High voltage switchgear and operations, by their very nature, can be extremely dangerous. Once in the door to a substation room, you are in a world where common sense and attention to detail are mandatory. This is an area of a multitude of potential hazards, but all of these are known and understood. These hazards can be planned for, worked around, reduced, or even removed.
Safety in the substation concerns three different areas: protection of life, protection of equipment, and prevention of power interruption. These ideals are easily obtainable, requiring only some additional effort in planning and use of proper safety equipment. Improvement of personnel safety, being of utmost concern, is also probably the most achievable by using a few simple rules and ensuring awareness of hazards is always of concern.
The obvious need for electrical safety is to prevent personnel from being exposed to electricity in an uncontrolled manner that may result in injury or death. Some of the other concerns are preventing damage to equipment and maintaining power service stability and continuity, but the biggest concern is the effects of electrical current and high electrical potentials on the human body.
Most people are aware of the fact that the principle danger from electricity is electrocution, but few understand just how small an amount of current flow is actually required for serious injury or death to occur. In gaining the understanding of the effects, we must look at the factors that affect the severity of a shock.
One of the first factors is the quantity of current and the effects on the body at different levels of current flow. Table 1 shows the effects of alternating current on the human body. We are illustrating alternating currents only. Even though the effects are similar for direct current, most of the exposure you will encounter will be with AC circuits. As shown in the table, most of the dangerous levels are above 100 milliamps, but another factor that goes hand-in-hand with the quantity of current is the time that contact is maintained with the circuit. The rule of thumb for ventricular fibrillation to occur is 100 milliamps for 1 second.
Table 1: Current Effects of 60 Hz AC on the Body
Another factor is the path that the current takes through the body. The most dangerous is the chest because of the effect on the heart. The final factor of concern is the frequency of the current to which you could be exposed. The most dangerous alternating current frequencies are around 50 to 100 hertz. These seem to have a more devastating effect because of the resulting ventricular fibrillation at lower current levels. Direct currents have a complete clamping and burning effect. Remember, the human body operates on direct current. The higher in frequency you go above 200 hertz, the more severe burns will be encountered because the current tends to travel the surface of the skin instead of inside tissue as occurs with 60 hertz.
Knowing the factors that affect the severity can help you in determining the type of precautions and the amount of precautions you must take in preparing and performing electrical work and operations. Always remember that your efforts should be towards controlling and minimizing these factors.
Examples of using your knowledge of these factors is the use of rubber insulating material or working with one hand as much as possible when working on energized circuits. The insulation helps to reduce the possibility of contact, and working with one hand and keeping the other insulated prevents a path for current through the chest.
Another point to remember is that even though the current flow through the body is what kills, the higher the voltage becomes in the scheme also has an effect. Above about 600 volts, the resistance of the skin ceases to exist, meaning that the only impedance to current flow at high voltages is the internals of the body. Somewhere above 2400 volts, burning becomes the major effect, and the amount of time in contact determines the severity.
There are many safety hazards within a substation. The most obvious are electrical hazards and other things you can see and hear. Other hazards are confined spaces, oil and other fire hazards, and compressed gas systems, to name a few.
There are definite differences in precautions and the approach to handling work on grounded versus ungrounded systems. The reason for this is the false sense of security created by the isolated neutral system.
Figure 1 shows a grounded power system and the effect of coming into contact with it energized. As long as the ground path is at a lower resistance than the person coming in contact with the circuit, the effect should be minimal and provide some safety. Again, the importance of the ground path resistance cannot be overemphasized. This is a system designed for personnel protection and equipment protection, but imperfections in ground can make it extremely hazardous to personnel. If you touch an energized source, you make a parallel circuit to ground, and some of the current will pass through your body.
Figure 1: Grounded Power System Contact
Figure 2 shows an ungrounded or isolated neutral system in which there is no contact to ground, and the system is not designed to operate at ground potential. Although you do not see an obvious path to ground for a complete path for current flow, the electrostatic coupling that occurs creates a path and makes the system dangerous. The isolated neutral system is extremely reliable from an equipment power viewpoint but extremely dangerous for personnel if approached like a grounded system. This also illustrates the importance of grounding for safety.
Figure 2: Ungrounded Power System
A common phenomenon of high-voltage electrical systems is electrostatic coupling. This is a capacitive effect caused by two insulated conductors being close together, one energized by a high voltage and the other one dead. The live conductor impresses a charge on the dead conductor in the same way that a capacitor is charged. Figure 3 illustrates this coupling by electrical fields created by the load current flow.
Figure 3: Electrostatic Coupling
This can have several effects. First, the coupling that occurs in the isolated neutral system results in a ground path for current to flow. Second, it can build a charge because of the capacitive effect and discharge when contacted by a technician. Although this in itself is rarely of sufficient capacity to harm the individual, it can startle the technician and cause him or her to fall from a high location or to make contact with another circuit that is energized from a live source.
Capacitors are often overlooked as a source of voltage when checking de-energized circuits. When preparing to service a circuit that contains capacitors, it should be done in the following sequence:
Although they seldom occur, you should be most prepared for hazards from electrical arcs. Too many times, personnel injury has occurred from exposure to an arc that should not have happened and was not expected. Severe burns and permanent eye damage can be avoided by simply using protective clothing and eye protection.
In addition to the hazards of burns from being in close proximity to arcs, a large number of injuries occur from direct contact with overheated electrical equipment. A good method to check electrical equipment for overheating is to use the back of your hand to check surfaces. A rule of thumb to remember is if you cannot hold the back of your hand to a surface for more than 10 seconds, it is hotter than 150 degrees.
A storage battery is constantly "alive" electrically and is a source of electrical shock. Care must be taken to avoid contacting the positive and negative terminals. Tools and test equipment should never be laid down on top of batteries because of the danger of extreme short-circuit currents.
Smoking should never be permitted in a battery charging room or substation control house, since all storage batteries generate hydrogen gas during a charge. Ventilation should always be maintained in these areas to prevent a buildup of explosive gas concentration.
Always avoid contact with the electrolyte used in batteries. The acid is highly corrosive to any material contacted and dangerous if ingested or if it contacts soft tissue, such as the face or eyes. If contact with the eyes occurs, an emergency eyewash facility should be used to flush the acid from the eyes. A good neutralizer to use in washing acid away from metals, floors, and the tops of the battery cases is a solution of bicarbonate of soda and water.
In almost all cases of fire in electrical equipment, removing the power from the component or circuit will stop the fire. Removing the power is the same as removing the fuel. If an electrical fire continues after removing the power, it is due to either the insulation material burning or debris in the vicinity burning. In any case, you should always extinguish any other material on fire and then cool the area to prevent fire re-ignition.
The most effective extinguisher for use in an electrical fire is a fire extinguisher rated for a Class C fire. The CO2and dry chemical extinguishers are both rated Class C. The biggest advantage of using a CO2extinguisher is that it will not severely damage any of the electrical circuits it contacts. A dry chemical extinguisher begins an immediate corrosive action that will damage any metal it contacts if not completely removed from all surfaces and equipment as soon as possible. The use of water should be restricted to an extreme emergency and then only by trained fire fighters capable of dealing with an out-of-control fire.
The effective range of a 15# CO2extinguisher is 2 to 5 feet, and it will only last for about 40 to 45 seconds on a continuous discharge. DO NOT confine yourself into an area with CO2because it displaces the oxygen, which could cause you to lose consciousness if exposed for very long. A large fire could require the use of several CO2extinguishers, so keep that in mind.
A dry chemical extinguisher has a maximum range of about 15 feet, and it will only last about 30 seconds on a continuous discharge. When using a dry chemical extinguisher, a problem that is similar to the CO2extinguisher is the effect on breathing if a large amount is used or if you are in a confined space. It does not displace oxygen, but it is a heavy powder, and it will disperse in the air, making breathing difficult.
If you find a fire, no matter what the cause, you should immediately report it. Other emergency actions you can perform for an electrical fire are as follows:
If a transformer containing PCBs is on fire, leave the area and report the fire. When heated above 175F, PCBs produce phosgene gas. Phosgene gas is toxic, and you should not take any action to try and extinguish it yourself. You should warn the fire department of this when they arrive to fight the fire. This will ensure that they are wearing respiratory equipment.
Always remember, '''NEVER''' try to extinguish large fires or chemical fires, and '''NEVER''' try to do it alone. Equipment can be replaced and rebuilt; people cannot.
The most important piece of safety equipment in performing work in an electrical environment is common sense. All areas of electrical safety precautions and practices draw upon common sense and attention to detail. One of the most dangerous conditions in an electrical work area is a poor attitude towards safety.
The following are considered some of the basic and necessary electrical safety precautions that lay the groundwork for a proper safety program:
Before going on any electrical work assignment, the following safety precautions should be reviewed and adhered to:
The types of electrical safety equipment and personnel protective equipment (PPE) available for use in a substation are quite varied. We will discuss the care and general requirements for use of the major types of safety equipment necessary to perform your tasks safely and effectively. The major types of equipment and apparel that will be discussed in the section are as follows:
Rubber gloves with leather protectors that have been tested to at least 10,000 volts should be worn when work is performed on, or within reach of, energized conductors and/or equipment. The rubber gloves and protectors of the appropriate class should be available to all trained personnel as part of the available safety equipment for use in substation operations and maintenance.
Rubber gloves and protectors are of two types:
Both high- and low-voltage rubber gloves are of the gauntlet type and are available in various sizes. To get the best possible protection and service life, here are a few general rules that apply whenever they are used in electrical work:
When inspecting rubber gloves, stretch a small area at a time, as shown in Figure 4, checking to see that no defects exist, such as:
Figure 4: Inspecting Rubber Gloves
Remember, any damage at all reduces the insulating ability of the rubber glove. Look for signs of deterioration from age such as hardening and slight cracking. Also, if the glove has been exposed to petroleum products, it should be considered suspect because of the deterioration caused by exposure. Gloves that are found defective should be replaced. Never leave a damaged glove around for any other purpose; someone may think it is a good glove and not perform an inspection prior to using it.
After visually inspecting the glove, other defects may be observed by applying the air test as follows:
Figure 5: Applying the Air Test
Figure 6: Rolling the Glove Gauntlet
Figure 7: Trapping Air
When working with high voltages, fire suits may be required in some applications. Some plants require them to be worn for all switching and rack-in or rack-out operations.
Face shields should also be worn during all switching operations where arcs are a possibility. The thin plastic type of face shield should be avoided because it will melt when exposed to the extremely high temperatures of an electrical arc.
Rubber sleeves are another type of protective apparel that should be worn during switching operations and breaker racking.
An individual who is going to be working in a substation should dress accordingly. The wearing of synthetic fiber clothing should be avoided. These types of materials tend to melt when exposed to high temperatures and will actually increase the severity of a burn. Cotton clothing, fiberglass toe boots or shoes, hard hats, and hearing protection where needed are appropriate types of clothing.
Hot sticks are insulated tools designed for the manual operation of disconnecting switches, fuse removal and insertions, and application and removal of temporary grounds.
A hot stick is made up of the head, or hook, and the insulating rod. The head can be made of metal or hardened plastic, while the insulating section may be wood, plastic, laminated wood, or other effective insulating materials.
A stick of the correct type and size for the applications intended should be selected. There are also telescoping sticks available.
Storage of hot sticks is important. They should be hung up vertically on a wall to prevent any damage. They should also be stored away from direct sunlight and prevented from being exposed to petroleum products. The most preferred method of storage is to place the stick in a long section of capped pipe.
Clearance distances provided in Table 2 are from NFPA 70E Table 2-1.3.4 Approach Boundaries to Live Parts for Shock Protection. Do not approach any electrical conductors closer than indicated in the table unless the circuit has been verified by a qualified person de-energized. Also, the values given below are minimum safe-clearance distances. If you already have standard distances established, these are provided only as supplemental information.
Table 2: Minimum Safe Clearance Distances
The insulating blanket is a versatile, cover-up device that is best-suited for protection against accidental contact of technicians’bodies with energized electrical equipment.
Blankets are designed and manufactured to provide insulating quality and flexibility for use in covering. Insulating blankets are designed only for covering and should not be used for standing on. Use caution when installing on sharp edges or covering pointed objects. The visual inspection that is performed on rubber gloves prior to use should also be done with the insulating blanket prior to use, with the exception of an air test. Many of the same storage requirements should also be adhered to, except that blankets should be rolled up for storage.
The best type of fuse puller to use is one that has a spread guard installed. This prevents the pullers from opening if resistance is met in installing fuses.
When replacing transformer fuses in the distribution system, fuse pullers of the type shown in Figure 8 should be used. When placing the puller grip on the fuse, turn it clockwise to tighten the grip and turn it counter-clockwise to loosen the grip.
Figure 8: Transformer Fuse Puller
There is a seemingly endless variety of electrical test equipment. The types we will discuss will be of the style that will be needed for use in the field: the low-voltage tester, audio voltage detectors, and high-voltage, direct-contact, and proximity detectors.
Low-voltage testers, such as the "Wiggins" or "Simpson" multimeter, should be used for measuring voltages in the range from 110 to 600 volts. They can be used to test for power presence, blown fuses, grounds, and polarity.
These meters should be tested before use to verify their operability. The Wiggins does not contain any internal protection in the event of contact with too high of a voltage; therefore, when using the Wiggins, use caution. The multimeter is preferable for use, even though it is sometimes more cumbersome than the small hand-held Wiggins.
The audio-type voltage detector uses the electrostatic field created by an AC-voltage presence to operate the detector. Some of the devices can sense from as low as 110 volts AC to use on high-voltage systems. These instruments normally have a telescoping shield that can be extended for greater sensitivity and use on higher voltages.
The audio detector will emit a tone, click, or beep when turned on. A change in the initial signal indicates the presence of a voltage. This type of detector will provide you indication of the voltage value.
The proximity-type detector, or "Static Scope", works similarly to the audio detector, except that a neon tube illuminates when near a voltage. This type of detector is usable only for voltages greater than 1,000 volts. This type of detector is also referred to as a ''glow stick''.
The direct contact type of detector is used for detecting and measuring high voltages. Its construction is the same as all the previous types we have discussed, except that this type contains a high-voltage voltmeter for reading phase-to-ground or phase-to-phase voltages.
When measuring voltages or testing a circuit with electrical test equipment, the following precautions should be observed:
To de-energize a piece of equipment, circuit breakers or switches must be opened and/or fuses removed. Certain safety precautions must be observed when conducting switching operations. Additionally, proper grounding must be used to ensure safety once the equipment has been verified de-energized. More than once, ground clusters have saved a life when improper switching has occurred.
Each breaker must be opened, racked out to a disconnected position or removed from its cubicle, a sign hung, and lockouts installed when a breaker is used for isolation. In addition, the springs should be discharged. A standard racking procedure should be provided with the switchgear and followed to prevent mishaps.
Where disconnects are installed for use in isolation, they should never be opened under load. When manually opening a disconnect, it should be done quickly with a positive force. Again, lockouts should be used when the disconnects are open.
The air break disconnects (quick disconnects) provided on the upstream side of the transformer fuses must be opened and locks removed prior to opening the fuse compartment. Severe arcing can result in a 13.8 kV system, resulting in personnel injury and equipment damage.
To replace fuses, the following basic steps should be followed:
When performing maintenance on electrical equipment, it is essential to make sure that the equipment is isolated and grounded; therefore, some methodical system is needed to make sure that the right equipment is isolated and remains isolated while you are doing your work.
