Lightning strikes the primary line and the current is discharged through the primary arrester to the pole ground lead. This lead is also connected to the X2 bushing of the transformer at the top of the pole. Thus, some of the current will flow toward the load ground.

The amount of current into the load ground is primarily dependent on the size of the pole ground resistance relative to the load ground. Inductive elements may play a significant role in the current division for the front of the surge, but the ground resistances basically dictate the division of the bulk of the stroke current.

The current that flows through the secondary cables causes a voltage drop in the neutral conductor that is only partially compensated by mutual inductive effects with the phase conductors. Thus, there is a net voltage across the cable, forcing current through the transformer secondary windings and into the load as shown by the dashed lines in the figure.

If there is a complete path, substantial surge current will flow. As it flows through the transformer secondary, a surge voltage is induced in the primary, sometimes causing a layer-to-layer insulation failure near the grounded end.

If there is not a complete path, the voltage will buildup across the load and may flash over somewhere on the secondary. It is common for the meter gaps to flashover, but not always before there is damage on the secondary because the meter gaps are usually 6 to 8 kV, or higher.

The amount of voltage induced in the cable is dependent on the rate-of-rise of the current, which is dependent on other circuit parameters as well as the lightning stroke.

The chief power quality problems this causes are
• The impulse entering the load can cause failure or misoperation of load equipment.
• The utility transformer will fail causing an extended power outage.
• The failing transformer may subject the load to sustained steady-state overvoltages because part of the primary winding is shorted, decreasing the transformer turns ratio. Failure usually occurs in seconds, but has been known to take hours.

The key to this problem is the amount of surge current traveling through the secondary service cable. Keep in mind that the same effect occurs regardless of the direction of the current. All that is required is for the current to get into the ground circuits and for a substantial portion to flow through the cable on its way to another ground.

Thus, lightning strikes to either the utility system or the end-user facilities can produce the same symptoms. Transformer protection is more of an issue in residential services, but the secondary transients will appear in industrial systems as well.

MITIGATION EQUIPMENT FOR VOLTAGE SAGS POWER QUALITY PROBLEM


The most commonly applied method of mitigation is the installation of additional equipment at the system-equipment interface. Also recent developments point toward a continued interest in this way of mitigation.

The popularity of mitigation equipment is explained by it being the only place where the customer has control over the situation. Both changes in the supply as well as improvement of the equipment are often completely outside of the control of the end user. Some examples of mitigation equipment are:

. Uninterruptable power supply (UPS). This is the most commonly used device to protect lowpower equipment (computers, etc.) against voltage sags and interruptions. During the sag or interruption, the power supply is taken over by an internal battery.

The battery can supply the load for, typically, between 15 and 30 minutes.

. Static transfer switch. A static transfer switch switches the load from the supply with the sag to another supply within a few milliseconds. This limits the duration of a sag to less than one halfcycle, assuming that a suitable alternate supply is available.

. Dynamic voltage restorer (DVR). This device uses modern power electronic components to insert a series voltage source between the supply and the load. The voltage source compensates for the voltage drop due to the sag.

Some devices use internal energy storage to make up for the drop in active power supplied by the system. They can only mitigate sags up to a maximum duration.

Other devices take the same amount of active power from the supply by increasing the current. These can only mitigate sags down to a minimum magnitude. The same holds for devices boosting the voltage through a transformer with static tap changer.

. Motor-generator sets. Motor-generator sets are the classical solution for sag and interruption mitigation with large equipment. They are obviously not suitable for an office environment but the noise and the maintenance requirements are often no problem in an industrial environment.

Some manufacturers combine the motor-generator set with a backup generator; others combine it with power-electronic converters to obtain a longer ride-through time.

FLICKERING LIGHTS – POWER QUALITY CASE STUDY AND SOLUTION


This case study concerns a residential electrical system. The homeowners were experiencing light flicker when loads were energized and deenergized in their homes.

Background
Residential systems are served from single-phase transformers employing a spilt secondary winding, often referred to as a single-phase three-wire system. This type of transformer is used to deliver both 120-volt and 240-volt single-phase power to the residential loads.

