Important Guidelines to Startup and Shutdown a Large Generator Operating Conditions

The purpose of these guidelines is to ensure the continuing operational integrity of generators.

Operating conditions (startup and shutdown) that have forced units off-line or have damaged or shortened the life of turbine (or generator) components in the past are highlighted in the guideline to prevent recurrences in the future.

Startup Operation

Shutdown Operation

Startup Operation

In addition to monitoring the various generator support systems for cooling and lubrication, electrical

Parameters, temperatures, and vibration, inattention to the following areas has caused problems in the past:

Problem #1

At no time should excitation interlocks or protective relay functions be bypassed or disabled for the purpose of energizing a generator’s direct current (DC) field winding.

Problem #2

For generators requiring field pre-warming, the manufacturer instructions and established procedures should be followed relative to the allowable field currents.

Problem #3

A generator field should not be applied or maintained at turbine speeds above or below that recommended by the manufacturer. On cross-compound units where a field is applied at low speeds or while on turning gear, extreme caution must be exercised.

Should either or both shafts come to a stop, the field current should immediately be removed to prevent overheating damage to the collector or slip rings.

Problem #4

After the field breaker is closed, the generator field indications should be closely monitored. If a rapid abnormal increase occurs in field current, terminal voltage, or both, immediately open the field breaker and inspect the related equipment for proper working condition before reestablishing a field.

Problem #5

During off-line conditions, at no time should the field current be greater than 105% of that normally required to obtain rated terminal voltage at rated speed in an unloaded condition.

Typically, turbo-generators are designed to withstand a full load field with no load on the machine for only 12 seconds; after that, severe damage can occur to the stator core iron laminations.

Problem #6

When synchronizing a generator to the system, the synchroscope should be rotating less than one revolution every 20 seconds Phase angle differences should be minimized and no more than 5 degrees out of phase when the circuit breaker contacts close.

Phase angle differences as little as 12 degrees can develop shaft torques as high as 150% of full load and damage shaft couplings and other turbine and generator components. Manufacturers usually recommend limiting maximum phase angle differences to 10 degrees. 

It is also desirable that incoming and running voltages are matched as closely as possible to minimize reactive power flow to or from the electrical system.

In general, the voltages should be matched within 2% at the time of synchronization. The speed of the turbine should be slightly greater than synchronous speed prior to breaker closure to help ensure that the unit will not be in a motoring condition following connection to the electrical system, and the generator voltage should be slightly higher to ensure VAR flow into the system instead of into the generator.

NOTE: Under no circumstances should operators allow a unit to be synchronized using the sync-check relay as the breaker-closing device (i e , holding a circuit breaker control switch in the closed position and allowing the sync-check relay to close the breaker). Some sync-check relays can fail in a “closed” state, allowing the circuit breaker to be closed at any time.

Shutdown Operation

Normally, units are removed from service through operator initiation of distributed control system (DCS)

Commands or turbine trip buttons that shut down the prime mover. Closure of steam or fuel valves will then initiate anti-motoring or reverse power control circuits that isolate the unit electrically by opening the generator circuit breakers, field breakers, and, depending on the design, unit auxiliary transformer (UAT) low side breakers. If limit switch circuitry or anti-motoring/reverse power relays fail to operate properly, the unit may stay electrically connected to the system in a motoring condition. 

If excitation is maintained, this condition is not harmful to the generator. However, the turbine blades may overheat from windage. On steam units, the low pressure turbine blades are impacted the most, with typical withstands of 10 minutes before damage.

However, the unit can be safely removed from service with the following operating steps:

Operating step #1

Verify that there is no steam flow or fuel flow in the case of combustion turbine units to ensure that the unit will not over speed when the generator circuit breaker(s) are opened. 

Operating step #2 

Transfer the unit auxiliary power to the alternate source if opening the unit breakers will de-energize the UAT.

Operating step #3

Reduce or adjust the generator’s output voltage (voltage regulator) until the field current is at the no load value, and transfer from automatic voltage regulator mode to the manual mode of operation.

Operating step #4

Open the generator circuit breaker(s). 