This system is called the ''lockout system''. Basically, this system consists of shutting down the equipment by normal means, locking out the equipment with an assigned individual lock, and dissipating any "stored" energy such as in capacitors, air pressure, hydraulic pressure, and springs.
To lock out equipment, a lockout device is placed on the operating handle of the isolating device to prevent the handle from moving. For example, a lockout device can be placed on a disconnect switch to prevent the switch from moving out of the OFF position.
When you are locking out a piece of equipment, a safety lock is used. The locks installed on some circuit breakers are for ensuring that proper switching sequences are followed and are NOT to be used as a replacement for approved safety locks.
This lock and its key are issued to an individual. Combination locks are not to be used for lockout purposes. To protect yourself and others, you should never give the key to your lock to anyone else. The rule is ONE WORKER - ONE LOCK - ONE KEY.
When two or more people are working on the same equipment, both people lock out the affected equipment. By using the multiple lockout devices, several people can lock out the same equipment with their own safety locks.
The use of lockout is standard for all situations that require isolation protection. The step-by-step lockout process ensures that the equipment you are working on gets electrically isolated. It also takes into account other equipment that may be affected. '''Figure 9''' shows a typical electrical energy lockout verification flow path.
'''Figure 9: Electrical Energy Lockout Verification'''
Find the specific area or section of equipment where the work is to be done. Notify the affected employees that a lockout system is going to be used, and tell them the reason for it. Then, look around the area for any additional hazards such as traffic, trip hazards, construction, etc. It is important to always block off your work areas, and never leave them unattended unless the work and area are in a secure condition.
Identify the electrical system to be worked on by components. Use the appropriate technical documentation to locate and identify all approved isolating devices that supply the equipment to be locked out. Any circuits and equipment to be worked on must be disconnected from all energy sources by approved isolation devices, i.e., circuit breakers, fuses, or disconnect switches. Control circuit devices such as push buttons, selector switches, and interlocks may not be used as the only means for de-energizing circuits or equipment. Also note that more than one energy source (electrical, mechanical, or others) may be involved.
Always assume that lockout is needed. Lockout is not needed only when electrical energy is required to do your job. If lockout is not needed, proceed with your assigned task. Make sure you observe all of the necessary safety precautions.
Visually follow the lines from the component to the disconnect or point of lockout. This ensures that you will be locking out the correct equipment.
If the system supplies energy to more than one piece of equipment, you have to make arrangements before turning the supply off.
This may have to be coordinated between several people. Arranging turnoff ensures that other equipment is not de-energized unnecessarily.
Inform the equipment operator (if necessary) BEFORE you turn the power off and lock it out.
Before operating a disconnect to turn power OFF, always use the control stop buttons or selector switches to stop the affected machine. Next, ensure that the equipment has been shut down, and operate the switches, valves, or other energy isolating devices so that the equipment is isolated from its energy sources. Stored energy (such as that in springs, elevated machine members, rotating flywheels, hydraulic systems, and air, gas, steam, or water pressure, etc.) must be dissipated or restrained by methods such as repositioning, blocking, or bleeding down.
Never stand in front of the disconnect enclosure when operating a disconnect. Turn your head away, and position the disconnect device in one firm, positive motion.
A lock will be placed on each disconnecting means used to de-energize circuits and equipment on which work is to be performed. The lock will be attached so as to prevent persons from operating the disconnecting means unless they resort to undue force or the use of tools. To verify this, each employee who attaches a lock to a disconnect device must ensure that the lock physically prevents the device from being closed.
Each switchgear-mounted circuit breaker used for lockout isolation must be opened and racked out to the disconnected position. Afterward, approved safety locks will be installed to prevent the breaker’s reinsertion. When applicable, a sign should be hung on the breaker identifying its use as a lockout point. When the circuit breaker cubicle allows the breaker to be withdrawn, withdraw the breaker fully, and attach the safety lock on the cubicle door. Always follow the standard rackout and removal procedures that were supplied with the switchgear. In addition, ensure that the closing springs on the breaker have been discharged.
Once the appropriate disconnect devices have been opened and locked out, it may be necessary to release the stored electrical energy present before checking that the equipment is fully de-energized.
There a three ways to store electrical energy:
Capacitors and batteries store energy even after being disconnected from the source. They present an electrical shock hazard to personnel performing maintenance. To eliminate this shock hazard, capacitor-shorting switches are shut and batteries are disconnected to discharge the stored energy.
Induced voltages may be present in isolated equipment due to electrostatic coupling. Care should be taken to avoid this hazard until the equipment can be effectively grounded.
This is the most important step in the process. Manually test each electrical system after it has been locked out. (Activate ON/OFF switches, push buttons, controls, etc.) Look for any machine movement as you test the equipment.
After the electrical equipment to be worked on has been locked out, and no machine movement is noted when operating the equipment controls, the equipment must be verified de-energized before work can proceed.
First, and most importantly, only qualified persons may verify that a circuit or piece of equipment is de-energized.
Upon opening a control enclosure, the qualified person will note the presence of any additional components that may store electrical energy. Initially, these components should be avoided.
To verify that the lockout was adequate and the equipment is de-energized, a qualified person will use the appropriate test equipment to check for power, paying particular attention to induced voltages and unrelated feedback voltage.
In order to ensure that their voltage testing equipment is reliable, electricians must perform the live-dead-live check. To perform this test, first check your voltmeter on a known live voltage source. This known source must be in the same voltage range as the electrical equipment on which you will be working. Next, without changing scales on your voltmeter, check for the presence of power in the equipment you have locked out. Finally, to ensure that your voltmeter did not malfunction, check it again on the known live source. Performing this test will assure you that your voltage testing equipment is reliable.
Once it has been verified that power is not present, stored electrical energy that might endanger personnel will be released. Qualified persons will use the proper devices to release the stored energy, such as using a shorting probe to discharge a capacitor.
If there is machine movement, or the equipment has not been de-energized, zero energy state has not been achieved. This means that the sources of energy have not been properly disconnected. Go back to the block labeled TRACE ENERGY SOURCE, shown previously in '''Figure 9'''.
If zero energy state has been achieved, proceed to the next block in the flow path shown in '''Figure 9'''.
Check the work area for other types of energy such as pneumatic, hydraulic, gravity, and momentum.
Many qualified persons will feel safe when working on electrical equipment that has been locked out and checked de-energized in accordance with the procedures we have discussed. However, it is still possible for the equipment they are working on to become energized through electrostatic coupling, accidental re-energizations, or even strokes of lightning. If any of these events were to occur, the safety of the technician will be compromised. By using temporary cables to ground the electrical equipment that you are working on, you offer yourself another level of safety and peace-of-mind.
Temporary grounding is accomplished by intentionally connecting the underground phase conductors of isolated equipment to ground. After grounding connections are made, any potential that develops in these ungrounded conductors will be immediately shunted to ground.
Before attempting to install temporary grounds on any piece of equipment, the conductors that will be grounded must be DE-ENERGIZED and verified DE-ENERGIZED by a qualified technician using the appropriate test equipment. Verify that the equipment is de-energized in accordance with previous discussions.
The following precautions should be observed when installing temporary grounds:
When removing temporary grounds, remove in the reverse of installation, equipment first and ground last. Always wear the appropriate protective equipment when removing the grounds. It is extremely important that a tracking system be used to ensure that temporary grounds are removed prior to clearing lockouts and re-energizing equipment. Several instances of racking in circuit breakers with temporary grounds installed have caused equipment damage and personnel injury.
Perform the intended work. When you have finished, remove tools and equipment from the work area and replace any safety guards.
Once the work has been completed and before the electrical equipment can be re-energized, qualified persons must ensure that all employees are clear of any danger. This paragraph identifies the precise procedure to follow when circuits and equipment are re-energized, even temporarily.
If an employee is absent from the workplace when it is time to re-energize equipment on which he or she was previously working, then the absent employee’s lock or tag may be removed by another qualified person under the following conditions:
Look to see if anyone, including yourself, is in a dangerous position before restarting any equipment. Good communication is essential.
Remember, never stand in front of the panel when turning on an energy source.
The importance of maintaining electrical equipment cleanliness cannot be overemphasized. Most of the failures that occur in electrical equipment, beyond improper use, are due to the accumulation of dirt and foreign material. The effects of prolonged buildup can cause insulation deterioration, binding in operation, and development of corona discharge in high-voltage equipment.
Any time electrical equipment is down for repair or maintenance, cleaning should be incorporated as part of the action. Excessive use of cleaning solvents and de-greasers should be avoided when cleaning insulating materials; accumulations that are allowed to evaporate actually cause insulation deterioration. The best method of cleaning is to wipe down with clean rags or to vacuum clean. Never use volatile cleaning substances to clean a component that experiences arcing; this would present a serious fire hazard.
Lack of cleanliness can also present a personnel hazard because dirty connections develop high resistance. If you are relying on a ground connection, you want to ensure that the surfaces are clean and will definitely be of less resistance than your body.
An '''''electrical power system''''' can be defined as "a network of interconnected components that convert non-electrical energy into electrical energy and deliver it to a specified location." To expand on this basic definition, the transported electrical energy must also be transformed and regulated to meet specified tolerances to make it acceptable for use.
Human safety and prevention of property damage are the two most important factors in the design of a substation. The design engineer must always assume that the public, or others within the plant, are not aware of the dangers that are present in a substation. The engineer also needs to consider the safety of personnel who will be working on or around the electrical equipment in the substation.
The more simple a substation is designed to operate, the more safe and reliable it is to maintain and operate. As the equipment in the substation increases, it becomes more complex to operate, and correspondingly, the substation becomes less reliable.
Providing continuous power to loads is very important. Engineers call the ability to reliably supply power to a location, and they know that it is not possible to provide power to a load 100% of the time; therefore, the engineer must consider other factors in the design of the system. The level of reliability required is dependent on the facility. If a facility can remain without power for a long period, a less reliable system can be designed and installed. If a facility is critical in nature, redundant or parallel systems should be installed to improve reliability of the system. The following factors affect the reliability of the substation:
The design of the substation must consider the need for maintenance. The substation equipment must be easy to access, and space must be provided for inspection, adjustment, and repair of the electrical equipment. Maintenance is also a major safety concern for plant engineers.
The substation should include plans for expansion. The engineer needs to consider the plant voltages, equipment ratings, space for additional equipment, and the capacity for increased loads. Designing flexibility into a substation today could save many resources in the future.
In analyzing power systems, the reference is always system operating voltage. The various voltage levels are classified as low, medium, high, extra-high, and ultra-high.
Low voltage is 600 volts and below. It is typically used to supply nominal voltage directly to electrical loads. Common voltages in this voltage class are 120 V, 208 V, 277 V, 440 V, 480 V, and 600V.
Medium voltage is from 601 volts to 15 Kilovolts (kV). It is mainly used for distribution purposes and for supplying large electrical loads. Common voltages in this voltage class are 2.4 kV, 4.16 kV, 6.9 kV, 13.8 kV, and 15 kV.
High voltage is from above 15 kV to 230 Kv. It is mainly used for utility generation levels and transmission purposes. It is also used by some utilities as subtransmission. Common voltages in this voltage class are 22 kV, 25 kV, 34.5 kV, 69 kV, 135 kV, and 230 kV.
Extra high voltage is from above 230 kV to 800 kV. It is only used for bulk power transmission over long distances. Common voltages in this voltage class are 345 kV, 500 kV, 750 kV, and 800 kV.
Ultra high voltage is any level above 800 kV. This level is used in limited applications in the United States and only in the range from 1100 kV to 1,500 kV.
''Generation'' refers to "the production of electrical power." Generators represent the sources of electrical energy. The purpose of the generator is to convert energy from a non-electrical form into electrical energy and maintain a constant and regulated supply of this electrical power for transmission to all points of the power system.
The size of the generators in typical systems can range from 100 kilowatts to 1,300 megawatts of power, operating at voltage levels from 480 volts to 25 kV. Typically, utilities will generate at voltage levels from 22 to 25 kV.
The transmission network begins after the generation of the electrical power. At the generating stations, the voltage level will be increased from its generated level to a transmission level. This network must have the flexibility to route large blocks of power over a number of alternate routes. The design must be such that the loss of a few lines does not completely disable the system. Transmission lines also serve as ties to other systems over which power can be exchanged in both directions. These ties to other systems through their transmission systems are known as the "power grid."
Normal transmission voltage levels are in the UHV, EHV, and HV classes. These voltage levels are used because of the long distances that must be covered from generator to consumer. Transporting power at high voltages is much more efficient because of line losses and loading effects over long distances.
''Subtransmission'' designates the section of a power system between the EHV transmission and MV distribution. A subtransmission system is used to accommodate distribution substations and to further increase system efficiency by reducing the transformation levels.
The voltage of the subtransmission system is intermediate between the transmission and distribution voltages. Typical values range from 69 to 12 kV.
''Distribution'' refers to the "delivery section" of the power system. The power that is brought by the transmission or subtransmission system is transformed downward to voltages for delivery to the consumer’s location. This constitutes the "primary distribution" system.
The "secondary distribution" system provides the user with the specific voltage required for their application. The complexity of the design depends on the user’s needs, which may vary from a simple pole transformer to a complicated, grid-type network.
'''Figure 10''' shows the relation of primary and secondary distribution systems.
'''Figure 10: Power Distribution Systems'''
Three-phase, AC distribution systems may be divided into two general classes: the solidly grounded neutral system and the isolated neutral or ungrounded system. A modern modification of these two systems is the high-resistance grounded system.
A grounded distribution system has one conductor of the system solidly connected to a common system ground. The grounded system offers the advantages of greater safety to personnel and equipment, reduced exposure to over-voltages, and easier location of ground faults. Connection of a grounded system is shown in '''Figure 11'''.
'''Figure 11: Delta-Wye Grounded System'''
Accidental grounds in a grounded system generally cause the opening of circuit breakers or the blowing of fuses. In the case of high-resistance ground faults, the ground current may not be high enough to operate the protective device. However, the ground current created from a high-resistance ground fault may be sufficient enough to cause sustained arcing and burning of electrical equipment. The best protection against this is the use of a ground-fault relay. A ground-fault relay will sense low levels of ground current and actuate a protective function if the ground current exceeds a predetermined value. If the ground fault relay is not used, the circuit breaker overcurrent trips should be set as low as possible to provide protection. However, these same overcurrent trips must also be set high enough to prevent tripping the supply breaker in a high inrush current from system loads. This problem can make trip coordination very difficult.
An ungrounded distribution system has no deliberate electrical connection to ground. It’s most significant advantage is that an accidental contact between one line and ground does not cause an interruption of service. However, it is still important that this type of fault be cleared immediately. If not, a second ground fault would cause a direct short circuit of the system, tripping more than one circuit breaker and resulting in a more extensive outage. An illustration of an ungrounded system is shown in '''Figure 12'''.
'''Figure 12: Delta-Delta Ungrounded System'''
Another important point to remember is that if one phase of the ungrounded distribution system suddenly shorts to ground, a voltage imbalance will be felt with reference to ground. The grounded phase will exhibit the lowest potential, and the two ungrounded phases will be somewhat higher. This increases the electrical stresses in the ungrounded phase’s insulation and thus increases the possibility of insulation breakdown. See '''Figure 13'''.
'''Figure 13: Fault Effects on System Voltage'''
The voltage between each phase and ground is normally about 277 volts. When a ground occurs, the phase-to-phase ground voltage on the ungrounded phases will increase close to full phase potential to ground and cause the increase in stress on the insulation. If there is a weak area of insulation, it could fail, causing more damage to occur in the system.
