Substation
Operation and
Maintenance
Table of Contents
C
ontents
1
Substations and Switchyards
. . . . .1Introduction to Substations and Switchyards . . . .1
Basic Equipment . . . .3
Substations: Protective Equipment . . . .5
Regulation, Monitoring, and Communication Equipment . . . .9
Switchyards . . . 13
Switchyard Inspection . . . 16
2
Safety in Substations and Switchyards
. . . . .21Hazards and Safety Practices . . . 21
Safety Practices . . . 21
Electrical Safety . . . 22
Chemical Safety. . . 26
Personal Safety . . . 28
Using Support Devices . . . 29
Dangers and Accidents . . . 30
Safety Review. . . 32
3
Power Transformers, Part 1
. . . . .33Transformer Principles. . . 33
Power Transformers, Current Transformers, and Potential Transformers . . . 35
Power Transformer Cooling Systems, Self-Cooled . . . 39
Power Transformers Cooling Systems, Forced Air/Oil . . . 43
4
Power Transformers, Part 2
. . . . .53Visual Inspection . . . 53
Inspection of a Transformer’s Exterior Condition. . . 54
Inspection of a Transformer’s Sealing System . . . 55
Inspection of a Transformer’s Cooling System. . . 56
Gas and Oil Testing. . . 57
Testing for Combustible Gas . . . 57
Testing for Oxygen . . . 59
Testing Oil Insulating Strength . . . 59
Tap Changers. . . 60
No-Load Tap Changers. . . 61
Load Tap Changers . . . 62
Tap Changer Maintenance . . . 64
De-Energizing, Isolating, and Grounding a Power Transformer . . . 64
Tap Changer Maintenance . . . 66
Physical Condition of the Tap Changer . . . 67
Mechanical Operation of the Tap Changer . . . 68
Electrical Operation of the Tap Changer . . . 68
Turns Ratio Test . . . 69
Overview . . . 69
Calculating the Turns Ratio . . . 70
Identifying Bushing Connections . . . 70
Substation Operation and Maintenance
Overview . . . 72
Test Connections. . . 73
5
New Power Transformer Inspection and Tests
. . . .75‘’On-Car’’ Inspections and Tests . . . 75
Moving a New Power Transformer . . . 77
‘’On-Site’’ Inspections and Tests . . . 81
6
Power Transformer Turns Ratio Testing
. . . .87The Purpose of Transformer Turns Ratio Testing . . . 87
Test Equipment . . . 88
Test Connections. . . 92
Test Procedures . . . 93
Evaluating Test Results . . . 95
7
Power Transformer Oil Testing
. . . .99The Purpose of Transformer Oil Testing . . . 99
Oil Dielectric Test Set . . . 100
Dielectric Breakdown Strength Test . . . 101
Oil Sample Taking. . . 103
Lab Tests. . . 107
8
Power Transformer Insulation Resistance Testing
. . . .113The Purpose of Insulation Resistance Testing . . . 113
Test Equipment . . . 115
Test Connections. . . 118
Test Procedures . . . 120
Evaluating Test Results . . . 124
9
Power Transformer Temperature Indicator Testing
. . . .127Temperature Indicators . . . 127
Temperature Indicator Testing. . . 132
Heater Circuit Testing, Part 1. . . 134
Heater Circuit Testing, Part 2. . . 138
10
Power Transformer Pressure Relay Testing
. . . . .143Sudden Pressure Relays . . . 143
Fault Pressure Relays. . . 146
Testing a Sudden Pressure Relay . . . 148
Testing a Fault Pressure Relay . . . 152
11
Circuit Breaker Operation
. . . .157Introduction to Circuit Breakers . . . 157
Air-Magnetic and Air-Blast Circuit Breakers . . . 160
Oil and Vacuum Circuit Breakers . . . 162
Gas-Blast and Gas-Puffer Breakers . . . 163
Solenoid and Motor/Spring Operating Mechanisms. . . 166
Pneumatic and Hydraulic Operating Mechanisms . . . 169
12
Circuit Breaker Maintenance
. . . . .175General Circuit Breaker Maintenance. . . 175
Operating Mechanism Maintenance, Part 2. . . 182
Air-Magnetic and Vacuum Breaker Maintenance . . . 187
Oil Circuit Breaker Maintenance. . . 192
13
New Circuit Breaker Inspections and Tests
. . . .199Receiving . . . 199
Installation. . . 203
Post-Installation Inspection. . . 206
Proof Tests . . . 208
14
SF6 Gas Properties and Handling
. . . .213Properties of SF6. . . 213
Personal Protection. . . 215