Operating step #5

Open the generator field breaker

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Testing and Commissioning of Substation DC System

Objective

Power substation DC system consists of battery charger and battery. This is to verify the condition of battery and battery charger and commissioning of them.

Test Instruments Required

Following instruments will be used for testing:

Multimeter. (Learn how to use it)

Battery loading unit (Torkel-720 (Programma Make) or equivalent.

The Torkel-720is capable of providing a constant current load to the battery under test.

Commissioning Test Procedure

1.Battery Charger 

1. Visual Inspection: The battery charger cleanliness to be verified. Proper cable termination of incoming AC cable and the outgoing DC cable and the cable connection between battery and charger to be ensured. A stable incoming AC supply to the battery charger is also to be ensured.
2. Voltage levels in the Float charge mode and the Boost charge mode to be set
3. according to specifications using potentiometer provided.
4.  Battery low voltage, Mains ‘Off”, charger ‘Off’ etc., conditions are simulated and
5. checked for proper alarm / indication. Thus functional correctness of the battery charger is ensued.
6. Charger put in Commissioning mode for duration specified only one time during initial commissioning of the batteries. (By means of enabling switch.)
7. Battery charger put in fast charging boost mode and battery set boost charged for the duration specified by the battery manufacturer.
8. After the boost charging duration, the battery charger is to be put in float charging (trickle charge) mode for continuous operation.
9. Some chargers automatically switch to float charge mode after the charging current reduces below a certain value.
10. Voltage and current values are recorded during the boost charging and float charging mode.

This test establishes the correct operation of the battery charger within the specified voltage and current levels in various operational modes.

2. Battery Unit

 Mandatory Condition: The battery set should have been properly charged as per the commissioning instructions of the battery manufacturer for the duration specified

.
Visual Inspection: Cleanliness of battery is checked and the electrolyte level checked as specified on the individual cells. The tightness of cell connections on individual terminals should be ensured.

The load current, minimum voltage of battery system, ampere-hour, duration etc., is preset in the test equipment using the keypad.

It is to be ensured that the set value of the current and duration is within the discharge capacity of the type of cell used. Also the total power to be dissipated in the load unit should be within the power rating of the battery load kit.

Individual cell voltages to be recorded before the start of the test.

Battery chargers to be switched off/load MCB in charger to be switched off
Loading of the battery to be started at the specified current value.

 Individual cell voltages of the battery set are to be recorded every half an hour.
 It is to be ensured that all the cell voltages are above the end-cell voltage specified by the manufacturer.

If any of the cell voltages falls below the threshold level specified by the manufacturer, this cell number is to be noted and the cell needs to be replaced.

Test set automatically stops loading after set duration (or) when minimum voltage reached for the battery set.

Test to be continued until the battery delivers the total AH capacity it is designed for.Value of AH and individual cell voltages to be recorded every half an hour.         

Acceptance Limits

This test establishes the AH capacity of battery set at required voltage.

The acceptance limit for the test is to ensure the battery set is capable of supplying the required current at specified DC voltage without breakdown for the required duration.

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On Power System Stability the Impact Of Voltage Regulation

Voltage Tolerance Ranges

Voltage regulation, by definition, is the percentage change in secondary voltage from no-load to full-load conditions. The regulation is customarily specified at a specific power factor, as the power factor of the load affects the voltage regulation of the device or circuit.
Voltage regulation cannot be improved by the use of the conventional no-load tap changer on a transformer. The tap changer merely changes the transformer turns ratio, but does not significantly change the transformer impedance.

The regulation (percent change from no-load to full-load) will, therefore, not change.
The operating voltage range will, however, change and affect the performance of the utilization equipment.

Load flow studies should be performed and operating conditions (no-load, light-load, or full-load) examined to ensure that voltage tolerance ranges are not exceeded. If voltage tolerance ranges are exceeded, then one alternative is to adjust transformer taps to compensate for either high voltage, at no-load or light-load conditions, or low voltage, at full-load conditions.

Capacitors of either switched or fixed configurations can also be used to correct the voltage range profile of a distribution system.

Often, for large complex systems, the use of switched capacitors is the only realistic solution for a voltage range that is too wide. In this instance, capacitors are switched off-line when the load is light, so that the voltage does not become too high.