As we have seen, a ground fault can cause two completely different actions, depending upon whether the distribution system is grounded or ungrounded. When a ground fault occurs in a grounded distribution system, a heavy inrush of current flows, the protective device closest to the fault should open to isolate it, and the location of ground fault is immediately known. Conversely, in an ungrounded distribution system, the occurrence of a first ground fault causes no immediate action, and there is no indication of where that ground fault may be. Furthermore, the occurrence of a second ground fault in an ungrounded system will cause a heavy inrush of current and usually result in an extensive outage. The point to remember is that in an underground system, there must be some means to identify that a ground fault has occurred, and once that indication is received, a large-scale effort must be commenced to locate and repair that ground before a second one occurs. The function of identifying that a ground does indeed exist is fulfilled by applying some sort of ground-detection circuit.
A typical ground-detecting circuit for a three-phase ungrounded system is shown in '''Figure 14'''. A step-down isolating transformer is used to provide low voltage for the ground indicating lights. The primary is wye-connected with a resistance-grounded neutral. The secondary is a grounded wye connection with indicating lamps parallel to each phase. With no ground on the system, all primary and secondary voltages are balanced and the lamps glow with equal intensity.
'''Figure 14: Three-Phase Ground Detection Circuit'''
If a ground occurs on Phase C, a voltage imbalance occurs in the primary, which will be felt in the secondary. This ground will effectively short-circuit the primary coil on Phase C, and no voltage will be dropped across the coil. Phases A and B lights will now glow brighter, and Phase C will be dimmer or completely dark, indicating the ground condition on Phase C.
In an attempt to design a grounding method that offers the advantages of both the grounded and ungrounded systems, the high-resistance, neutral-grounded system was developed. High-resistance neutral grounding has frequently been applied in processes and similar industries in the belief that delayed tripping of a critical process circuit will improve overall service continuity. The system accomplishes this by permitting an orderly shutdown under ground fault conditions. '''Figure 15''' shows a high-resistance grounded system.
'''Figure 15: High-Resistance Grounded System'''
The basic objective is to gain control of the system transient while minimizing the possibility of having service interruption. Since a second ground fault can shut down the entire circuit, it is advisable to complement this grounding method with ground detection and alarm devices and fault-tracing equipment.
When a ground fault occurs, a system with high-resistance neutral grounding avoids the arc blast of a solidly grounded system and minimizes the fault damage associated with arcing line-to-ground faults. Such faults, however, may develop into line-to-line faults if they are not cleared promptly. They may also be compounded by a similar fault on another phase, with subsequent arc damage quite like that with a solidly grounded neutral system. Furthermore, ground faults that have not been removed will continue to produce some damage at the fault point, and they may eventually become seriously damaging. On equipment with multi-turn coils, such as motors, such unremoved faults may cause eventual turn-to-turn failures and consequent severe damage (turn-to-turn currents are not limited by the grounding resistor).
The basic objectives for using the high-resistance grounded neutral system are:
An additional benefit is a reduction in voltage dip during ground faults, provided simultaneous ground faults on different phases are not encountered.
Effectively monitoring for ground faults with ground-detection equipment will lessen the probability of a second ground fault shutting down two circuits simultaneously.
Since un-removed ground faults in this type of system continue to liberate energy at the fault point, which may eventually cause further breakdown in the insulation system, it is essential to monitor the high-resistance grounded-neutral for ground faults, to trace them promptly with the fault locating equipment, and to remove them as quickly as possible. When a ground fault remains in this system, it loses its original characteristics and becomes essentially a "corner-of-the-delta" grounded system, with serious flash hazard, arc blast, voltage dip, and the probability of fault escalation if a second ground fault occurs.
Substations are commonly supplied by voltages ranging from 15 to 230 kV-class utility or user-owned distribution systems. '''Figure 16''' shows a basic power and transmission distribution system with the following types of substations:
A large or medium industrial substation is typically used to transform a higher utility voltage to a plant’s lower distribution or utilization voltage level. Industrial substations (medium and large) are normally dedicated to serve a single industrial plant with loads greater than 5 MVA and commonly include one or more transformers. Unit-type substation sizes typically range from 500 to 3,000 kVA.
'''Figure 16: Electrical Power System'''
Although a substation performs many functions, the five major functions consist of the following:
Voltage transformation from high to low voltage is accomplished in any one of several different ways, with the most common being a single three-phase transformer or three single-phase transformers. In industrial substations, a three-phase transformer makes a neater, more compact substation, reduces the number of bushings, fittings, cable connections, etc., and is typically easier to inspect and maintain.
Circuit switching can also be accomplished by several means. No-load switches, load-break switches, fused disconnect switches, and both low and medium voltage circuit breakers are the most common form of switching electrical circuits.
Most substations require some form of voltage regulation. Very large substation transformers use automatic 10% load tap changers (LTC), with 33 steps, each step 0.625%, to regulate the voltage. Most other substations use 5% no-load tap changers (NLTC), with 5 steps, each step 2.5%, to regulate the voltage. Very large utility transmission substations use separate voltage regulators to regulate the voltage. Voltage regulators are not often used in industry substations, but they are available if voltage problems warrant their use.
Volt-amps-reactive (VAR) control is the planned control of the reactive power (current) in an electrical system. VAR control of an industrial system is most often accomplished using power factor correction capacitors.
System protection is accomplished by means of fuses, circuit breakers, lightning arrestors, and protective relays. For example, an overcurrent relay (ANSI Device 51) protects the system from overloads and faults, whereas a lightning arrestor protects the transformer from overvoltages caused by lightning strikes or switching surges.
There are many ways of connecting substations to the primary distribution system and then arranging the secondary to supply the loads. The common circuit arrangements used for industrial application are as follows:
A simple radial system ('''Figure 17a''') looks like an inverted tree. A single primary service and transformer serve the entire load. There is no duplication of electrical equipment (cables, breakers, etc.), and the system is the least expensive of all of the types of circuit arrangements. The operation and expansion of the radial system is simple, and the reliability is high if high-quality components are used. Unfortunately, loss of a single cable, transformer, etc. will shut down the entire system. The equipment must also be shut down to perform routine maintenance. The simple radial system is an adequate power system circuit arrangement for most non-critical process loads.
The expanded radial system ('''Figure 17b''' and '''Figure 17c''') is just an expansion of the simple radial system, and it is used to supply power to multiple unit substations near major load centers. The advantages and disadvantages described for simple radial systems also apply to expanded radial systems.
'''Figure 17: Radial Systems'''
A primary loop is more reliable than a radial system. If one source feeder fails, the other source feeder supplies the load. The loop system is more dangerous to work on than the radial system because power is supplied from both directions to the load. Fault duties are typically double that of a radial system because the parallel feeders’impedance is 50% of the single radial feeder impedance. Loop systems provide greater reliability for critical loads because single faults will not isolate the system. Loop systems are also more expensive because of the duplication of equipment. Short-circuit studies performed on loop systems are much more complex because of the need to use directional relays. '''Figure 18''' shows two types of primary loop circuit arrangements. If any one of the normally closed (N.C.) switches shown in '''Figure 18''' are opened, the system reverts back to a simple radial system.
'''Figure 18: Loop Systems'''
Secondary loop is not an ANSI/IEEE preferred term. Secondary loop implies that the system is a secondary selective system with a normally closed tie breaker.
Selective system circuit arrangements are either primary selective, secondary selective, or a combination of both.
Loss of a primary source can be protected against by use of a primary selective system ('''Figure 19'''), where each transformer is supplied by two sources. Normal operation is to supply half the load (transformer) from one source, with the other source acting as the alternate (emergency) source. Switching of the load (transformer) over to the alternate source can be manual or automatic, but there will be a power interruption until the load is transferred to the alternate source.
'''Figure 19: Primary Selective System'''
If pairs of unit substation transformers(double-ended substation configuration) are connected through a normally open (N.O.) tie breaker, the system is called a secondary selective system ('''Figure 20a'''). Each unit substation normally carries half the load, and in the event of a failure of the normal source or for routine normal maintenance, the N.O. tie breaker is closed. If the substations are geographically remote from one another, two tie breakers are used for selective switching purposes, as shown in '''Figure 20b'''.
'''Figure 20: Secondary Selective Systems'''
The combined selective circuit arrangement system ('''Figure 21''') is simply a combination of both the primary and secondary selective systems. '''Figure 22''' illustrates an alternative type of combined selective system.
'''Figure 21: Combined Selective System'''
'''Figure 22: Alternative Combined Selective System'''
The main portion of switchgear is formed from heavy gauge steel welded with members across the top and bottom to provide a rigid enclosure. Most switchgear enclosures are divided into three sections:
These three sections are physically separated from one another by partitions. This is done to confine damage in one section and keep it from spreading. The number of sections and physical makeup will vary depending on plant specifications and the manufacturer. '''Figure 23''' shows an example of a typical switchgear arrangement.
'''Figure 23: Typical Switchgear Arrangement'''
To provide for ease of maintenance, switchgear assemblies are made with the capability to install, remove, rack in, and rack out circuit breakers and other devices from the switchgear while it is energized. Air circuit breakers normally have devices that accommodate three breaker positions: connected, test, and disconnected.
The circuit breaker and racking mechanism are interlocked so that if the circuit breaker is closed and you attempt to rack out the breaker from the connected position, it will trip the circuit breaker open. Another interlock used with circuit breakers prevents the circuit breaker from being racked in if the circuit breaker is in the closed position.
Transformers are usually found in all substations (except switching substations). They are devices used in AC power systems to convert electrical power at one voltage or current into electrical power at some other voltage or current. Transformers are reliable devices that can provide service for long periods of time if maintained and serviced regularly. Transformers have a wide variety of industrial applications; the most important is their use as power transformers in transmission and distribution systems.
Transformers operate on the principle of electromagnetic induction. Electromagnetic induction is the generation of a voltage in a conductor by the change in magnetic flux passing through it. In a transformer, alternating current from the power source flows through the primary winding, producing a magnetic field. The secondary winding is wound so that this flux passes through it. The two windings are then said to be inductively coupled, as shown in '''Figure 24'''. This flux, since it was produced by an alternating current, is constantly changing in magnitude and, therefore, generates a voltage in the secondary winding.
'''Figure 24: Inductive Coupling'''
The electrical energy is always transferred from the primary to the secondary winding without a change in frequency but usually with changes in voltage and current. A step-up transformer receives electrical energy at one voltage and delivers it at a higher voltage. Conversely, a step-down transformer receives energy at one voltage and delivers it at a lower voltage.
This action of step-up and step-down is accomplished by varying the number of windings of conductors in the primary (first coil) and the number of windings of conductors in the secondary (second coil). The varying of windings changes the amount of voltage that is generated by the primary and induced in the secondary. By maintaining a strict turns-ratio, we can determine the amount of voltage that will be induced in the secondary for a constant voltage being applied to the primary. This is expressed in the formula:
In a perfect transformer, the power measured on both the primary and secondary windings would be exactly equal. Unfortunately, there is no such thing as a perfect transformer. In a practical transformer, the power measured in the primary and secondary windings will be very close but not equal. There will always be a small power loss, which means that not all of the energy is transferred from the primary winding to the secondary winding. This loss of energy is a measure of the transformer’s efficiency. Transformer efficiency is the ratio of real output power (Pout) to real input power (Pin), expressed as a percentage. The real output power is simply the power rating of the load, whereas the inputs power is the sum of the output power plus the copper and iron losses of the transformer.
Copper losses are caused by the resistance of the primary and secondary windings (conductors) of the transformer. These copper losses are directly proportional to the magnitude of the load current squared (I2) multiplied by the winding resistance (R). Because the copper losses are directly proportional to the load current, they are often called load losses.
Iron or magnetic core losses are another type of losses that occur in a transformer. These core losses occur regardless of whether there is load on the transformer.
Eddy current losses are caused by the currents that circulate through the mass of the magnetic steel of the core. Because the magnetic core is laminated and oriented perpendicular to the path of the magnetic flux, the eddy currents are confined within small volumes. Lamination of the core effectively reduces the eddy current losses compared to the losses in a "solid" core.
Hysteresis losses represent the extra power that is required to overcome the small magnetism that resides after each reversal of the magnetic field (residual magnetism). Hysteresis loss is minimized by the use of silicon steel or amorphous steel as the material for a magnetic core.
The efficiency of a transformer changes as a function of loading and power factor. '''Figure 25''' is a plot of five different efficiency curves for five different conditions of lagging power factor and represents the performance of a typical power transformer. Note that the maximum efficiency is achieved at about half-load. This maximum efficiency at half-load is established by adjusting a balance between specific design variables related to the magnetic core and conductors. Efficiency variations are usually very small between different power transformers, and most power transformers are typically in the 98% efficiency range.
'''Figure 25: Transformer Efficiency'''
Transformers are generally classified by the following attributes where applicable to each transformer:
All transformers require some means of removing the heat produced during operation. The heat energy is from the I2R losses in the transformer windings and from the hysteresis and eddy current losses in the transformer core. If this heat energy is not dissipated in a satisfactory manner, the transformer would operate at an excessively high temperature that would eventually destroy the insulation of the transformer and cause a failure.
There are two types of classifications for cooling methods: liquid and dry type transformers. The dry-type can be self-cooled or forced air-cooled. The liquid-filled can be self-cooled, forced air-cooled, forced oil-cooled, or water-cooled. Within the classification of liquid-filled is the gas-cooled type.
Self-cooled transformers use the natural circulation of hot air to create an air draft and liquid flow.
Designations for the type transformer and cooling method are given below:
Two liquids have been used extensively in the past for transformers: mineral oils and polychlorinated biphenyls (PCB), commonly known as Askarel. Askarel is a non-biodegradable fluid and highly toxic. Its use is severely restricted, and its availability for use in new applications is almost nonexistent. Newer silicone-based and pure hydrocarbon fluids, such as RTEmp, have been used in place of Askarel.
Gas-cooled transformers can contain several types of gas, but the major types in use now are sulphur hexaflouride (SF6) and Freon™.
Insulation of transformer coils from each other and from the core is performed in two different ways: dry-type insulation and insulating oil.
Dry-type insulation used in transformer design and construction has a definite bearing on temperature and size of the unit. The higher the insulation, the higher the temperature rating and the higher load that can be supplied.
Insulating oil used with the dry insulation adds to the unit’s dielectric strength, but its function of increasing heat removal is a key. Even with oil added for increased insulation strength, the transformer cannot exceed the temperature rating of the dry-type insulation.
Transformers can be classified as single-phase or polyphase. Since there are numerous possible arrangements of the coils and cores in constructing a polyphase transformer, it can be stated that a polyphase transformer consists of several single-phase transformers.
Transformers are constructed with different types of metal-enclosed framework, but they are designed for mounting in one of the following ways:
Transformers are classified according to the service they perform. Some common service classifications are:
The power transformer is used to step up voltage to transmission levels. The distribution transformer is used to step down voltage to a usable consumer level. The instrument transformer is used to step down voltages to a safe level for use in indicating and protective devices.
There are two common connection methods for polyphase transformer windings: wye and delta connections. The use of these two connections will determine the operating characteristics of the transformer.
The wye (or star) connection shown in '''Figure 26''' shows that each winding is connected to a common point. This common point is termed "neutral" and is often used for a grounding connection. The other end of each winding is connected to a phase conductor.
The main advantage of this type connection for a system is that any phase to neutral or ground can be used as a single-phase power source. It also provides the added advantage that ground fault currents are limited because only the grounded phase will be affected.