Handling SF6 Gas and Its Decomposition Products . . . 218
Cleanup . . . 221
15
Vacuum Bottle Hi-Pot Testing
. . . . .225Vacuum Interrupter Principles . . . 225
Test Principles, Precautions, and Preparations. . . 227
Hi-Pot Test Setup and Steps. . . 231
Watching for Signs of Breakdown . . . 234
16
Circuit Breaker Time-Travel Characteristics
. . . .237Purpose and Principles of Time-Travel Testing . . . 237
Circuit Breaker Operations . . . 239
Circuit Breaker Time Characteristics . . . 242
Circuit Breaker Travel Characteristics. . . 244
17
Circuit Breaker Time-Travel Testing
. . . . .249Time-Travel Test Equipment . . . 249
Drop-Bar Recorder Testing . . . 253
Light-Beam Recorder Testing. . . 259
Digital Timer/Analyzer Testing . . . 263
18
Circuit Breaker Time-Travel Test Analysis
. . . .267Time-Travel Recordings . . . 267
Electrical Analysis . . . 270
Mechanical Analysis . . . 272
Velocities . . . 275
19
Contact Resistance Testing
. . . . .279The Purpose of Contact Resistance Testing . . . 279
Test Equipment . . . 280
Test Connections. . . 283
Test Procedures and Results . . . 285
20
Capacitors and Reactors
. . . . . .289Function of Capacitors and Reactors . . . 289
Clearing Capacitor Banks. . . 292
Capacitor Bank Maintenance. . . 297
Substation Operation and Maintenance
Shunt Reactors . . . 305
Series Reactors. . . 309
21
Voltage Regulators
. . . .313Voltage Regulator Operation, Part 1 . . . 313
Voltage Regulator Operation, Part 2 . . . 315
Voltage Regulator Control, Part I . . . 319
Voltage Regulator Control, Part 2 . . . 322
Field Inspection. . . 325
Field Control Checks . . . 326
Regulator Replacement. . . 329
22
Protective Relays
. . . .333Introduction to Relays . . . 333
Overcurrent Relays . . . 336
Directional Overcurrent Relays . . . 340
Reclosing Relays . . . 343
Voltage Relays . . . 345
Auxiliary Relays. . . 347
Solid-State Relays . . . 348
23
Protective Relays, Transmission Systems
. . . .351Introduction to Protective Relays . . . 351
Differential Relays . . . 354
Transfer Tripping . . . 359
Distance Relays . . . 362
Zoned Protection . . . 363
Pilot Wire Relaying . . . 366
Breaker Failure Relaying. . . 369
24
Control Equipment
. . . .373Control Functions, Modes, and Equipment . . . 373
Voltage Control . . . 376
Distribution Feeder Fault Control. . . 377
Transmission and Subtransmission Feeder Fault Control . . . 380
Station Fault Control . . . 382
Source Circuit Fault Control . . . 384
Routine Checks of Control Equipment . . . 387
25
Substation Batteries
. . . .391Substation DC Control System Overview. . . 391
Cell Components and Electrochemical Action . . . 394
Cell and Battery Ratings. . . 398
Battery Inspection. . . 401
26
Substation Battery Testing
. . . .405Voltage and Resistance Testing. . . 405
Specific Gravity Testing . . . 407
Integrity and Capacity Testing. . . 410
27
Substation Battery Chargers
. . . . .419Charger Functions and Components . . . 419
DC Control System. . . 420
Freshening Charge . . . 421
Float and Equalizing Charges . . . 424
Charger Inspection and Adjustment . . . 426
28
Substation Battery, Cell and Charger Replacement
. . . . .429Cell Replacement . . . 429
Replacing Battery Cells. . . 429
Battery Removal . . . 432
Auxiliary Battery and Auxiliary Battery Trailer . . . 432
Battery Installation . . . 436
Inspecting New Cells . . . 436
Placing New Cells on the Battery Rack . . . 437
Preparing Electrical Contact Surfaces . . . 438
Making Intercell Connections . . . 439
Battery Charger Replacement . . . 440
Taking the Existing Charger Out of Service . . . 440
Substations and Switchyards
C
hapter
1
Substations and Switchyards
Electricity is a necessity of modern life. Transmission and distribution (T&D) systems provide electricity to consumers wherever and whenever it is needed. Two of the major components of a typical T&D system are substations and switchyards.