The primary of the transformer is often served from a 12 to 15 kV distribution system by the local utility. Figure 29.14 illustrates the concept of a split-phase system.

FIGURE 29.14 Split-phase system serving a residential customer.

When this type of service is operating properly, 120 volts can be measured from either leg to the neutral conductor. Due to the polarity of the secondary windings in the transformer, the polarity of each 120-volt leg is opposite the other, thus allowing a total of 240 volts between the legs as illustrated.

The proper operation of this type of system is dependent on the physical connection of the neutral conductor or center tap of the secondary winding. If the neutral connection is removed, 240 volts will remain across the two legs, but the line-to-neutral voltage for either phase can be shifted, causing either a low or high voltage from line to neutral.

Most loads in a residential dwelling, i.e., lighting, televisions, microwaves, home electronics, etc., are operated from 120 volts. However, there are a few major loads that incorporate the use of the 240 volts available. These loads include electric water heaters, electric stoves and ovens, heat pumps, etc.

The Problem
In this case, there were problems in the residence that caused the homeowner to question the integrity of the power system serving his home. On occasion, the lights would flicker erratically when the washing machine and dryer were operating at the same time. When large single-phase loads were operated, low power incandescent light bulb intensity would flicker.

Measurements were performed at several 120-volt outlets throughout the house. When the microwave was operated, the voltage at several of the 120-volt outlets would increase from 120 volts nominal to 128 volts.

The voltage would return to normal after the microwave was turned off. The voltage would also increase when a 1500-Watt space heater was operated. It was determined that the voltage would decrease to approximately 112 volts on the leg from which the large load was served. After the measurements confirmed suspicions of high and low voltages during heavy load operation, finding the source of the problem was the next task at hand.

The hunt began at the service entrance to the house. A visual inspection was made of the meter base and socket after the meter was removed by the local utility. It was discovered that one of the neutral connectors was loose. While attempting to tighten this connector, the connector fell off of the meter socket into the bottom of the meter base (see Fig. 29.15).

  FIGURE 29.15 Actual residential meter base. Notice the missing neutral clamp on load side of meter.

Could this loose connector have been the cause of the flickering voltage? Let’s examine the effects of the loose neutral connection. Figures 29.16 and 29.17 will be referred to several times during this discussion.

Under normal conditions with a solid neutral connection (Fig. 29.16), load current flows through each leg and is returned to the source through the neutral conductor. There is very little impedance in either the hot or the neutral conductor; therefore, no appreciable voltage drop exists.

FIGURE 29.16 The effects of a solid neutral connection in the meter base.

When the neutral is loose or missing, a significant voltage can develop across the neutral connection in the meter base, as illustrated in Fig. 29.17. When a large load is connected across Leg 1 to N and the other leg is lightly loaded (i.e., Leg 1 to N is approximately 10 times the load on Leg 2 to N), the current flowing through the neutral will develop a voltage across the loose connection.

This voltage is in phase with the voltage from Leg 1 to N0 (see Fig. 29.17) and the total voltage from Leg 1 to N will be 120 volts.

FIGURE 29.17 The effects of a loose neutral connection in the meter base.

However, the voltage supplied to any loads connected from Leg 2 to N0 will rise to 128 volts, as illustrated in Fig. 29.17. The total voltage across the Leg 1 and Leg 2 must remain constant at 240 volts. It should be noted that the voltage from Leg 2 to N will be 120 volts since the voltage across the loose connection is 1808 out of phase with the Leg 2 to N0 voltage.

Therefore, with the missing neutral connection, the voltage from Leg 2 to N0 would rise, causing the light flicker. This explains the rise in voltage when a large load was energized on the system.

The Solution
The solution in this case was simple—replace the failed connector.

Conclusions
Over time, the neutral connector had become loose. This loose connection caused heating, which in turn caused the threads on the connector to become worn, and the connector failed.

After replacing the connector in the meter base, the flickering light phenomena disappeared. On systems of this type, if a voltage rise occurs when loads are energized, it is a good indication that the neutral connection may be loose or missing.



NEC GROUNDING TERMS AND DEFINITIONS BASIC INFORMATION


Bonding Jumper, Main: The connector between the grounded circuit conductor (neutral) and the equipment-grounding conductor at the service entrance.