'''Figure 26: Three-Phase Circuit Wye Connection'''
The delta connection shown in '''Figure 27''' shows that each winding is connected to the ends of the other windings. The junction points are then connected to a phase conductor for an output. The main advantage of this type of connection is that a transformer can be made smaller because less winding conductor is needed for the same load carried in a wye connection. This is because less current flows through the individual windings of a delta connection than that of a wye connection.
'''Figure 27: Three-Phase Circuit Delta Connection'''
The connections used in the primary and secondary of a transformer can vary depending on the intended use. Connections of the transformer windings should never be disturbed during a normal maintenance action; it can result in changes of the protection provided for the transformer. '''Figure 28''' shows the most common types of transformer connections used in power systems.
'''Figure 28: Three-Phase Transformer Connections'''
Transformer terminal board connection markings are shown in '''Figure 29'''.
'''Figure 29: Transformer Terminal Markings'''
Power transformers are equipped with devices that allow voltage control and monitoring of operating conditions and provide protection in the event the transformer fails. The most common accessories are as follows:
Often it is desirable to change, by a relatively small amount, the voltage ratio of a transformer. This voltage ratio change is done to compensate for the voltage drop in the supply source or to accommodate a change in the load. Most transformers have a device or method to change the voltage rating of one or both of the transformer windings. To change the voltage relationship, the ratio of the turns between the winding must be changed. Changing the turns ratio is exactly what a tap changer does; it adds or subtracts transformer winding turns.
The simplest type of tap changer is one that brings taps from one or both windings to a terminal board where jumpers can be manually reconnected. Dry-type transformers will normally have this jumper board located inside of the winding enclosure or in an adjacent compartment. In small, liquid-filled transformers, the tap connection board is usually located just below the surface of the oil, which requires removal of the tank cover and manual changing of the jumpers. For larger, liquid-filled transformers, the manually connected jumpers are replaced with a rotating switch that is manually operated from outside of the tank ('''Figure 30'''). For all of these types of tap changers, the transformer must be de-energized before the connections or taps can be changed. These types of tap changers are known as NLTC or no-load tap changers. They are also called DETC or de-energized tap changers; both terms are commonly used.
A second type of tap changer is one that allows the taps to be changes while the transformer is still energized and under load. Typically, this type is applied to the voltage regulator applications where the maintenance of voltage is of paramount importance. This type of tap changer is known as a load tap changer or an LTC.
'''Figure 30: NLTC Set at Position #5'''
The no-load tap changer (NLTC), as its name implies, requires that the transformer load be de-energized (no-load) before changing the taps. It is typically used for applications that require only infrequent tap changes or adjustments and where the transformer can be disconnected from the line. The NLTC must never be operated while the transformer is energized because it has no capability of interrupting load current.
An NLTC adds or subtracts turns in the high-voltage winding of the transformer. The standard arrangement includes five tap positions, with the middle position being the rated voltage position. There are two tap positions above the rated voltage position and two below. Each tap selection represents a terminal-to-terminal voltage that is normally different by an amount equal to 2.5% of the rated voltage. The nameplate voltage associated with each tap selection represents the voltage that is needed at the high-voltage terminals to produce rated voltage at the low-voltage winding terminals, whenever that tap is selected, and with a condition of no-load current. The five positions thus provide a range of+5 and -5% from rated voltage.
The location and placement of taps within a winding are constructed with care to avoid potential physical and electrical problems. Normally, taps are not placed in the end of a winding because this would make the winding physically and electrically unsymmetrical, causing increases in the stray losses and the mechanical forces. As a result, taps are normally placed in the center of a divided winding.
One problem with the NLTC is that the transformer must be de-energized to change the taps, which means that the power must be turned off, subsequently disconnecting service and shutting down the operation of equipment. In many cases, the user does not want, or cannot permit, the power to be shut down. Typical examples are large users of power with transformers that feed industrial plants, or large distribution systems that provide power to critical services (e.g., hospitals, schools, etc.). For cases where power must be maintained while adjustments are made to the voltage level, a load tap changer (LTC) must be used.
The most important advantage of an LTC is that it allows changing of a transformer’s turns ratio (adjusting voltage level) without shutting off the power. Another difference of the LTC, when compared to the NLTC, is that it is located in the low-voltage winding of the transformer, and it accomplishes voltage adjustments by changing the number of turns in the low-voltage winding.
Normally, load tap changers have 16 steps or taps above and 16 steps below the normal-rated voltage level, resulting in a total of 33 tap positions. The preferred step change for each tap is 0.625% of normal-rated voltage, which provides an adjustable voltage range of 10% above and 10% below the normal-rated voltage (16x0.625%=10%).
In accordance with ANSI/IEEE C57.12.10-1988, liquid-filled transformers supplied with an LTC are required to have a tap position indicator similar to the design shown in '''Figure 31'''. The indicator must be fitted with hands to indicate the maximum and minimum positions used, and it must be located so that it can read while operating the tap changer by hand. The face of the indicator must be marked to show the normal-rated voltage (N - neutral) position, the 16 steps of the raise range marked with an "R" and the 16 steps of the lower range marked with an "L."
'''Figure 31: Position Indicator for LTC'''
Heat is a natural enemy to winding insulation. As a result, designers determine and specify the maximum temperature at which windings may operate and still achieve normal expected service life. For liquid-filled transformers, the rated maximum hottest-spot winding temperatures are 95C and 110C. For dry-type transformers, the maximum hottest spot temperatures range from 130C to 220C. The winding temperature indicator is a device that monitors a winding’s hottest-spot temperature and, as needed, sounds an alarm or turns on additional cooling equipment. The method varies depending on whether the transformer is a dry-type or liquid-filled transformer.
For dry-type transformers, a thermal sensor is appropriately insulated and is directly placed at the estimated hottest-spot location in the low voltage windings. The sensor is connected to a dial-type indicator that is mounted to the outside of the enclosure where it is readily visible to maintenance personnel. In addition to the (black) temperature indicating pointer, the dial typically has a second resettable (red) pointer that is used to indicate the maximum temperature attained since the last time it was reset. The temperature scale that is marked on the dial is well above the hottest-spot temperature rating that could possibly occur. Winding temperature indicators for dry-type transformers may have scales that extend to 270C, depending on the temperature rating of the transformer. Alarm and/or control switches may be included in the dial assembly to sound alarms or to switch on bands of cooling fans. A typical winding temperature gauge is shown in '''Figure 32'''.
'''Figure 32: Winding Temperature Indicator'''
For liquid-filled transformers, it is not practical to pass a sensor through the tank wall and attach it to the windings. For this reason, a different method is used to monitor the winding hottest-spot temperature. Typically, the temperature is measured by placing a thermal sensor (i.e., thermometer bulb, bimetallic element) in a metal thermometer well together with a heating coil. The thermal sensor is connected to a dial indicator located on the tank wall at eye level for convenient reading. The meter thermometer well is located in the hottest oil near the top of the transformer. Per ANSI/IEEE Standard C57.12, the thermometer well is required to be placed in the tank at least one inch below the liquid level at minimum operating temperature (-20C).
Current proportional to the transformer load current is supplied to the heating coil through a current transformer (CT), which is typically one of the bushing CTs. The increment of temperature provided by the heater adds to the temperature sensed by the thermal element from the hot oil to give a dial indicator reading that is equal to the winding hottest-spot temperature. In this manner, the device is able to indicate the winding hottest-spot temperature for any constant load.
The temperature marked on the indicator is above the transformer’s hottest-spot temperature rating based on the transformer’s application and rating. Typical indicators for liquid-filled transformers have scales that extend to 120C and 160C, although some indicators have higher scales.
The liquid temperature indicator ('''Figure 33''') is a device that measures the transformer’s top liquid temperature. It is typically constructed of a stem-type, bimetallic element housed in a weatherproof casing. The stem fits closely into a thin-walled well and screws into the side of the tank. Use of the metal thermometer allows the thermal unit to be removed for inspection or calibration without loss of liquid, and with no need to lower the liquid level.
'''Figure 33: Liquid Temperature Indicator'''
In accordance with ANSI/IEEE Standard C57.12, the thermometer well is required to be placed in the tank at least 1 inch below the liquid level at minimum operating temperature (e.g., -20C). ANSI/IEEE Standard C57.12 requires that the indicator face be mounted vertically when located at heights of 96 inches and below, and angled down at 30 when mounted higher.
Per standards, the indicator is required to have a dark-face dial with light markings, a light-colored indicating hand, and an orange-red, resettable maximum indicating hand. The standards additionally require that the dial indicator have a diameter of 4-1/2" 1", with a temperature range of 0C to 120C, and have the words "Liquid Temperature" on the dial face or on an adjacent nameplate.
Liquid temperature indicators typically come with two built-in control microswitches set to operate at different temperature levels. The lower temperate switch is set to control the fan circuit and to turn on the cooling fans when the transformer’s temperature comes within range of the switch setting. The higher-temperature switch is designed to operate an alarm and give warning if, for any reason, the fans do not limit the temperature to the proper range. However, it should be noted that the function of controlling the cooling fans is normally handled by the winding temperature indicator. The liquid temperature indicator is connected and used to control the cooling fans only when there is no winding temperature indicator installed on the transformer.
The liquid level indicator is a self-contained, float-type device that indicates the transformer liquid level. The construction is a two-part assembly. One part is a sealed body attached to the tank wall with an actuating magnet shaft and float arm located inside the transformer. The other part is the bezel ('''Figure 34'''), or outer assembly, containing the calibrated dial and indicating needle. The indicating needle is directly connected to a second magnet that is positively displaced by the rotation of the magnet and the float arm assembly that is inside the tank.
In accordance with ANSI/IEEE Standard C57.12, the dial is marked to show the 25C liquid level. It is also required to show, by a permanent marking on the tank or an indication on the nameplate, the distance from the liquid level to the highest point of the hand-hole or manhole flange surface. The 25C mark also indicates the normal level for the liquid when it is at a temperature of 25C. As the liquid warms during transformer operation, its volume will expand (the volume of oil expands approximately 5% when heated from 25C to 85C). Because the surface area for the liquid remains the same, the change will take place in the height or level of the liquid. In a similar manner, as the liquid cools, its volume decreases, and its level goes down. The maximum or "HI" level mark indicates the correct level for the liquid when it is operating at its maximum rated temperature. The minimum or "LO" level mark indicates the correct level for the liquid at its minimum rated operating temperature.
'''Figure 34: Liquid Level Indicator'''
The pressure/vacuum gauges shown in '''Figure 35''' indicates whether the gas space in a transformer tank is under positive or negative pressure. Most liquid-filled transformers are sealed to prevent the entrance of oxygen, moisture, and other harmful contaminants. The gas space above the liquid is then normally filled with nitrogen to a pressure of 3 psig at a 25C liquid temperature. However, after the initial filling, the pressure will vary depending on barometric pressure and the temperature inside the transformer. If the transformer is de-energized or operated under light load in low ambient temperatures, the pressure might turn negative. A positive pressure (minimum 0.5 psig) should always be maintained to prevent breathing in moist air through potential leaks in the seals.
'''Figure 35: Pressure/Vacuum Gauge'''
In accordance with ANSI/IEEE Standard C57.12, the pressure/vacuum indicator is required to be a dial-type gauge with a diameter of 3-1/2" 1/4", have a dark face with light-colored markings and pointer, and have a scale with a range of 10 psig. This gauge type of indicator will very often have two alarm microswitches set to operate at approximately 8.5 psig on the pressure side and -1.5 psig on the vacuum side. On oil-filled transformers, the pressure/vacuum indicator is normally furnished in combination with a pressure regulator that will automatically bleed off excess pressure or add make-up gas.
Typically, transformers rated above 2500 kVA are furnished with a pressure relief device, sometimes referred to as a mechanical relief device (MRD), mounted on the transformer cover. '''Figure 36''' shows a pressure relief device. The device consists of a self-resetting, spring-loaded diaphragm and mechanical operation indicator (semaphore). Should the tank pressure increase above 10 psig, the gas pressure will lift the diaphragm and vent the excess pressure. Immediately after the pressure returns to normal, the diaphragm will reset and reseal the transformer.
'''Figure 36: Pressure Relief Device or Mechanical Relief Device'''
The mechanical operation indicator is a lightweight plastic semaphore that rests on the diaphragm. When pressure increases and the diaphragm rises, it lifts the semaphore into view and indicates that the relief device has operated. Although the relief device resets and reseals automatically after each operation, the semaphore remains in the tripped (visible) position until manually reset.
For some transformer installations, a vent hood is bolted over the pressure relief device with an exhaust pipe connecting it to an outside area. The purpose of the vent hood is to allow any toxic and/or combustible gases, released by the relief device, to be carried outside of a vault or building. As a precaution, personnel should not enter a vault or any confined area in which a transformer relief device has been known to operate or in which a transformer has failed until the area has been thoroughly ventilated. Gases released from a transformer can be toxic and life threatening.
When a transformer is to be pressure tested for leaks at a pressure greater than 8 psig, the relief device must be replaced with a blind flange. On the other hand, the typical relief device will withstand full vacuum and does not need to be removed from the transformer tank during any vacuum treatment. Should disassembly of the relief device be necessary, caution must be taken to guard against injury to personnel. The pressure-releasing springs are under tension, and if this tension is not carefully released, the force from the springs could cause the cover to blow off.
Similar to the other indicators and devices attached to a transformer, the pressure relief device is sometimes supplied with alarm contacts for use in triggering remote indicators to alert maintenance personnel that the pressure device has operated.
The sudden pressure relay (SPR), as shown in '''Figure 37''', is a device designed to respond to a sudden increase in gas pressure in power transformer, which is typically caused by internal arcing. An SPR normally consists of three main parts: a pressure-sensing bellows, a microswitch, and a pressure-equalizing orifice. The relay is typically enclosed in a sealed case and is mounted on top of the transformer with its pressure sensing element in direct contact with the gas cushion of the transformer.
'''Figure 37: Sudden Pressure Relay (SPR)'''
When an arcing internal fault in the transformer produces an abnormal rise in gas pressure, the bellows expands, causing the microswitch to operate, which in turn signals a circuit breaker to trip and clear the fault.
Under fault conditions, the rate-of-rise of gas pressure in a transformer is proportional to the arc power and inversely proportional to the volume of the gas space. The SPR operates on the difference between the pressure in the gas space of the transformer and the pressure inside the relay. The SPR is constructed to be very sensitive to rapid pressure change, and it will normally operate within 3 to 4 cycles (0.049 to 0.066 seconds) in response to a pressure rise of 5.5 psi per second. At high rates of rise, 30 to 40 psi per second, the SPR will operate in as little as 1/2-cycle (0.008 seconds).
For normal pressure changes resulting from changing ambient temperatures or load conditions, the equalizing orifice allows the pressure within the relay to equalize with the pressure in the transformer. This prevents any operation of the relay due to slow pressure changes.
A liquid-filled transformer typically has two valves for handling the fluid. One valve is located at the top of the tank, slightly below the normal oil level, and it is referred to as the upper fill (and filter) valve. The other valve is positioned at the bottom of the tank for draining (and filtering) the fluid and it is typically called the drain valve.
In accordance with ANSI/IEEE C57.12, the lower combination drain and filter valve must be located on the side of the tank, and it must provide for drainage of the liquid to within 1 inch of the bottom of the tank. The drain valve must have a built-in, 3/8-inch sampling device located in its side between the main valve seat and the pipe plug. The sampling device must be supplied with a 5/16-inch 32 male thread for the user’s connection, and it must have a thread-protecting screw-on cap.