This chapter examines the role that substations and switchyards play in a T&D system and discusses some of the equipment that is commonly used in substations and switchyards. Security and safety precautions associated with substations and switchyards are also covered when appropriate.
Introduction to Substations and Switchyards
Major Components of a Transmission and Distribution System
The major components of a transmission and distribution system typically include transmission lines, distribution lines, substations, and switch-yards. Transmission lines carry electricity from the generating plant where it is produced, and distri-bution lines carry electricity to the houses, offices, and industries where it is used.
The distances between generating plants and consumers are often too great to allow electricity to be carried directly from the plants to the
consumers. To carry electricity over long distances, transmission and distribution systems need voltage changing substations, which are referred to in this program as substations. An example of a substa-tion is shown in Figure 1-1. At substasubsta-tions, voltage is increased for efficient transmission over long distances or decreased for distribution to nearby customers.
Besides changing voltage for transmission or distribution, a transmission and distribution system must also be able to ensure that users will continue to receive electricity even if part of the system fails. To meet this rquirement, circuits
Figure 1-1. Substation.
Substations and Switchyards Shunt reactors are used to improve substation
efficiency by adding inductive load to counterbal-ance capacitive loads. A shunt reactor, like the one shown in Figure 1-33, looks like a power trans-former, except that the bushings on a shunt reactor are connected with the source circuit; there are no major connections leading out of a shunt reactor (such as the secondary connections on a power transformer).
Monitoring Equipment
Monitoring equipment is used to provide a means of “watching” substation equipment and systems for problems so that they can be limited and corrected. Commonly used types of monitoring equipment include potential transformers, current transformers, meters, and relays.
Potential transformers
Potential transformers are devices that reduce line voltage to a proportionally lower and safer voltage for metering and relaying. A potential transformer, like the one shown in Figure 1-34, normally has a large porcelain bushing that insulates the higher voltage conductor going into the transformer. The transformer itself is usually enclosed in a metal housing. The output wires of the transformers are enclosed in conduit to protect them. These wires connect to meters or relaying equipment in a control house.
Potential transformers come in many shapes and sizes. They are sometimes difficult to distin-guish from other devices such as some current transformers and surge arrestors. For this reason, potential transformers are often identified in substations by signs like the one shown in Figure 1-35.
Current Transformers
In contrast to potential transformers, which reduce line voltage, current transformers reduce line current to a proportionally lower current for metering or relaying. Current transformers
can look like potential transformers or surge arrestors. One identifying feature on the current transformer shown in Figure 1-36 is a large canister on top of the bushing with a conductor
Figure 1-32. Capacitor bank.
Figure 1-33. Shunt reactor.
Bushings
Source circuit
Shunt reactor
Figure 1-34. Potential transformer.
Bushing
Transformer housing
Power Transformers, Part 1 are not always forced-oil/forced-air cooled.
Power transformers with other kinds of cooling systems can also be gas sealed. Figure 3-36 shows a gas-sealed, self-cooled/forced-air-cooled power transformer. The cooling system is recognizable by the combination of the radiator and the fan. Regardless of the type of cooling system that a gas-sealed power transformer has, the gas seal system works in basically the same way. The simpli-fied illustration in Figure 3-37 represents the sealing system of a gas-sealed power transformer. The components of the sealing system are a gas cylinder, two pressure regulators, two gauges, and a pressure relief device.
The windings in a gas-sealed power transformer are completely covered by oil. The rest of the enclosure is filled with gas, which is supplied through tubing from the cylinder. The regulators ensure that gas is supplied at a pressure slightly above atmospheric pressure. This slight positive pressure keeps air and moisture from leaking into the enclosure.