As the load increases, capacitors are switched on-line to prevent the voltage from becoming too low.

For maximum benefit, capacitors should be located close to the load that is causing the problem, however, this is often not technically or economically feasible.

Synchronous motors can also be used to good advantage on large power systems if the 0.8 power factor design is purchased, rather than the less expensive unity power factor motor. The 0.8 power factor synchronous motor can be used to improve voltage levels on its utilization bus in the same manner as capacitors.

Control of the operating voltage range can also be achieved by the use of transformers with on-load tap changers and line regulators.

Both devices use multi-tap devices, in combination with voltage sensing and control apparatus, to adjust the transformer ratio or regulator ratio by actively switching taps as the steady-state load changes. These devices are usually used by utilities in the primary distribution system and provide the final distribution circuits with a voltage range within the Range A limits of ANSI C84.1.

Unless the site distribution system is unusually large and complex, and the daily load fluctuations quite large, these devices are not applied to electrical distribution systems on facilities.

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Maintenance Of SF6 Gas Circuit Breakers

Sulfur Hexa fluoride (SF6) is an excellent gaseous dielectric for high voltage power applications. It has been used extensively in high voltage circuit breakers and other switchgears employed by the power industry.

          Applications for SF6 include gas insulated transmission lines and gas insulated power distributions.

         The combined electrical, physical, chemical and thermal properties offer many advantages when used in power switchgears.

      Some of the outstanding properties of SF6 making it desirable to use in power applications are:

 High dielectric strength

Unique arc-quenching ability

Excellent thermal stability

Good thermal conductivity

Properties Of SF6 (Sulfur Hexafuoride) Gas

A) Toxicity:- SF6 is odorless, colorless, tasteless, and nontoxic in its pure state. It can, however, exclude oxy­gen and cause suffocation. If the normal oxygen content of air is re­duced from 21 percent to less than 13 percent, suffocation can occur without warning. Therefore, circuit breaker tanks should be purged out after opening.

B) Toxicity Of Arc Products:- Toxic decomposition products are formed when SF6 gas is subjected to an elec­tric arc. The decomposition products are metal fluorides and form a white or tan powder. Toxic gases are also formed which have the characteristic odor of rotten eggs. Do not breathe the vapors remaining in a circuit breaker where arcing or corona dis­charges have occurred in the gas.

Evacuate the faulted SF6 gas from the circuit breaker and flush with fresh air before working on the circuit breaker.

C) Physical Properties:- SF6 is one of the heaviest known gases with a den­sity about five times the density of air under similar conditions. SF6 shows little change in vapor pressure over a wide temperature range and is a soft gas in that it is more compressible dynamically than air.

The heat trans­fer coefficient of SF6 is greater than air and its cooling characteristics by convection are about 1.6 times air.

D) Dielectric Strength:- SF6 has a di­electric strength about three times that of air at one atmosphere pressure for a given electrode spacing. The dielectric strength increases with increasing pressure; and at three atmospheres, the dielectric strength is roughly equivalent to transformer oil. The heaters for SF6 in circuit breakers are required to keep the gas from liquefying because, as the gas liquifies, the pressure drops, lowering the dielectric strength.

      The exact dielectric strength, as compared to air, varies with electrical configuration, electrode spacing, and electrode configuration.

E) Arc Quenching:- SF6 is approxi­mately 100 times more effective than air in quenching spurious arcing. SF6 also has a high thermal heat capacity that can absorb the energy of the arc without much of a temperature rise.

F) Electrical Arc Breakdown:- Because of the arc-quenching ability of SF6, corona and arcing in SF6 does not occur until way past the voltage level of onset of corona and arcing in air. SF6 will slowly decompose when ex­posed to continuous corona.

All SF6 breakdown or arc products are toxic. Normal circuit breaker operation produces small quantities of arc products during current interruption which normally recombine to SF6.

Arc products which do not recombine, or which combine with any oxygen or moisture present, are normally re­moved by the molecular sieve filter material within the circuit breaker.

*------Handling Nonfaulted SF6-------*

The procedures for handling nonfaulted SF6 are well covered in manufacturer’s instruction books. These procedures normally consist of removing the SF6 from the circuit breaker, filtering and storing it in a gas cart as a liquid, and transferring it back to the circuit breaker after the circuit breaker maintenance has been performed.