The size of the drain valve must be 1 inch for transformers through 2,500 kVA and 2 inches for larger kVA ratings. Transformers rated through 2500 kVA must have a 1-inch upper fill (filter) plug or cap located above the maximum liquid level. Above 2,500 kVA, transformers must have a 1-inch fill (filter) valve located below the 25C liquid level.
Circuit-interrupting equipment is installed in the plant or electrical system to give control of the electrical supply to any equipment or groups of equipment. The circuit-interrupting devices are designed to switch power on or off and to automatically operate should an overload or other intolerable condition occur. Circuit-interrupting devices fall into three groups or classes: fuses, switches, and circuit breakers.
Fuses are usually installed in a circuit to protect the conductors, the device, and the switchgear from short-circuit currents. Some types of fuses are time-delay, or "slow-blow", for motor protection. Other types are current-limiting in that they blow very fast under very high fault current conditions. Fuses operate one time and then must be replaced.
Switches are devices that are used to isolate a circuit or piece of equipment. Almost all switches are manually operated, and most have spring-loaded, quick-acting, fast-make/break mechanisms. Switches are generally not designed to be opened under fault conditions. In addition, some switches are designed to be non-load-making and require interlocking with the downstream protective devices.
There are several different types of switches defined in the IEEE C37 standard, but this section will focus on the following types:
An isolating switch does not have an interrupting or load-breaking capability. The only purpose of a disconnect is to provide isolation of a circuit or load. An isolating switch cannot be operated until all current has stopped flowing in the circuit, which means that another device must be used in the circuit for protection and interruption of the load. An isolating switch is always operated manually and usually does not have a quick-acting mechanism.
Load-interrupting switches can be divided into two types: low-voltage and medium-voltage. The major difference between them is that low-voltage switches generally do not have any arc arresting features and are air-break. Medium-voltage switches can be air-break or liquid-filled. Both types are designed to interrupt normal load currents only and not fault currents.
These switches are also known as safety switches and are used primarily for stopping motor-driven equipment in an emergency. They can be fused or unfused, and they are rated in horsepower, current, and voltage. The switch can safely interrupt the stall or locked rotor current of the motor, which is about six times full load current for a three-phase, AC, induction motor. Safety switches are required to be able to interrupt at least 125% of the expected continuous load current.
Medium-voltage, load-interrupting switches are used for de-energizing medium-voltage loads and switchgear equipment. They are fused to provide short-circuit protection. These switches can be assembled as individual switches or combined into a distribution line-up, where they can be mechanically interlocked with other switching devices.
To ensure fast closing and opening speed, the switch mechanism is a stored-energy device that uses a large spring that is compressed by the operating or charging handle. Once charged, the spring is released and operates the switch. This spring action occurs both when closing and opening the switch. The design for most switches allows for few operations, about 500 in most cases; therefore, a switch should not be used in applications where frequent operation is required.
Air-break switches have two sets of contacts: the main contacts and arcing contacts. The main contacts carry the load current, and arcing contacts interrupt the current. In an opening operation, the main contacts open first, transferring the load current to the arcing contacts. At a preset point in the operation, the arcing contacts open at very high speed, interrupting the current. The resulting arc is extinguished by an arc chute.
Liquid-filled switches have operating mechanisms similar to air-break designs, but they do not need arc chutes or arcing contacts. The insulating and heat-dissipating qualities of the liquid are sufficient to extinguish the arc.
Magnetizing current-break switches are constructed similarly to load-interrupting switches. They are designed to interrupt the magnetizing (inrush) current of a transformer, which is about 8 to 12 times the primary full-load amperes rating of the transformer. The load must be removed (secondary main breaker opened) before operation of a magnetizing current-break switch.
Circuit breakers are the only circuit-interrupting devices that combine full fault-current interruption capability and the ability to be manually or automatically opened or closed. Circuit breakers are designed to interrupt either normal or short-circuit currents. The circuit breaker is the most flexible and practical interrupting device to use.
According to the IEEE (Institute of Electrical and Electronics Engineers), a circuit breaker is defined as "a mechanical switching device capable of making, carrying, and breaking currents under normal circuit conditions and also making, carrying for a specified time, and breaking currents under specified abnormal circuit conditions such as those of a short circuit."
Circuit breakers are classified by interrupting medium. The four general classifications of circuit breakers are as follows:
The basic construction of any circuit breaker includes a support assembly that houses the main contacts and auxiliary or arcing contacts, the arc extinguishing devices (air chutes etc.), an operating mechanism, and, a protective device on low-voltage units.
The most frequently used breaker for medium-voltage applications is the air-magnetic breaker. Its name comes from the fact that the contacts are in air, and a magnetic field is used to help elongate the arc and pull the arc into the arc chute. Air-magnetic circuit breakers are often called ''air circuit breakers''.
Air circuit breakers (ACBs) are physically quite large and are mounted on wheels to permit movement. A typical breaker may be 3 feet wide, 6 feet high, 3.5 feet deep, and weigh close to 1,500 pounds. The circuit breaker has a steel frame that supports the operating mechanism and the current-carrying parts. The size of the breaker depends on its voltage, current, and interrupting ratings. The operating mechanism is a stored-energy mechanism.
The arc chutes, or arc interrupters, of ACBs must be able to handle very large amounts of energy. The arc chutes are very large, and the arc-splitter plates are made of ceramic, not metal, because metal arc chutes would melt due to the amount of energy released during arc interruption. The arc is drawn up into the arc chute by its own magnetic field and also by a field generated from an electromagnet built into the sides of the arc chute. This electromagnet is called a ''blow-out coil''. As the arc is drawn up into the arc chute, the arc is elongated, cooled, deionized, and extinguished.
When an ACB opens under low current, such as rated continuous current, there may not be enough energy for the arc to rise up into the arc chute. To prevent this from happening, many breakers have a built-in device called a puffer. A puffer is a piston in a plastic tube connected to the breaker operating mechanism. When the breaker opens, the piston moves and forces a puff or blast of air through a plastic tube to the area where arcing starts, which forces the arc up into the arc chute.
Most manufacturers no longer make medium-voltage, air-magnetic circuit breakers. Vacuum circuit breakers have become the standard for medium-voltage applications.
The oil circuit breaker (OCB) is probably the most common type of circuit breaker found in large outdoor substations. Mineral oil is used as the insulating and arc interruption medium. On arc interruption, the oil quickly extinguishes or quenches the arc. All main power electrical components are immersed in a tank filled with mineral oil. Depending on the breaker rating, all three phases may be in one oil-filled tank, or each phase will be in a separate oil-filled tank. At the higher voltage rating, there may be in excess of 1,000 gallons of oil in each tank. Oil circuit breakers have an excellent history of performance. Their major disadvantage is the use of mineral oil, which is flammable and requires periodic testing and maintenance. OCBs are applied at voltages ranging from 34.5 to 345 kV.
Vacuum circuit breakers are used in newer power distribution systems. These breakers are of draw-out construction designed for use in medium-voltage, metal-clad switchgear. They consist of five major parts:
An air-magnetic circuit breaker is very large and heavy. The arc chutes are costly and can weigh up to 250 pounds. Extinguishing a powerful high-voltage arc of ionized gases is very difficult. It is much simpler to extinguish an arc in a vacuum since there are no gases to ionize. The arc in a vacuum consists only of vaporized metal from the contacts.
A circuit breaker using vacuum interrupters, or "bottles", is much simpler in design than an air-magnetic circuit breaker. It is more compact since there are no arc chutes. The operating mechanism is much simpler since the contacts only separate about half an inch.
The vacuum bottle consists of a pair of contacts surrounded by a vapor-condensing shield. The contact at one end is fixed in position, and the other is connected to a flexible metallic bellows to allow for the contact travel. The entire assembly is sealed in a vacuum-tight enclosure. The arc is extinguished the first time the current passes zero after the contacts part.
One major concern in applying vacuum interrupters is what could occur if an interrupter lost its vacuum and tried to interrupt a fault current. Loss of vacuum would probably destroy the vacuum interrupter, but most manufacturers state the damage would be confined to the interrupter. The breaker’s phase-to-phase and phase-to-ground insulation would prevent further damage to the breaker.
Vacuum interrupters require very little maintenance. Contact erosion, which occurs during each interruption, is slight, and the interrupters should last the normal life of a breaker. Since it is impossible to visually inspect the contacts, a method to check contact erosion is provided by the manufacturer. Periodically checking vacuum integrity by applying an AC high voltage across the open contacts is the only other maintenance requirement for the vacuum circuit breaker interrupter.
Another type of breaker commonly used is the gas circuit breaker. The gas circuit breaker is quickly replacing the oil circuit breaker. Sulfur-hexaflouride (SF6) is a gas with excellent insulating and arc-interrupting properties. SF6gas is inert, nonflammable, nontoxic, and odorless.
The contacts of an SF6gas circuit breaker are contained within a sealed tank in which SF6gas is maintained at a pressure of about 75 pounds per square inch. The breaker is designed so that when the contacts separate, there is a pressure buildup of gas around the parting contacts. This high-pressure gas sweeps away the hot arc gases, stretches and cools the gases, and finally extinguishes the arc. SF6circuit breakers are commonly found at voltage levels ranging from 34.5 to over 700 kV. SF6breakers also are becoming more readily available for medium-voltage applications.
The operating mechanisms of a circuit breaker must be designed to ensure positive or definite opening of the circuit breaker, and circuit interruption must occur whether the tripping or opening signal is received with the circuit breaker fully closed or in any partially closed position. The operating mechanism must also be capable of closing, re-closing, and latching the circuit breaker closed.
The term "operation" is intended to cover tripping, closing, and re-closing of the circuit breaker. Most low-voltage circuit breakers use three-pole operation. This causes the simultaneous opening or closing of all three poles.
There are five basic types of low-voltage circuit breaker mechanisms: manually operated, manually charged spring-operated, solenoid-operated, motor-operated, and motor-charged spring-operated mechanisms.
Manually operated mechanisms are available on small circuit breakers. They use a lever-operated toggle mechanism that releases energy from a relatively small spring. They may or may not have tripping capability. If they cannot trip, a backup protective device is applied. Molded case breakers are good examples of breakers with a manual operating device.
Manually charged spring-operated mechanisms have limited use. Applications where re-closing is not required would be suitable for this type of mechanism. Compression of a spring to store the closing energy is accomplished by using a hand jack, which may be portable or integral with the operating mechanism.
There are two types of solenoid-operated mechanisms: voltage-operated and current-operated.
Voltage-operated solenoids (AC and DC) are effective but relatively slow compared to other operating methods. They require a large-capacity power source. Capacitor trip devices can be provided to operate the solenoid.
Current-operated solenoids, supplied with current from bushing type or separate current transformers, are available on the smaller circuit breakers. Like the capacitor trip devices, they are very useful in isolated areas where a separate operating power supply is not desired.
Motor-operated mechanisms can be AC and DC and usually of a high torque and high speed to drive a spring-loaded toggle to provide closing speed.
Motor-charged spring-operated mechanisms use a motor to compress a coil spring that holds this stored energy until a closing signal is received. The spring expands to close the circuit breaker and simultaneously charge or compress a smaller coil spring, which is used to trip the circuit breaker. The breaker mechanisms provide high-speed closing and tripping.
The operation of the contacts in a circuit interruption is critical to the rating, performance, longevity, and safety of the breaker. The contacts have two vital but opposing functions.
First, the contacts must have minimum resistance across their junction when the breaker is closed. If electrical continuity is not maintained to a very high degree, excessive localized heating at the contact tips will result. This can be followed by degradation and even failure of the interrupter’s insulation medium, the contacts themselves, or both.
Second, when the breaker is tripped, the contacts must provide a very high resistance between themselves, while at the same time being exposed to the super-hot arc. Each operation of the breaker produces unavoidable damage to the contacts; therefore, it is necessary to perform periodic maintenance on the breaker based on the number of interruptions endured by the contacts.
Another consideration in the design of the contacts centers on the requirement that the contacts must move apart. Usual practice is for one contact to be movable and the other to be stationary. The connections between the stationary contact and its external bushing are rigid and relatively simple. The bushing to moveable contact connection is more complex, requiring that good conductivity and insulation be maintained through either a hinge or a flexible connection.
There are two principal types of circuit breaker contacts: butt and wedge.
Butt contacts consist of two solid elements with flat or curved mating surfaces. Silver-plating the mating surfaces reduces contact resistance and reduces heating and pitting. This is the simplest and also the lower rated contact design. Both normal closed position current flow and trip arcing are passed through the same surfaces.
Wedge contacts are commonly used in air-break circuit breakers. The wedge is squeezed into spring jaws when the breaker is closed, providing a good area for the contact pressure. Forcing the wedge between the spring jaws also produces a wiping motion that maintains a clean surface on both of them. Arcs are normally drawn on the top of the blade, thus protecting the actual contact area from the damage.
The moving contacts are usually made of hard copper alloy with renewable arcing tips. The stationary contacts consist of fingers arranged in pairs so that they may surface well on both sides of the moving contact when the breaker is closed. Flat springs on the fingers permit the contacts to align themselves automatically on the wedge so that full current-carrying capacity can always be obtained.
The purpose of a protection system is to maintain electrical service under normal conditions while minimizing damage and providing for quick power restoration under abnormal conditions. To accomplish these goals, relay set points and fuse ratings are carefully selected to ensure that protective actions only initiate during a fault and that only the device nearest the fault initiates a protective action. This results in what is called ''selective tripping''.
A fuse is a device that protects an electrical circuit by fusing (melting) open its current-responsive element when an overcurrent (low magnitude) or a short-circuit current (high magnitude) passes through it.
A fuse has the following functional characteristics:
IEEE standard C37.100 - 1981 defines a protective relay as "a relay whose function is to detect defective lines or apparatus or other power system conditions of an abnormal or dangerous nature and to initiate appropriate control circuit action." In other words, a relay triggers a protective response when it senses a fault. Relays can be used to monitor a variety of parameters such as voltage, current, and temperature. They can provide alarms and warnings, and they can control many different types of equipment. Because of their versatility, relays form the backbone of power distribution protection systems.
Relay protection systems are organized into zones, with each zone protecting a section of a bus or a piece of equipment such as a transformer. Zones are generally designed to overlap in order to provide protection if a relay fails. The kind of equipment in the zone dictates what types of relays are used to protect it. For example, a transformer zone might use a current differential relay and a temperature relay to control it feeder breaker, while a power cable zone might use phase differential and ground fault relays to protect it. '''Figure 38''' shows a generic protective relay setup. All relay systems have five parts in common:
'''Figure 38: Protection System Components (Subsystems)'''
Sensors provide a relay with information on conditions in the power distribution system. Examples of sensors are current and voltage instrument transformers, pressure transducers, and thermocouples. The relay initiates a protective action based on input from its sensors. Sensor performance is critical, especially for instrument transformers, because the relay is only as accurate as it sensors.
Current transformers are the most common type of relay sensor. They almost universally have five-amp secondary ratings and are designed to accurately reproduce the primary current in both wave shape and magnitude.
Although relays are the "brains" of the protection system, they are low-energy devices and are incapable of clearing or isolating system faults by themselves. The relay controls other pieces of equipment ("the muscle") such as radiator fans and coolant pumps. The circuit breaker is the most common device controlled by protective relays. Modern medium-voltage breakers can interrupt fault currents on the order of 100 kA at system voltages up to 800 kV. The circuit breaker is operated by the relay, which energizes the breakers trip coil from the source of control power. In low-voltage circuit breakers, relays are often mounted in the breaker itself to provide overcurrent trips, over/under voltage trips, and other capabilities.