When the transformer is operating, the windings heat the oil, causing it to expand. As the expanding oil compresses the gas, the pressure inside the enclosure increases. If the pressure rises enough to exceed a predetermined high value, the relief device releases gas from the transformer enclosure to atmosphere. The release of gas continues until pressure returns to an acceptable value.
When the transformer becomes cooler, for example, during a period of reduced load, the oil also becomes cooler, and it contracts. As the oil contracts, the pressure inside the transformer enclosure drops. If the pressure falls below a prede-termined low value, a regulator adds gas from the cylinder to the enclosure until the pressure returns to an acceptable value.
The regulators and the relief device in a gas-sealed
power transformer regulate gas flow. The gauges indicate pressure. For example, the gauge shown in Figure 3-38 indicates the pressure inside the gas cylinder. As gas in the cylinder is used, the cylinder pressure drops. A low pressure reading means that the gas is running out, and the cylinder may need to be replaced.
Figure 3-35. Gas cylinder, regulators, gauges, and pressure relief device.
Regulators
Gas cylinder Guage
Figure 3-36. Gas-sealed power transformer, Example 2.
Radiators
Gas cylinder Guage
Figure 3-37. Simplified representation of a gas-sealed power transformer.
Regulators Gas cylinder Oil Windings Guage Tubing
Power Transformers, Part 2 Next, both selector switch A and selector switch B are rotated clockwise, so that selector switch B slides over to tap 2, and selector switch A slides across tap N to the opposite end of the tap. (Selector switch A remains on tap N.) Since current is not flowing through selector switch B, there is no arcing as the switch changes taps.
Then, transfer switch B is closed, so that current flows across the reversing switch and the raise tap, labeled R, from left to right through a portion of the tapped winding, across tap 2 and selector switch B, across transfer switch B, and out lead X0. Current continues to flow across the neutral tap, across selector switch A, across transfer switch A, and out lead X0.
Transfer switch A is then opened to interrupt current flow through selector switch A. Both selector switch A and selector switch B are rotated clockwise, so that selector switch A slides over to tap 2, and selector switch B slides across tap 2 to the opposite end of the tap.
Once selector switch A is on tap 2, transfer switch A is closed, so that current again flows across selector switch A and transfer switch A and out lead X0. This completes the tap change. The new tap position is shown in Figure 4-18. With
the reversing switch in the Raise position and the selector switches on tap 2, a portion of the tapped winding is added to the secondary winding. This changes the ratio of secondary turns to primary turns and effectively raises the secondary voltage. The first tap position that adds turns to the secondary winding is called one-raise.
As the selector switches are moved clockwise to the other taps, turns are added to the secondary to raise the secondary voltage. When all of the tapped windings are added, the tap changer is at the full-raise position.
Figure 4-19 shows the tap changer at full-raise. To lower the secondary voltage, the selector switches are rotated counterclockwise back to the neutral tap. Then, the reversing switch slides from the Raise position (R) to the Lower position (L), and the selector switches rotate counterclockwise from tap N to tap 4.
Figure 4-20 shows the new tap position called: on-lower.
When the reversing switch is in the Lower position, and the selector switches are on tap 4, current flows from left to right across the secondary winding, across the reversing switch and the Lower tap, from right to left through part of the tapped winding, across tap 4 and the selector switches, across the transfer switches, and out lead X0.
Figure 4-18. Tap changer at one-raise position.
Power Transformer Insulation Resistance Testing between the high voltage winding and ground to be tested. Although the low voltage winding is not included in this test, current leakage to the low voltage winding could affect the resis-tance measurement. To avoid this problem, a lead is connected to the guard (G) terminal of the megohmmeter and the low voltage (X) terminal of the transformer. The guard diverts current that leaks to the low voltage windings so that this leakage current is not included in the test measurement.
Connections for Testing the Resistance Between the Low Voltage Winding and Ground
The connections for testing the insulation resis-tance between the low voltage winding and ground are illustrated in Figure 8-18. One test lead is connected to the earth (-) terminal of the megohmmeter and to a transformer case ground. Another test lead is connected to the line (+) terminal of the megohmmeter and to the low voltage (X) terminal of the transformer. A lead is also connected between the guard (G) terminal of the megohmmeter and the high voltage (H) terminal of the transformer to divert current that leaks to the high voltage winding so that this leakage current is not measured.