Conduit=Enclosure Bond: (bonding definition) The permanent joining of metallic parts to form an electrically conductive path which will assure electrical continuity and the capacity to conduct safely any current likely to be imposed.

Grounded: Connected to earth or to some conducting body that serves in place of the earth.

Grounded Conductor: A system or circuit conductor that is intentionally grounded (the grounded conductor is normally referred to as the neutral conductor).

Grounding Conductor: A conductor used to connect equipment or the grounded circuit of a wiring system to a grounding electrode or electrodes.

Grounding Conductor, Equipment:The conductor used to connect the noncurrent-carrying metal parts of equipment, raceways, and other enclosures to the system grounded conductor and=or the grounding electrode conductor at the service equipment or at the source of a separately derived system.

Grounding Electrode Conductor: The conductor used to connect the grounding electrode to the equipment-grounding conductor and=or to the grounded conductor of the circuit at the service equipment or at the source of a separately derived system.

Grounding Electrode: The grounding electrode shall be as near as practicable to and preferably in the same area as the grounding conductor connection to the system. The grounding electrode shall be:

(1) the nearest available effectively grounded structural metal member of the structure; or
(2) the nearest available effectively grounded metal water pipe; or
(3) other electrodes (Section 250-81 & 250-83) where electrodes specified in (1) and (2) are not available.

Grounding Electrode System: Defined in NEC Section 250-81 as including: (a) metal underground water pipe; (b) metal frame of the building; (c) concrete-encased electrode; and (d) ground ring. When these elements are available, they are required to be bonded together to form the grounding electrode system.

Where a metal underground water pipe is the only grounding electrode available, it must be supplemented by one of the grounding electrodes specified in Section 250–81 or 250–83.

Separately Derived Systems: A premises wiring system whose power is derived from generator, transformer, or converter windings and has no direct electrical connection, including a solidly connected grounded circuit conductor, to supply conductors originating in another system.

SHAFT CURRENT, BEARING INSULATION, AND PHASE SEQUENCE TEST OF SYNCHRONOUS GENERATORS


Shaft Current and Bearing Insulation
Irregularities in the SG magnetic circuit lead to a small axial flux that links the shaft. A parasitic current occurs in the shaft, bearings, and machine frame, unless the bearings are insulated from stator core or from rotor shaft.

The presence of pulse-width modulator (PWM) static converters in the stator (or rotor) of SG augments this phenomenon. The pertinent testing is performed with the machine at no load and rated voltage. The voltage between shaft ends is measured with a high impedance voltmeter.

The same current flows through the bearing radially to the stator frame. The presence of voltage across bearing oil film (in uninsulated bearings) is also an indication of the shaft voltage.

If insulated bearings are used, their effectiveness is checked by shorting the insulation and observing an increased shaft voltage. Shaft voltage above a few volts, with insulated bearings, is considered unacceptable due to bearing in-time damage.

Generally, grounded brushes in shaft ends are necessary to prevent it.

Phase Sequence
Phase sequencing is required for securing given rotation direction or for correct phasing of a generator prepared for power bus connection. As known, phase sequencing can be reversed by interchanging any two armature (stator) terminals.

There are a few procedures used to check phase sequence:

• With a phase-sequence indicator (or induction machine)
• With a neon-lamp phase-sequence indicator (Figure 8.1a and Figure 8.1b)
• With the lamp method (Figure 8.1b)

When the SG no-load voltage sequence is 1–2–3 (clockwise), the neon lamp 1 will glow, while for the 1–3–2 sequence, the neon lamp 2 will glow. The test switch is open during these checks.

The apparatus works correctly if, when the test switch is closed, both lamps glow with the same intensity (Figure 8.1a).

FIGURE 8.1 Phase-sequence indicators: (a) independent (1–2–3 or 1–3–2) and (b) relative to power grid.

With four voltage transformers and four lamps (Figure 8.1b), the relative sequence of SG phases to power grid is checked. For direct voltage sequence, all four lamps brighten and dim simultaneously. For the opposite sequence, the two groups of lamps brighten and dim one after the other.


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