Control power is a source of low-voltage AC or DC power used by the relay to operate protection system equipment like circuit breakers. For AC systems, 240V, 120V, and 69V are standard. DC control power systems typically operate at 125V or 250V for very large substations, but with the increased use of electronic relays, 48V is becoming more common. Battery backup is often provided to boost system reliability.
In addition to powering the protective relays, control power is also used to energize instrumentation, breaker spring-charging motors, and controls mounted on the switchgear.
A relay that monitors a power system and controls equipment to protect the system from a fault is called a ''protective relay''. There are many different designs, the most common of which will be discussed later. The specific relay(s) selected to protect a zone or piece of equipment is based on the kind(s) of protection required. The most common types of protection used in power distribution systems are as follows:
A zone of protection usually consists of one piece or type of equipment. The types of power system equipment protected by relays are as follows:
Relays continuously monitor complex power circuit conditions such as current and voltage magnitudes, phase angle relationships, direction of power flow, and frequency. When an intolerable circuit condition, such as a short circuit, is detected, the relay responds and closes its contacts and the abnormal portion of the circuit is de-energized via the circuit breaker. In addition, the relay can also provide alarm signals and lockout functions. Since no single relay can be designed to monitor and respond to every abnormal condition that can occur in an electrical circuit, it is necessary to gain a basic understanding of the relay operation, design, and construction variations.
All protective relays use one or more of the following basic operation principles:
Electromechanical relays contain mechanical parts that are moved by magnetic fields or heat produced by electrical currents. The most common types are as follows:
The time-delay unit is based on the induction disc principle. The e-magnet shown in '''Figure 39''' has three poles on one side of the disc and a common magnetic member or keeper on the opposite side.
'''Figure 39: Westinghouse Type CO Induction Disc Unit (E-Magnet)'''
The main coil is on the center leg. Current (l) in the main coil produces flux (φ1), which passes through the air gap and the disc to the keeper. The flux (φ1) returns as φ2through the left-hand leg and as φ3through the right-hand leg, where φ1= φ2+φ3. A short-circuited lagging coil on the left leg causes φ2to lag both φ3and φ1, producing a split-phase motor action. Flux φ2induces voltage Vs,and current lsflows, essentially in phase, in the shorted lag coil. Flux φ4is the total flux produced by the main coil current (I). The three fluxes cross the disc air gap and induce eddy currents in the disc. These eddy currents set up counter fluxes, and the interaction of the two sets of fluxes produces the torque that rotates the disc. With the same reference direction for the three fluxes, as shown in '''Figure 39''', the flux shifts from left to right and rotates the disc clockwise.
The induction disc relay is designed so when a preset current is applied to a coil, a torque is produced on the induction disc. The more current, the faster the disc turns. The disc continues to turn until the moving and stationary contacts touch. The contacts are connected to the trip circuit of the circuit breaker. The circuit breaker trips when the contacts close. Once the circuit breaker opens, the current is interrupted and the relay resets. A spiral spring is attached to the rotating disc to provide counter-torque to the disc ('''Figure 40''').
'''Figure 40: GE Type IAC Induction Disc Unit (C-Magnet)'''
Polar units operate from direct current applied to a coil that is wound around the hinged armature in the center of the magnetic structure. A permanent magnet across the structure polarizes the armature-gap poles, as shown in '''Figure 41'''. Two nonmagnetic spacers, located at the rear of the magnetic frame, are bridged by the two adjustable magnetic shunts. This shunt arrangement enables the magnetic flux paths to be adjusted for pickup and contact action. With balanced air gaps ('''Figure 41a'''), the flux paths are as shown, and the armature will float in the center with the coil de-energized. With the gaps unbalanced ('''Figure 41b'''), some of the flux is shunted through the armature. The resulting polarization holds the armature against one pole with the coil de-energized. The coil is arranged so that its magnetic axis is in line with the armature and at a right angle to the permanent magnet axis.
Current in the coil magnetizes the armature either north or south, increasing or decreasing any prior polarization of the armature. If, shown in '''Figure 41b''', the magnetic shunt adjustment normally makes the armature a north pole, it will move to the right. Direct current in the operating coil, which tends to make the contact end a south pole, will overcome this tendency and the contact will move to the left. Depending on design and adjustments, this polarizing action can be gradual or quick. The left gap adjustment ('''Figure 41b''') controls the pickup value, and the right gap adjustment controls the reset current value.
'''Figure 41: DC Polar Unit Cylinder'''
The operation of a cylinder unit is similar to that of an induction motor with salient poles for the stator windings. Shown in '''Figure 42''', the basic unit used for relays has an inner steel core at the center of the square electromagnet, with a thin-walled aluminum cylinder rotating in the air gap. Cylinder travel is limited to a few degrees by the contact and stops, and a spiral springs provides reset torque. Operating torque is a function of the product of the two operating quantities and the cosine of the angle between them. Different combinations of input quantities can be used for different applications, system voltages or currents, or network voltages.
'''Figure 42: Cylinder Unit'''
Clapper or armature units have a U-shaped magnetic frame with a movable armature across the open end. The armature is hinged at one side and spring-restrained at the other. When the associated electrical coil is energized, the armature moves towards the magnetic core, opening or closing a set of contacts with a torque proportional to the square of the coil current. The pickup and dropout values of clapper units are less accurate that those of solenoid plunger units. Clapper units are primarily applied as auxiliary or go/no-go units.
Two clapper units are shown in '''Figure 43''': the first ('''Figure 43a''') is for DC service and the second ('''Figure 43b''') for AC operation. In both units, upward movement of the armature releases a target that drops to provide a visual indication of operation.
The DC ICS unit ('''Figure 43a''') is commonly used to provide a seal-in around the main protective relay contacts. The AC IIT unit ('''Figure 43b''') operates as an instantaneous overcurrent or as an instantaneous trip unit. Its adjustable core provides pickup adjustment over a nominal four-to-one range.
'''Figure 43: Clapper or Armature Units'''
Plunger or solenoid units have cylindrical coils with an external magnetic structure and a center plunger. When the current or voltage applied to the coil exceeds the pickup value, the plunger moves upward to operate a set of contacts. The force, F, required to move the plunger is proportional to the square of the current in the coil.
The plunger unit’s operating characteristics are largely determined by the plunger shape, the internal core, the magnetic structure, the coil design, and the magnetic shunts. Plunger units are instantaneous in that no delay is purposely introduced. Typical operating times are 5 to 50 msec, with the longer times occurring near the threshold values of pickup.
The plunger unit shown in '''Figure 44''' is used as a high drop-out, instantaneous, overcurrent unit. The steel plunger floats in an air gap provided by a nonmagnetic ring in the center of the magnetic core. When the coil is energized, the plunger assembly moves upward, carrying a silver disc that bridges three stationary contacts (only two are shown). A helical spring absorbs the AC plunger vibrations, producing good contact action. The air gap provides a ratio of dropout to pickup of 90% or greater over a two-to-one pickup range. The pickup range can be varied from a two-to-one to a four-to-one range by the adjusting core screw. When the pickup range is increased to four-to-one, the dropout ratio will decrease to approximately 45%.
'''Figure 44: Plunger or Solenoid Units'''
In the D’Arsonval unit, shown in '''Figure 45''', a magnetic structure and an inner permanent magnet form a two-pole cylindrical core. A moving coil loop in the air gap is energized by direct current, which reacts with the air gap flux on very low energy input, such as that available from DC shunts, bridge networks, or rectified AC. The unit can also be used as a DC contact-making milliammeter.
'''Figure 45: Moving Coil (D’Arsonval) Unit'''
Thermal replica units consist of bimetallic strips or coils that have one end fixed and the other end free. As the temperature changes, the different coefficients of thermal expansion of the two metals cause the free end of the coil or strip to move (bend), which operates a contact structure for relay applications.
Thermal replica units receive their name from the fact that they replicate the heating characteristics of the motor. In other words, the bimetallic strips "think" they are measuring temperature, whereas, in fact, they operate directly from motor current. '''Figure 46''' is the time-overcurrent (T/C) characteristic curve of an ABB Type BL-1 thermal replica relay.
'''Figure 46: T/C Curve of a Thermal Replica Relay'''
The electronic principle of operation is accomplished by employing solid-state components and auxiliary current or potential transformers ('''Figure 47''').
'''Figure 47: Electronic Relay'''
Line overcurrent causes the auxiliary transformer’s secondary resistor voltage to increase proportionally. This voltage source then drives the relay’s inverse time circuit. The circuit will not be triggered into operation until the source voltage exceeds a definite voltage value at which a diode conducts and a capacitor begins to charge (the relay picks up). A further increase in voltage increases the capacitor's charging rate. When a predetermined charge is reached, transistors begin to conduct, emitting a pulse signal that activates the trip unit. On a high-current fault, the instantaneous element senses the fault and signals an immediate trip. The trip unit is an off-on electronic switch capable of handling the circuit breaker trip current.
Digital electronic protection devices are computers dedicated to monitoring the power distribution system. They consist of a microprocessor, memory, a display unit, and associated electronic switches (relays) that control circuit breakers and indicating lights. They have many advantages over comparable electromechanical relay and indicating setups:
'''Memory''' - The computer can "remember" thesystem conditions that lead up to a fault. This provides a valuable troubleshooting resource.
Regardless of what a protective relay does or how it is constructed, it must meet several basic requirements to effectively protect the system:
These requirements often conflict with one another. A relay must compromise between these requirements and still provide adequate system protection.
The following protected equipment is discussed in this section:
Lines and cables are the backbone of the protected equipment in an electrical power system. If the lines and cables are inadequate, for whatever reasons, no matter how superb the other equipment, unsatisfactory operation will result.
Protection against cable overloads is typically achieved by means of devices that are sensitive to both current magnitude and fault duration (time). Protection against cable short circuits is achieved by similar devices, but they are sensitive to much greater current magnitudes and shorter time durations.
Transformer failure may result in loss of service; however, prompt fault clearing from the system, in addition to minimizing the damage and cost of repairs, usually minimizes system disturbance, the magnitude of the service outage, and the duration of the outage. Prompt fault clearing will usually prevent catastrophic damage. Proper protection is important for transformers of all sizes, even though the transformers are among the simplest and most reliable components in the plant’s electrical system.
Small transformers that are rated under 5 MVA are typically protected by use of overcurrent relays (ANSI Devices 50 and 51) for both phase and ground fault protection. As their sizes increase, more elaborate and expensive relays are designed and installed to protect the transformer. For example, differential relays are almost always used to provide sensitive fault protection for transformers that are rated 5 MVA and larger. Transformers are also provided with inherent (manufacturer installed) protective devices such as thermal protection (RTDs), temperature indicators, and sudden pressure relays.
There are many variables involved in choosing motor protection: motor importance, motor rating (from one to several thousand horsepower), type of motor controller, etc.; therefore, it is recommended that protection for each specific motor installation be chosen to meet the requirements of the specific motor and its use. After the types of protection have been selected, manufacturers’bulletins should be studied to ensure proper application of the specific protection chosen.
Typical protection schemes for motors include undervoltge protection, phase and unbalance protection, RTD thermal protection, locked-rotor protection, and ground and phase fault protection.
To isolate faults on buses, all power source circuits connected to the bus are opened electronically by relay action or by direct trip-device action on circuit breakers, which shuts down all loads and associated processes that are supplied by the bus. When bus-protective relaying is used, it should operate for bus or switchgear faults only. It is essential that bus-protective relaying operates for bus or switchgear faults only, because false tripping on external faults is intolerable.
In view of the disastrous effects of a bus fault, all bus equipment should be designed to be as nearly "fault-proof" as practical and high-speed protective relaying should be used to keep the duration of the fault to a minimum, which limits the damage and minimizes the effects on other parts of the power system. When medium-voltage industrial power systems are grounded through resistance to limit fault damage, the current available to detect a ground fault is small; therefore, the protective relaying system should be very sensitive.
Bus overcurrent protection (overload and phase-fault) is typically provided by time/overcurrent relays (ANSI Device 51). Where more sensitive and high-speed fault protection is desired, differential protection (ANSI Device 87B) is used to protect the bus and associated switchgear.
The transformers are protected from internal overcurrent and overvoltage faults by type KAB differential relays manufactured by Asea Brown Boveri and power fuses.
The relays are instantaneous units that use bushing transformers to sense electrical conditions within the zone of protection. The relay has two separate units:
Overcurrent protection for the distribution system is provided by the Siemens Communicating Overcurrent Relay (SCOR), which is used to open circuit breakers in the event of a fault. This relay is microprocessor-based, has a RS-485 port to allow it to be integrated into a power-monitoring network, and has a RS-232 port for programming by a computer, i.e., an appropriately equipped laptop. The relay has programmable current trip functions: time overcurrent, instantaneous overcurrent, and ground time and instantaneous overcurrent.
The time overcurrent function has two parts: the pickup point and the time delay. The pickup point for the time overcurrent trip function is coarsely adjustable by selecting current transformer pickup taps from the front panel rotary switch, and it is finely adjustable by programming the computer through the communications ports or the front panel. The length of the time delay depends on the magnitude of the current and which time-current characteristic is used. One of 16 families of 100 time-current characteristics can be selected for the time overcurrent trip. Selection of the timing characteristic is programmed through one of the communications links or from the front panel.
When the monitored current exceeds the overcurrent pickup point, the TMG LED illuminates as timing begins. The timing process continues until the time delay expires and the relay trips or the current drops below the pickup point (which causes the timer to reset). If the relay trips, the TMG LED will remain lit as an indication of contact closure.
The instantaneous current pickup is adjustable from .50 times to 20 times the time overcurrent pickup setting. An indicator separate from the time overcurrent trip LED is provided to show an instantaneous trip occurred. The pickup point is programmable from the front panel or via the communications ports.
The ground time and instantaneous overcurrent trips work the same as the phase overcurrent functions, but the ground time-current characteristic and instantaneous pickup are selected separately and function independently of the phase trips. The ground overcurrent trips are not required to be used and may be disabled.
Monitoring of power distribution system parameters may be performed by an electronic metering package. A typical unit is based on a 12-MHz, 16-bit microprocessor, allowing the software to process inputs in real time. The unit is self-contained, and its program and logs are maintained in nonvolatile memory, which allows the unit to retain system information and setpoints in the event of a complete power outage.
The 4700 can monitor the following power system parameters:
It maintains a log of the last 100 of these values taken at user-defined intervals as well as a record of power system events and minimum/maximum values for the monitored parameters.
The unit can be equipped with communications port, which allows it to be linked with up to 32 other power system monitoring devices. This allows remote monitoring and control of the distribution system.
The meter has three relays that may be used for the operation of alarms or load control. Each relay can switch AC loads of 120V and DC loads of 24V at 10 amps. The relays may be controlled remotely via the RS-485 communications port and by programmable setpoints.
The meter has definable setpoints. A setpoint is a group of six parameters that tell the unit:
Setpoints can function either as over setpoints or under setpoints. An over setpoint activates when the monitored value rises above the high limit for a certain period of time (activate delay); it deactivates when the value falls below the low limit and stays below it for a time (deactivate delay). An under setpoint functions like the over setpoint, except that it activates when the monitored value falls below the low limit and resets when the value climbs above the high limit. Note that the time delays do not vary with the magnitude of the monitored parameter (i.e., inversely with current) and so are not suited to provide some types of protective functions.
Troubleshooting system problems and returning the system to full capability as quickly as possible is important. However, a correct response is more important than simply making a speedy response. Taking the proper approach and using logical steps to respond and correct problems is the most effective method.