Connections for Testing the Resistance Between the
Low Voltage Winding and the High Voltage Winding
The connections for testing the resistance between the low voltage winding and the high voltage winding are illustrated in Figure 8-19. One test lead is connected to the earth (-) terminal of the megohmmeter and to the high voltage (H) terminal of the transformer. Another test lead is connected to the line (+) terminal of the megohm-meter and to the low voltage (X) terminal of the transformer. A lead is also connected between the guard (G) terminal of the megohmmeter and a transformer case ground to divert current that leaks to ground so that this leakage current is not measured.
Connections for Testing the Insulation Resistance
Between the Transformer Core and Ground
A transformer core to ground test is a type of insulation resistance test that is typically performed after a transformer has been moved or after any work has been done inside a transformer. As illus-trated in Figure 8-20, a core ground connects the core that the windings are wound around to the
Figure 8-18. Connections for testing insulation resistance between the low voltage winding and ground.
Figure 8-19. Connections for testing insulation resistance between the low voltage winding and the high voltage winding.
Figure 8-20. Transformer core and core ground.
Core ground
Core
Tank, or case ground
Circuit Breaker Operation is no current flow. Circuit breakers are designed
to take advantage of these momentary absences of current flow to help extinguish arcs.
Classification of Circuit Breakers
Circuit breakers are generally classified according to the dielectric mediums they use to help extin-guish arcs. Four mediums that are commonly used for this purpose are air, oil, vacuum and gas. Figures 11-4 and 11-5 show two types of
breakers that use air as a dielectric medium. The air-magnetic breaker (Figure 11-4) uses air and a magnetic field to help extinguish arcs.
The air-blast breaker (Figure 11-5) uses a high-pressure blast of air.
Figure 11-6 shows an oil breaker. In an oil breaker, the contacts are submerged in insulating oil, which helps extinguish the arc.
Figure 11-7 shows a vacuum breaker. A vacuum breaker encloses its contacts in a vacuum, which
Figure 11-4. Air-magnetic breaker.
Figure 11-5. Air-blast breaker.
Figure 11-6. Oil breaker.
Figure 11-8. Gas-blast breaker.
Figure 11-7. Vacuum breaker.
Circuit Breaker Operation As illustrated in Figure 11-21, a gas-puffer breaker interruptor is enclosed in a pipe-like tank, which is filled with low-pressure SF6 gas. The
interruptor is an insulated tube that houses the breaker’s interrupting mechanisms and insulates them from the outer tank.
The interruptor’s main features (Figure 11-22) include a stationary contact assembly, a moving contact assembly with a non-conducting nozzle, and a chamber where gas is compressed during the operation of the breaker. Each of the contact assemblies includes main contact fingers and arcing contact fingers.
When the circuit breaker is closed, the current path is through the stationary contact assembly, the main contact fingers and the moving contact assembly. When the breaker trips (Figure 11-23), the moving contact assembly moves away from the stationary assembly and the main contact fingers separate. Arcing does not occur, however, because the circuit is still complete through the arcing contacts.
As the moving contact assembly moves away from the stationary assembly, the SF6 gas in the compression chamber is compressed. Compressing the gas increases its dielectric strength. Eventually, the moving contact assembly moves so far that the arcing contact fingers separate, and an arc forms (Figure 11-24).
When the arcing fingers separate, the compres-sion chamber opens, and thehigh-pressure gas flows through the arc to the low pressure areas of the interruptor. The dielectric strength of the high-pressure gas weakens the arc. As the gas flows through the arc, the arc is lengthened and cooled, until it eventually extinguishes at a current zero.
Figure 11-21. Gas-puffer breaker.
Bushings
Interruptor Tank Low pressure
SF6 gas
Figure 11-23. Gas-puffer breaker interruptor – main contacts open.
Main contacts separate Gas comnpressing in chamber Arcing contacts still meet
Figure 11-24. Gas-puffer breaker interruptor - arcing contacts open.