The obvious benefit of a system that never experiences unplanned outages is increased productivity. An unfortunate reality of the situation is that equipment and systems fail. This makes our main concern here that these failures are taken care of and corrected quickly and safely.
Unlike planned switching events, power outages cannot be scheduled. Because these outages occur without warning, the maintenance department must be prepared to troubleshoot equipment and restore operations at a moment’s notice. Getting power back on-line requires good organization, knowledge of the equipment, and skill. After an equipment failure, it requires a team effort by all involved to ensure that operations are restored quickly and safely. This section explains how the technicians can troubleshoot power outages and breakdowns effectively.
Power outages disrupt the routine of operations at the manufacturing facility and frequently force the emergency crew to work under pressure. Management tends to "look over the shoulder" of the emergency crews to pressure them into completing the restoration quickly. The first and foremost rule to follow when troubleshooting is never let anyone rush you, and always understand what you are doing before you do it.
Troubleshooting can be defined as the logical analysis of symptoms to determine the cause of a failure and return the equipment or system to service. There are six basic steps to troubleshooting, as shown in '''Figure 48'''.
'''Figure 48: Basic Troubleshooting Steps'''
Using the steps shown in '''Figure 48''', technicians can logically and effectively identify and repair equipment or system problems in the plant's power distribution system.
For a clear understanding of the six troubleshooting steps, each step will be covered separately.
The first step in a logical approach is to determine that there is, in fact, a problem.
During symptom elaboration, you look into the symptoms in more depth.
Using the indicated symptoms, logically determine whether the list of causes is possible or probable. This step may include various equipment tests to go from one suspected cause to the next.
The isolation of a faulty component and equipment are very closely related. Once the faulty equipment is determined, it often can be directly related to a component. In determining the faulty component, again, testing to prove or disprove possibilities must be specified. At this point, the use of a schematic or wiring diagram will be needed to determine test points that will split the circuit into sections to give a yes or no indication for evaluation.
This point is too often overlooked. Simply replacing a faulty component without determining the cause can result in another failure. Further testing may be required if the cause is related to a design or application problem.
The final steps are the repair or replacement of faulty components and then adequately testing the repair to ensure that it will accomplish the desired result.
The tests to verify a repair can be a simple check of circuit continuity or a complex sequencing of operations to ensure correct function. Continuity checks and insulation tests should always be included as a minimum in electrical equipment testing.
Always use the equipment's technical manual or maintenance manual for reference when making repairs and testing electrical equipment.
One aspect of troubleshooting is recognizing an abnormal condition or operational performance. In distribution systems, the failure of equipment is most often times quite noticeable and easy to determine that the equipment has failed. Sometimes overlooked is the cause of the failure; too often, it is assumed that it was simply the equipment that failed due to age or an internal fault. This can lead to costly replacements when a second unit fails shortly after replacement when it is assumed everything else in the system is fine.
There are many causes of equipment failure. A few of the most common are as follows:
One of the most often occurring problems with distribution equipment is overheating. It is an easily recognized condition, but one that has many possible causes and remedies. The most common causes of distribution equipment overheating are as follows:
When inspecting for signs of overheating, look for several indications. The most obvious is a component that is extremely hot to touch or shows signs of peeled paint or scorching. Remember to always use the back of your hand when checking equipment temperatures by touch.
Another method of checking for overheating is the use of temperature indicators. The use of installed temperature gauges and contact pyrometers can supply data for establishing a trend analysis when problems are suspected.
Blocked or dirty ventilation louvers or dirty air filters are another cause of restricted ventilation airflow to switchgear and power-consuming equipment. Ventilation louvers and screens must be kept clean at all times to allow for maximum airflow to the equipment.
Poor insulation resistance can be both a symptom and the cause of failures. This aspect must be thoroughly investigated if it is considered to be a cause. Overheating or high short-circuit current is often the cause of low insulation resistance.
'''Figure 49''' shows the effect of a low insulation resistance. The cable pictured was exposed to water. You can also see tracking that can result in a high-voltage system as insulation integrity is lost.
'''Figure 49: Damaged Cable'''
Resistance creates heat at any point in an electrical system as a result of the power consumed. In the case of distribution systems where large amounts of power flows, a high resistance connection can be devastating.
High-resistance connections feed on themselves and become worse over time. The use of thermography is an economical means by which loose, overheating connections can be found and corrected. Thermography is typically performed while the switchgear is under load. The temperature difference shows hot spots or loose connections and these potentially trouble spots are scheduled for inspection and repair during the next outage.
Busbars connect the high-voltage equipment within the switchgear enclosure, such as the main bus, circuit breakers, pads for cable lugs or terminators, and instrument transformers. Standard busbar material is aluminum with tin plating and copper bar with silver plating. Both are normally coated with epoxy insulation. Busbar joints are insulated with molded boots or taped insulation.
A bus joint is the connection between two busbars. The joint must be able to withstand any mechanical stress placed on it and also provide good electrical contact between the busbars. In order for the joint to meet the above criteria, observe the following items when assembling or disassembling bus joints:
'''Figure 50: Main Bus Joints - Breaker Section'''
'''Figure 51: Busbar Joint Assembly'''
'''Figure 52: Ground Bus Connection'''
There are no precautions or procedures involved in the disassembly of bus joints; however, care should be exercised to avoid damaging insulation boots and the plating on contact surfaces. The fasteners and contact surfaces should be inspected for damage and signs of overheating or pitting, and any problems should be addressed before reusing the hardware.
Bus and connections are insulated in metal-clad switchgear as part of a coordinated insulation system; air or creep distance combines with bus insulation for the needed insulation level. The busbar coating is an epoxy designed to minimize the probability and reduce the impact of a fault. It will not prevent electric shock. The bus joints are insulated by molded boots or are taped.
Bus-joint insulating boots come in parts that are molded to fit around the joint and then are bolted or snapped together. Fastening hardware is made of non-conductive nylon. When the boot is installed, it should be flush with the busbar insulation and overlap it by at least 1 inches. In those cases where the boot does not close flush with the bar insulation or the overlap is less than 1 inches, apply one layer of tape half-lapped overlapping the bar insulation and boot by 1 inches. '''Figure 53''' shows a typical boot.
'''Figure 53: Typical Boot Installation'''
Insulation boots are provided by the factory for repetitive or standard bus-joint configurations. Where boots are not used, the joints must be carefully taped to the required insulation level as described below.
Tools that are often overlooked for use in maintenance and repairs are technical manuals, drawings, and references. The use of technical manuals and drawings ensures that the component or system is being maintained or repaired as per the original specification by the manufacturer. This ensures two things: the original intended operational requirements of the equipment are still being met, and if the equipment is still under a warranty, the manufacturer will be bound to honor the commitment to repair or replace.
There are many types of available reference materials to aid the technician in accomplishing maintenance and repairs. Some of these materials are the equipment technical manual, manufacturer drawings, plant drawings, and electrical reference books. All plant documentation, drawings, and references are maintained by Engineering.
The importance of the technical manual as a maintenance tool cannot be overemphasized. It provides the description of operation of the component, which is important to troubleshooting. It will provide a detailed listing of repair parts and the ordering numbers. These are normally given as a list of parts that should be maintained available to perform routine maintenance and minor repairs.
The technical manuals will usually contain troubleshooting charts. Although somewhat simplified many times, the chart provides a logical sequence with which to establish a starting point. In some cases, the troubleshooting charts will be the only way to accomplish a repair.
The use of manufacturer’s drawings and plant drawings is a necessity in accomplishing effective troubleshooting. The importance of the drawings is illustrated by thinking of them as a road map. Trying to find your way around a switchgear control circuit without a schematic or wiring diagram is like trying to navigate without a map.
The major importance of all reference materials is their use in support of equipment repairs and replacement. The procedures that are supplied by manufacturers and developed by plant engineers should be available for use by all in every aspect of maintaining equipment. The optimum use of references comes when they are maintained in a central location and updated on a regular basis to incorporate changes in equipment and systems.
Another reference book that can be developed by the users of the equipment is the operational history. If used and maintained correctly, it can be one of the most effective tools available in diagnosing problems and effecting repairs.
The first step in development of equipment history is to obtain an accurate and detailed list of all the equipment used in the system. This can be done in several ways, but the most efficient method used so far is the compilation by system. In the beginning of this type of an effort, it is often manpower intensive, but the overall benefits of the program far outweigh the initial costs.
The advantage of development by system is that it allows you to break the major systems down to subsystems that can be more easily addressed. An example would be the plant power distribution system. By considering each substation as a subsystem of the main distribution system, it becomes easier to visualize the equipment contained within each and to provide a history on the equipment contained with each.
Some of the following types of information should be contained as part of the initial development:
A simple and cost-effective way of maintaining an equipment history is to have the technicians involved in the maintenance and repairs making the updates on operational problems and maintenance actions performed.
Not every action performed should be recorded, but actions that may be of consequence should be recorded.
The types of actions which should be recorded as a minimum are the following:
All of the actions taken should include the date of performance or replacement. Detailed explanations of actions taken are sometimes a hindrance to the effective use of the history; short, bullet statements describing the actions are the most effective.
A method of gathering the information is maintaining a log at each major location of equipment. The entry of information as described above should be done by the electrical technician following an action. This includes the reclosure of circuit breakers following trips. This will alert Electrical Engineering to problems that may be accumulating over a period of time.
Establishing an equipment operational history serves several purposes that can improve the efficiency of the repairs and predicting failures.
The equipment history points out failures that are of a recurrent nature. This identifies a need for a change in design, operating procedures, or maintenance procedures.
It can also serve an effective use in troubleshooting. By recording symptoms observed during faults, it eliminates some of the first steps in a troubleshooting effort if the symptoms of a particular failure have already been seen and recorded in the history. This recognition can save hours of troubleshooting on difficult or tricky faults that are seldom seen on the equipment.
Using test data maintained in a history can aid in predicting a failure or when the equipment should be shut down for needed maintenance. This function is one of the more important functions. It provides an added benefit of eliminating a maintenance cycle based only on time period, and it allows for the performance when it is most needed, resulting in a more effective time usage for power outages.
''Preventive maintenance'' is defined as "the orderly routine of inspecting, testing, cleaning, drying, varnishing, and lubricating electrical apparatus conducted at regular time or operational periods." This ensures continuity of operation and lessens the danger of breakdown at peak loads, lessening the need for extensive overhaul and replacement.
''Predictive maintenance'' is defined as "the compilation of test and operational data to establish a trend in equipment operational performance and indicate the need for routine maintenance." The benefits are the same as an effective preventive maintenance program with the added benefit of reducing equipment outages and manpower requirements because the maintenance is performed only when deemed necessary to maintain continuity of operation.
There are several factors that determine the extent to which a preventive or predictive maintenance program is utilized and its overall effectiveness. These factors are economics, staffing, and tooling.
There is no argument that preventive maintenance programs are expensive; they require shop facilities, skilled labor, records keeping, and stocking of replacement parts. However, the cost of downtime resulting from avoidable outages may amount to ten or more times the actual cost of repair. The high cost of downtime, especially in facilities using mass production techniques, make it imperative to economic operation.
Switchgear should be scheduled out-of-service at least on a one-to-two-year basis for a thorough inspection, cleaning, checking, and tightening of all bus and cable connections. Testing and calibrating of critical components, such as circuit breakers, relays, and instruments, should be done on a frequency dictated by experience and service requirements. The overall frequency for any component is controlled more by the severity of the operational requirements and environmental concerns.
The switchgear enclosures should be inspected for security, leakage, moisture, heating, ventilation, housekeeping, and insulation. All of these aspects can be observed with the units energized as long as care is taken in not contacting energized points. However, it is always safer to perform all inspections with the switchgear de-energized and locked out. Newer NFPA and OSHA requirements give minimum approach distances that must be followed to prevent electrical shock and injury to personnel. Follow your facility standard electrical safety policy and practices.
Security inspections involve checking all doors and access panels to ensure that all hardware is in place and in good condition. This includes inspection or replacement of ventilation louver screens.
Checking for leakage is done by inspecting for leakage into and out of the switchgear and distribution components. Look for signs of rust or water marks, which will show you evidence of prior leakage. Check around the base of the enclosures for openings that would allow leakage. Any openings should be sealed.
Moisture accumulation can occur on surfaces even though they are watertight. The source of the moisture is condensation. This is caused by outside humidity levels and dew point changes that are uncontrollable. Again, all openings and unused conduits should be sealed to lessen the effects. Any standing water or surface accumulations should be removed as soon as possible. Heat losses in switchgear carrying around 75% full load should prevent the formation of condensation on surfaces. If space heaters are installed in equipment, they should be checked for proper operations and proper thermostat settings. Switchgear heaters should remain energized all of the time to raise the temperature above the dew point to minimize moisture condensation.
Where ventilation is installed, it should be checked for proper operations and to ensure that filters are clean and that there are no obstructions to airflow into the switchgear.
Checking to make sure all interior and exterior lighting is working properly is important for operations. Proper illumination is always important. Housekeeping of the areas around switchgear is important for two reasons: to prevent blocking of airflow required for switchgear ventilation and to prevent dust accumulation that can be introduced into the switchgear.
With proper maintenance, the insulation of switchgear is designed and expected to operate at normal voltages for many years. There are many factors that can affect the ability of the insulation to provide this type of service. Several that can be checked without special requirements or conditions needing to be met are the ones we have just discussed. Minimizing exposure to moisture and excessive dust and dirt accumulation will go a long way toward eliminating problems with low insulation resistance.
With any and all circuit-interrupters, the manufacturer’s specifications and guidelines should be followed when making adjustments and inspections. This is especially true of air circuit breakers (ACB).
The general rules to follow for maintaining contacts of all types are to keep them clean, smooth, dry, aligned, and operating at correct pressure. The correct operating pressure for contacts should be obtained from the manufacturer’s literature. Drawout mechanisms should be inspected, and drawout interlocks tested, to ensure proper operation.
The inspections of fuses are generally the same, except that particular attention must be given to the body of a fuse itself. The ability of a fuse to interrupt a circuit and protect the surroundings depends on the integrity of the fuse and its holder.
Visual inspection and electrical testing of insulation are the major maintenance procedures. However, it must be stressed that no amount of maintenance can correct improper application or physical damage done during installation.
If, in addition to the visual inspection, cables or buses are to be touched or moved, they should be de-energized. Cables should be inspected for the following:
Busbar and terminal connections should be checked periodically for looseness and signs of overheating. Overheated connections will feed on themselves, and deterioration will continue to the point that failure is sure to happen in the system, as well as a possible component failure.
Keep in mind that all visual inspections should be done as safe as possible and never done alone. Contact with energized equipment should be avoided; a visual inspection should not require any contact with equipment. This is especially true of cables. Just because the cable insulation or sheathing may look intact, movement may reveal a break that causes arcing. Any cable movement should be done only with the circuits de-energized.
It is important to understand the proper use of the tools and equipment required to do the job. In the case of electrical preventive maintenance, the tools and equipment required generally consists of various pieces of electrical test equipment.
Test equipment is very important to any electrical work. Not only can it be used to determine whether a device is operating properly, but it is also used to determine safe conditions. Before working inside a controller, it is important to know if it is energized or not. A voltmeter, or multimeter, is used for this purpose; therefore, it is extremely important to know how to properly and safely use them.