Arc
Figure 11-22. Gas-puffer breaker interruptor – closed. Main contact fingers Moving contact assembly Compression chamber Arcing contact fingers Stationary contact assembly Nozzle
New Circuit Breaker Inspections and Tests rod travel velocity, and a variety of other circuit
breaker operating characteristics. Figure 13-27 is an illustration of typical time-travel traces. The time-travel test is typically performed for several types of breaker operations. The traces for each operation can be analyzed to determine how the breaker is performing in comparison with the manufacturer’s specifications. If the breaker’s performance does not fall within acceptable ranges, the breaker must be properly adjusted before it can be put in service.
Contact Resistance Test
Resistance in the closed contacts of a circuit breaker can have a number of causes, including arcing deposits, a loose or incomplete connection, or pitting from repetitive arcing. Contact resistance creates heat that can reduce the life of the contacts and possibly even lead to breaker failure.
The purpose of contact resistance testing is to detect unacceptably high contact resistance levels before failure occurs.
In principle, the test is performed by passing a direct current through the closed contacts of the breaker and measuring the voltage drop across the contacts (Figure 13-28). The test instrument uses the current and voltage values to calculate and display the contact resistance.
If the contact resistance exceeds an acceptable limit, the contacts may have to be cleaned or replaced.
Insulation Resistance Test
When a circuit breaker’s contacts are open, the breaker’s insulation should provide a high resis-tance to prevent current from flowing.
The purpose of insulation resistance testing is to detect unacceptably low levels of insulation resis-tance before poor or weakened insulation results in failure.
In principle, the test is performed by applying a high DC voltage to one of the breaker’s bushing terminals with the breaker’s contacts open (Figure 13-29). Then, leakage current is measured either to
Figure 13-28. Performing a contact resistance test.
Figure 13-29. Performing an insulation resistance Figure 13-26. Transducer and timing rod on an oil circuit breaker.
Transducer Timing rod
Substation Operation and Maintenance
the power factor in this case by using capacitor banks, such as the one shown in Figure 20-8. The capacitor banks offset the excessive demand for inductive power, and thus bring the power factor closer to unity.
Excessive demand for non-working capacitive power also results in a lower power factor than desirable. In this case, instead of increasing power output to meet the demand for capacitive power, the utility can improve the power factor by using shunt reactors. The shunt reactors offset the excessive demand for capacitive power. Figure 20-9 shows an example of a typical shunt reactor.
Clearing Capacitor Banks
The main steps for safely clearing a capacitor bank for maintenance are similar to the steps taken to clear any other device in a substation. These steps include de-energizing, isolating, testing for dead, and grounding. However, a capacitor bank is different from other devices in a substation in that it stores an electrical charge even after the bank has been separated from its source of energy. Because of this ability to store a charge, some special safety precautions are required when clearing a capacitor bank.
De-Energizing and Isolating a Capacitor Bank
A capacitor bank is de-energized by electrically separating the bank from its source of energy. Figure 20-10 is a simplified illustration of a section of a substation that includes an energized three-phase bus, a three-three-phase circuit breaker, three single-phase disconnect switches, and a three-phase capacitor bank. In this example, the capacitor bank is de-energized by opening the circuit breaker. A capacitor bank is isolated by physically
separating the bank from its source of energy. As illustrated in Figure 20-11, the capacitor bank in this example is isolated by opening the three single-phase disconnect switches. Opening these switches
provides a visible break between the source of energy and the capacitor bank.
The actual switching devices that are operated and the sequence in which they are operated vary with the design of the substation. In general, a capacitor bank is switched out only after
Figure 20-8. Capacitor bank.
Figure 20-9. Shunt reactor.
Figure 20-10. Substation capacitor bank.
Circuit breaker Disconnect switches Capacitor bank
Voltage Regulators
Isolating the Regulator
After the bypass switch is closed, the regulator can be isolated from the circuit. This is done by opening the regulator source and load disconnect switches. The disconnect switch that is opened first depends on the design of the system and on company procedures.
The specific procedure for switching a regulator out of service may vary. For example, the type of switch shown in Figures 22-47 and 22-48 enables the regulator to be both bypassed and isolated in one switch operation. The switch in this example is made up of two bars. When the switch is closed, one bar connects the source circuit to the source lead of the regulator. The other bar connects the load lead of the regulator to the load circuit. The two bars are separated by insulators.
By opening the switch, three switching operations are completed in one action. The first operation is bypassing the regulator. When the switch is opened, a spring operated plate (Figure 21-48) moves into the space where the switch was. The plate connects the source circuit to the load circuit, and the regulator is bypassed.
For the second operation, the regulator is isolated from the source circuit. When the switch is opened, there is a visible separation between the source circuit and the regulator source lead.
For the third operation, the regulator is isolated from the load circuit. When the switch is opened, there is a visible separation between the regulator load lead and the load circuit.
Physically Disconnecting the Regulator
Generally, single-phase regulators in a substation are grouped in three-phase banks, as shown in Figure 21-49. To remove one of the regulators, all three units must be taken out of service. After the regulators have been switched out of service, they are tagged, tested for dead, and grounded according to company procedures.
To remove the regulator, its conductors are discon-nected from the regulator terminals. In Figure
Figure 21-49. Three single-phase regulators. Figure 21-46. Regulator bypass switch closed.
Source disconnect switch Load disconnect switch Bypass switch
Figure 21-47. Disconnect switch.
Regulator load lead Bars separated by insulators Regulator source lead Source
circuit circuitLoad
Figure 21-48. Disconnect switch opened.
Load circuit contact Plate Source circuit contact
Protective Relays, Transmission Systems The specific voltage-to-current ratio setting for a
distance relay is affected by several considerations. For example, a distance relay in substation A can be set for a voltage-to-current ratio that would cause the relay to operate for a fault anywhere on the section of line between substations A and B. With this setting, however, the relay might trip for a fault near substation B but between substations B and C (Figure 23-37). This type of relay operation is undesirable, because the basic approach to
trans-mission line protection is to isolate only the section of line in which a fault occurs. For a fault
between substations B and C,a relay in substation B should open a breaker in substation B, and,
possibly by transfer tripping, also open a breaker in substation C to isolate the fault. If a distance relay in substation A operates, it would isolate the
section of line between substations A and B, even though that section of line does not have to be isolated to remove the fault from the system.
Zoned Protection
To prevent undesirable operations, a distance relay is generally set to protect approximately 90% of a line section. This protected section is typically referred to as Zone 1 (Figure 23-38).
To protect line sections between substations, additional Zone 1 sections can be set up (Figure 23-39). However, with this type of protection, approximately 10% of each line section is left unprotected.
A common way to provide complete protection for line sections is to use a distance relay in each substation that provides Zone 1 protection in the opposite direction (Figure 23-40). This arrange-ment provides overlapping protection for each line section between substations.
In addition to Zone 1 protection, a distance relay may also provide Zone 2 and Zone 3 protection. For example, as illustrated in Figure 23-41, Zone 2 protection from substation A covers the line section between substations A and B, as well as part of the line section between substations B and C. Zone 3 protection from substation A covers the line sections between substations A and B, substa-tions B and C, and part of the line section beyond substation C.
Figure 23-37. Fault between substations B and C.
Figure 23-38. Zone 1 protection.
Figure 23-41. Zone 2 and Zone 3 protection from substation A.
Figure 23-40. Overlapping Zone 1 protection.
= Overlapping protection
Figure 23-39. Multiple Zone 1 protection.
Unprotected line sections
Substation Operation and Maintenance
Sensing Equipment
Sensing equipment is equipment that changes a condition such as voltage or current to a value or signal that can be measured. For example, potential transformers (Figure 24-1) change, or transform, line voltage to a proportionally lower voltage for measurement.
Another example of sensing equipment is a current transformer. Current transformers (Figure 24-2) transform line current to a proportionally lower current for measurement.
Measuring Equipment
The signals from sensing equipment are typically sent to measuring equipment and control-ling equipment. Measuring equipment measures the signal provided by sensing equipment and indicates the value of the condition being sensed. For example, a meter such as the ammeter shown in Figure 24-3 indicates the value of current it receives from a current transformer. Another example of measuring equipment is a recording meter, such as the one shown in Figure 24-4. A recording meter measures signals from sensing equipment and records the values of the signals over a period of time.
Controlling Equipment
Controlling equipment detects the signals it gets from sensing equipment, and, if a signal is different from a preset value, provides a signal that operates various other equipment. An example of controlling equipment is an overcurrent relay, such as the one shown in Figure 24-5.