If used correctly, test equipment can be a great asset. If not used correctly, test equipment can be a great safety hazard. In this section, we will cover the following commonly used pieces of test equipment:
A megger is used to perform an insulation test of electrical equipment. The megger insulation test determines insulation resistance from a conductor to ground. '''Figure 54''' shows a typical, hand-driven megger.
'''Figure 54: Hand-Driven Megger'''
The megohmmeter (megger) is a special-purpose resistance-measuring device. It is used to measure very high resistances. The megger consists of current-limiting resistors, meter movement, and a hand-cranked generator with speed gears capable of generating a constant voltage of several hundred to several thousand volts. The megger is capable of measuring resistance from several megohms to several thousands of megohms. Since this is the region of insulation resistance, the megger is most frequently used for measuring insulation resistance. The meter movement normally used in a megger is called a cross-coil meter. It is similar to the D’Arsonval movement, except that it has two coils, as shown in '''Figure 55'''.
'''Figure 55: Typical Megger Circuit'''
Coil 1, R1, and RX(the resistance to be measured) are in series with the generator. Coil 2 and R2are also in series with the generator but parallel to the combination of Coil 1, R1, and RX. If the test leads are open, no current flows through Coil 1. Current does flow through Coil 2 and deflects the pointer to infinity, which indicates a resistance too large to measure. When an unknown resistor (RX) is connected between the test leads, current will flow in Coil 1, tending to move the pointer to zero. At the same time, Coil 2 still tends to move the pointer to infinity because of the constant current through it. The pointer comes to rest at a position at which the two forces balance. This position depends upon the value of RX, which controls the magnitude of current in Coil 1.
Some meggers are constructed using a high-voltage power supply instead of the hand-crank generator. This type is not portable since the power supply requires an AC input.
Place the instrument on a firm and fairly level base. Avoid strong magnetic fields. The pointer may appear to stand anywhere over the scale until the instrument is operated because the "megger" ohmmeter has no control springs. (This does not prohibit the megger from being placed on top of a transformer.)
Before an actual measurement is made, check the test leads. With leads connected to the megger terminals, and with opposite ends separated, turn the crank at normal speed. If the pointer indicates less than infinity, then there is a leak between the leads that must be removed before proceeding with tests. Then, touch together the test leads while turning the crank to make certain that the leads are not open-circuited. The pointer should indicate a short circuit.
The equipment or device to be tested must be'''de-energized'''. It must be taken out of service and disconnected electrically from all other equipment.
The spot test is conducted by connecting the megger across the insulation to be tested and operating it for 60 seconds. Two data points are recorded: the 30-second and 60-second readings. Using these, the insulation’s dielectric absorption ratio (DAR) can be calculated with the following formula:
The 60-second reading should be temperature corrected to standardize the reading. By comparing the temperature-corrected reading and the DAR to acceptable values, a complete picture of the insulation condition can be obtained.
The time-resistance test is conducted similarly to the spot test, except that the duration is increased to ten minutes and a power-operated megger is used. The data points recorded for the test are the 1-minute and 10-minute readings. Using these, the insulation’s polarization index (PI) can be calculated with the following formula:
The advantage of performing a time-resistance test is that almost all of the absorption current has died away by the 10-minute point, leaving only the actual leakage current to be measured by the megger. To determine the condition of insulation, compare the calculated PI to acceptable values shown in '''Table 3'''. Remember to temperature correct the 10-minute reading.
'''Table 3: Acceptable Resistance Values'''
The step-voltage test is performed by doing a spot test at one voltage and then another spot test at a higher voltage. If the reading obtained from the higher voltage is lower, this indicates a leakage path through insulation to ground. The step test often identifies problems that would not be detected by the spot or time resistance test.
An analog multimeter combines the functions of several instruments into one. It can be used as a voltmeter, an ammeter, and an ohmmeter simply by selecting the proper function and range. The compactness and versatility of the multimeter make it the most commonly used instrument for electrical equipment maintenance.
The ability of the multimeter to perform the functions of several test meters makes it more hazardous to use than the single-purpose meters. It is quite possible to attempt to perform one function with a multimeter when it is set up to perform a very different function. For example, if the meter is set up to measure amps and it is connected in parallel with a voltage supply, as if to measure voltage, the meter may be destroyed and injury to the technician may result.
There is always a risk that the multimeter may be inadvertently set to an incorrect function and pose a personnel safety hazard when used. For this reason, single-purpose meters, such as voltmeters or ammeters, are somewhat safer to use than multimeters.
The digital multimeter uses digital electronics and a numeric display rather than the coil-driven meter used by an analog multimeter. The digital multimeter commonly has many more features than its analog counterpart, including automatic range selection and automatic polarity indication. In addition, the accuracy of the digital multimeter is far superior to that of the analog multimeter.
The same safety concerns that apply to the analog multimeter also apply to the digital multimeter. It is essential that the technician be aware of the operating mode to which the meter is selected and avoid applying the meter improperly.
A typical voltage detector is a lightweight, hand-held instrument that is used to detect AC and DC voltages in the 120- to 600-volt range. The instrument is limited to frequencies of 50 to 60 Hz when measuring AC.
The voltage detector is not a voltmeter. Although it has a voltage indicator, this indicator is suitable for comparative measurements and live/dead checks only. The voltage detector is frequently used in this capacity to check fuses and to verify that a circuit is de-energized prior to maintenance. The voltage detector should always be checked on a known live source before and after use to make sure that it operates properly.
The probes supplied with this instrument are fitted with spring-loaded retractable tip shrouds that protect the technician from coming in contact with a live tip and reduce the chances of accidentally shorting adjacent test points. The shrouds can be locked in the retracted position, if necessary, but it is recommended that this valuable safety feature not be defeated.
A voltage detector should be removed from the circuit as soon as the reading has been taken. The coil is rated for intermittent duty and should not remain energized for more than 15 seconds at a time.
The glow stick ('''Figure 56''') is a proximity voltage sensor. It is made of nonconductive material and contains a neon tube that glows when in the presence of high voltage AC. The glow stick is usable only at 1,000 volts or more, and it should not be used to check circuits that may be energized with a lower voltage. This might result in a false negative reading. In addition, the glow stick does not respond to DC signals and must not be used to check DC circuits. A false negative reading will result. To avoid shock hazards, the technician must not allow the glow stick to touch the conductor being tested. When testing high voltage, make sure that you do not get close enough to arc across the air space between you and the lines.
'''Figure 56: Glow Stick'''
The glow stick is used primarily to verify that a piece of high-voltage equipment has been de-energized and can safely be approached. The operator must test the glow stick on a known high-voltage source beforeandafter getting a negative reading. This confirms that the negative reading was not the result of a failure of the glow stick, in which case, the equipment might still be energized.
A conventional ammeter or multimeter must be placed in the circuit to be measured, in series with the load. This involves de-energizing the circuit twice: once when the meter is attached and once when the meter is removed. Such interruptions in service can be quite disruptive and costly in an industrial setting. The clamp-on ammeter shown in '''Figure 57''' is designed to measure AC amps in a line without breaking the circuit. The technician simply closes the clamps around the line, positions the meter so that the line runs perpendicular to the meter through the center of the gap, and reads the amps indicated on the scale.
'''Figure 57: Clamp-On Ammeter'''
The clamp-on ammeter operates on the principles of induction. As AC current flows through a conductor, it creates a magnetic field around the conductor that changes with the changing voltage in the conductor. This magnetic field induces a voltage in any conductor that is intersected by the lines of flux of the magnetic field. The clamp-on ammeter operates by measuring this induced voltage. This instrument may also be equipped with a set of external probe jacks for the purpose of measuring voltages.
In many instances, a clamp-on ammeter is more suitable for taking current measurements than a multimeter. The clamp-on ammeter is capable of reading very large currents, and there is no need to break the circuit. In addition, measuring the magnetic field around a conductor does not change the electrical properties of the circuit. Introducing a conventional ammeter or multimeter into a circuit always produces some change in the electrical properties, however slight.
To avoid a short circuit, care must be taken not to touch any uninsulated components with the jaws of the clamp-on ammeter. The instrument is equipped with a display lock feature that allows the operator to take a reading in a hard-to-reach or hazardous place and then to remove the ammeter and look at the display.
The purpose of high-potential (hi-pot) testing is to determine whether the insulation in a piece of electrical equipment is capable of handling overvoltages caused by switching and lightning surges without failing. This evaluation is accomplished by charging the equipment with a voltage somewhat in excess of its rated capacity and measuring the rate at which current leaks through the insulation to ground.
Any one of several types of hi-pot testers may be used, depending on the type of hi-pot test that is required. Equipment may be tested with 60 Hz AC, 0.1 Hz AC, or with DC power. Normally, when an AC hi-pot test is performed, the apparatus being evaluated is charged with 1.5 times its rated line-to-line voltage. When a DC test is performed, the test voltage is 2.55 times the rated voltage.
High-voltage testing, whether AC or DC, represents a potential hazard to life, and every safety precaution recommended by the manufacturer or testing agency must be followed. The voltages used and the available current are deadly. Electrician’s rubber gloves must be worn by the technician making the tests. After the test, the apparatus may retain a very large charge due to capacitance. For this reason, the wiring of the apparatus must be discharged by grounding for 15 minutes or more after the completion of the test.
Three-phase AC power consists of three separate alternating currents with the sine wave of each phase lagging the preceding phase by 120, as shown in '''Figure 58'''. The order in which the waveforms of these phases follow each other is called the ''phase sequence''.
'''Figure 58: Three-Phase AC Power'''
When a motor is hooked up to a three-phase power supply, it is important that the power leads be connected in the correct order so that the motor will rotate in the proper direction. The phase-sequence meter is used to determine the phase sequence of the power leads. It is also used to determine the order in which those leads must be attached to the motor to ensure proper rotation of the motor.
The phase-sequence meter has two sets of three test leads, as shown in '''Figure 59'''. One set of leads is used to determine line-phase sequence, and the other set is used for testing motor rotation. To test the line phase, the power leads to be tested must be energized. Use extreme caution when working with them. To test line-phase sequence, connect the three line test leads to the three power leads in any order, and turn the selector switch to "LINE." If the meter reads "CORRECT," label the power leads "A," "B," and "C" according to the designation of the test leads. If the meter reads "INCORRECT," swap any two of the test leads to obtain the correct phase sequence, and label the power leads accordingly.
'''Figure 59: Phase-Sequence Meter'''
To check for proper motor rotation, attach the three motor rotation test leads to the three motor terminals in any order. Position the meter selector switch to "MOTOR," and observe the meter while turning the motor shaft slightly in the proper direction of rotation. The meter needle will deflect first to one side and then kick in the opposite direction. If the direction of the initial deflection is toward "CORRECT," label the motor terminals according to the designation of the test leads. If the initial deflection is toward "INCORRECT," swap any two leads to obtain the proper rotation sequence, and label the terminals accordingly.
Many times, when distribution equipment fails, it unfortunately means a total replacement or refurbishment. In the following discussions, we will cover the installation and checks of cables, circuit breakers, and switchgear busbars.
Whether installing cable for a new installation or making a repair, there are several guidelines that must be observed.
The following standards can be used to extract information and guidelines to follow in such areas as lubricants, pulling, raceways, bend radius, and cable testing:
Whether you are performing the installation or you are responsible for checking contractor performance, the following areas should be inspected during all phases of a pull.
Raceways must be free of sharp edges and debris. Scaffolding material and tools should not be placed on or inside trays. All trays should be clean. Walking on cable inside a tray is definitely not permitted. Sharp objects or edges, such as bolts, cut tie wraps, and inside hold-down clips, must be eliminated. Cable pulled over these objects can cause damage to the cable jacket or insulation.
Cable should be handled so that it does not damage the cable jacket, the insulation, and the conductors. This refers to before, during, and after the pull. To ensure that the cable is not damaged, the manufacturer has stipulated a minimum bending radius for pulling. This means that all pulling aids, conduit bends, and tray bends should have a radius equal to the cable minimum bending radius or larger. Any bend smaller than the minimum bending radius would cause damage and must be avoided.
The National Electric Code (NEC) states that "conductors shall not be bent to a radius of less than 8 times the overall diameter for a non-shielded conductor or 12 times the overall diameter for shielded or lead-covered conductors during or after installation. For multiconductor or multiplexed single conductor having individually shielded conductors, the minimum bending radius is 12 times the diameter of the individually shielded conductor or 7 times the overall diameter, whichever is greater."
A dynamometer or tensiometer is used on pulls performed by mechanical pulling devices to monitor the pulling tension applied to the cable conductors. Typically, a dynamometer is placed in the line, as shown in Figure 60.
Following the manufacturerÃƒÆ’Ã‚Â¢ÃƒÂ¢Ã¢â‚¬Å¡Ã‚Â¬ÃƒÂ¢Ã¢â‚¬Å¾Ã‚Â¢s specifications for maximum pulling tension is important in preventing damage to the cable. If the tension specification is exceeded, the service life of the cable is now highly questionable.
Medium-voltage cables typically have design and specification spacing requirements from one cable to another. Ensure that the cable meets the requirements and is secured in place. Generally, tie wraps are used to train (not support) wires inside equipment, while cable (basket) grips are used to support cables in vertical positions.
Tie wraps are used to ensure that terminations are not supporting the weight of the cable. Ties should be applied loosely enough so as not to damage the cable.
IEEE 422 recommends testing terminations, connectors, and splices after installation but before ultimate connection to equipment. The purpose of the tests is to determine the integrity of the cable system and to detect any damages that may have occurred during storage and installation.
There are three types of tests required after the cable is pulled: the continuity test, the megger test, and the high-potential test.
The continuity check is performed on cable after it has been pulled to ensure that the conductors do not have a break in them. A continuity check is used on splices and installed cable. An ohmmeter is typically used for checking continuity, as shown in '''Figure 61'''.
'''Figure 61: Continuity Check'''
The megger test is used to check the integrity of the cable insulation. It measures resistance, in megohms, to the flow of current through and/or over the surface of electrical equipment insulation. A low DC current is applied to the electrical cable. If the insulation is in good condition, it will resist the flow of current, thus giving a high reading on the megger scale. If the insulation is in bad condition, current will flow through the insulation and give a low reading. Readings below 5 megohms typically indicate a problem with the cable insulation.
A high-voltage test may be performed on cable for acceptance testing. This is called a high-potential (hi-pot) test. This test is typically referred to as a "go/no-go test." Voltages used are much higher than those of a megger test . If a high potential test is done, always perform a megger test first. If the cable is not considered satisfactory by a megger test, do not perform a hi-pot.
The final and most important test is the wire check. Using wiring diagrams, all connections points must be checked to ensure proper hookup.
Whether working on the primary or secondary distribution system, the precautions and procedures are generally the same. The discussions that follow will cover the checks and procedures applicable to circuit breaker installation.
Some of the important aspects we will cover are safety, mechanical checks, electrical checks, and operational checks.
A major safety concern with circuit breakers is the mechanical energy stored by the closing springs. Always ensure that springs are discharged prior to beginning any task. The precautions to ensure this are as follows:
Visually inspect the breaker for signs of damage or loose hardware. Perform a manual slow close of the breaker. Watch for correct operation through the entire closing cycle and latching.
The closing check should be done as per the breaker instruction book. Additionally a check of the tripping should be done to ensure proper engagement. These checks should be done several times.
A secondary coupler can be used to test the electrical operation of the breaker or, if available, the test position of the unit in the cubicle.
Continuity checks and contact resistance are important for ensuring proper operation. These can be accomplished by using an ohmmeter or a test device known as a ductor. In either case, the resistance should be as low as possible. Contact pressures may need to be adjusted if resistances are high.