Figure 24-1. Potential transformer. Figure 24-2. Current transformer.
Figure 24-4. Recording meter. Figure 24-3. Ammeter.
Substation Operation and Maintenance
If alternating current to the charger is interrupted for any reason, the battery will instantly provide direct current to the steady, continuous loads and, as required, to the intermittent loads. It will continue to supply the loads until alternating current is restored or until the battery is fully discharged.
Cell Components and Electrochemical Action
Substation battery maintenance and testing are more likely to be performed properly when the worker knows the construction of the battery cells, how the cells work, and what can go wrong with the cells and why. This section describes the components and electrochemical action of a typical lead-acid substation battery cell.
Components of a Lead-Acid Cell
Battery cells used in substations are typically lead-acid cells. The external components of a typical lead-acid cell (Figure 25-10) include a container, which is often called a jar, positive and negative terminal posts, and a vent with a flame arrestor. The flame arrestor shields explosive gases at the vent from external sparks or flames. The internal components include a liquid called an electrolyte, conductive lead-based plates, and non-conductive separators. The electrolyte is composed of sulfuric acid and water.
Figure 25-11 shows a cell that has been disas-sembled so that the plates and separators can be seen. The plates are arranged so that the negative plates and the positive plates alternate. A cell always has one more negative plate than positive, and the plates at each end of the cell are negative. This is because each positive plate needs a negative plate on each side of it in order to function efficiently. All the positive plates are mechanically and electri-cally linked together by a bus bar and connected to one of the terminal posts. The negative plates are also linked together, and they are connected to the other terminal post. The non-conductive separa-tors insulate the negative and positive plates from each other.
The most widely used cell plate design is a type called the pasted plate, although there is a variety of other designs. The pasted plate uses porous lead compounds for the chemically active portions of the plate. This material is too soft to hold together by itself, so it is typically “pasted” onto a metal grid (Figure 25-12).
Figure 25-10. Components of a lead-acid cell.
Figure 25-11. Disassembled lead-acid cell.
Substation Operation and Maintenance
terminal of cell 7 is connected to the positive terminal of cell 8.
To begin the cell replacement procedure, the jumpers are connected to cells 6 and 8 and to the new cell (Figure 28-3). One end of a jumper is connected to the negative terminal of cell 6, and the other end of the jumper is connected to the positive terminal of the new cell. One end of a second jumper is connected to the positive terminal of cell 8, and the other end of that jumper is connected to the negative terminal of the new cell. The jumpers are connected to the terminal so that they will not interfere with the removal and reinstallation of the intercell connecting straps. With the jumpers in place, the bad cell is then disconnected from the battery by removing the intercell connecting straps between cells 6 and 7 and between cells 7 and 8. Because the new cell is connected in parallel, no arcing occurs when the intercell connecting straps are disconnected from the bad cell.
Next, the bad cell is removed from the battery rack, and the new cell is put in its place (Figure 28-4). Once the new cell is in place, it is connected to the adjacent cells in the battery. The intercell connecting straps are reinstalled, connecting the negative terminal of cell 6 to the positive terminal of the new cell, and the positive terminal of cell 8 to the negative terminal of the new cell. Then, both jumper cables are removed. Connecting a new cell in parallel with the old cell makes it possible to remove and replace a bad cell on a battery that is still in service.
Bypassing a Cell Using a Diode and Jumpers
As shown in Figure 28-5, the equipment required for bypassing a cell using a diode and jumpers includes a jumper with a diode that is connected in line with the jumper, and two jumpers without diodes. Also shown in Figure 28-5 are a combus-tible gas detector, an ohmmeter, and the new cell to be installed in place of the bad cell.
Some companies require that a combustible gas detector be used whenever work is performed on
Figure 28-4. New cell installed between cells 6 and 8 with temporary jumper connections only. Figure 28-2. Typical cell arrangement - one bad cell.
Negative terminals Positive terminals
Bad cell
Figure 28-3. Jumper connections to bypass bad cell.
New cell
Positive Negative
Figure 28-3. Jumper connections to bypass bad cell.
Figure 28-5. Equipment for bypassing a cell using
New cell Jumber with diode Jumpers without diodes Diode Combustible gas detector Ohmmeter