No special dress or precautions are required when handling nonfaulted SF6.

*---------Handling Faulted SF6---------*

Toxicity

FAULTED SF6 GAS – Faulted SF6 gas smells like rotten eggs and can cause nausea and minor irritation of the eyes and upper respiratorNormally, faulted SF6 gas is so foul smelling no one can stand exposure long enough at a concentration high enough to cause permanent damage.

SOLID ARC PRODUCTS – Solid arc products are toxic and are a white or off-white, ashlike powder. Contact with the skin may cause an irritation or possible painful fluoride burn. If solid arc products come in contact with the skin, wash immediately with a large amount of water. If water is not available, vacuum off arc products with a vacuum cleaner.

Clothing and safety equipment requirements

When handling and re­ moving solid arc products from faulted SF6, the following clothing and safety equipment should be worn:

COVERALLS – Coveralls must be worn when removing solid arc products. Coveralls are not required after all solid arc products are cleaned up. Disposable coveralls are recommended for use when removing solid arc products; however, regular coveralls can be worn if disposable ones are not available, provided they are washed at the end of each day.

HOODS – Hoods must be worn when removing solid arc products from inside a faulted dead-tank circuit breaker.

GLOVES – Gloves must be worn when solid arc products are hah-died. Inexpensive, disposable gloves are recommended. Non-disposable gloves must be washed in water and allowed to drip-dry after use.

BOOTS – Slip-on boots, non-disposable or plastic disposable, must be worn by employees who enter eternally faulted dead-tank circuit breakers. Slip-on boots are not required after the removal of solid arc products and vacuuming. Nondisposable boots must be washed in water and dried after use.

SAFETY GLASSES – Safety glasses are recommended when handling solid arc products if a full face respirator is not worn.

RESPIRATOR – A cartridge, dust-type respirator is required when entering an internally faulted dead-tank circuit breaker. The respirator will remove solid arc products from air breathed, but it does not supply oxygen so it must only be used when there is sufficient oxygen to support life. The filter and cartridge should be changed when an odor is sensed through the respirator.

The use of respirators is optional for work on circuit breakers whose in­ terrupter units are not large enough for a man to enter and the units are well ventilated.

Air-line-type respirators should be used when the cartridge type is ineffective due to providing too short a work time before the cartridge becomes contaminated and an odor is sensed.

When an air-line respirator is used, a minimum of two working respirators must be available on the job before any employee is allowed to enter the circuit breaker tank.

Disposal of waste

All materials used in the cleanup operation for large quantities of SF6 arc products shall be placed in a 55­ gal drum and disposed of as hazardous waste.

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TYPES OF BUS BAR SYSTEM

TYPES OF BUS BAR SYSTEM

1 Single Busbar System

Single busbar system is as shown below in figure 

Single Busbar System

a. Merits

1. Low Cost

2. Simple to Operate

3. Simple Protection

b. Demerits

1. Fault of bus or any circuit breaker results in shut down of entire substation.

2. Difficult to do any maintenance.

3. Bus cannot be extended without completely deenergizing substations.

c. Remarks

1. Used for distribution substations up to 33kV.

2. Not used for large substations.

3. Sectionalizing increases flexibility.

2 Main & Transfer Bus bar System

Main & Transfer Bus is as shown below in figure 

a. Merits

1. Low initial & ultimate cost

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

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

b. Demerits

1. Requires one extra breaker coupler.

2. Switching is somewhat complex when maintaining a breaker.

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

c. Remarks

1. Used for 110kV substations where cost of duplicate bus bar system is not justified. 

3 Double Bus bar Single Breaker system

Double Bus Bar with Double Breaker is as shown below in figure 

a. Merits

1. High flexibility

2. Half of the feeders connected to each bus

b. Demerits

1. Extra bus-coupler circuit breaker necessary.

2. Bus protection scheme may cause loss of substation when it operates.

3. High exposure to bus fault.

4. Line breaker failure takes all circuits connected to the bus out of service.

5. Bus couplers failure takes entire substation out of service.      

c. Remarks

Most widely used for 66kV, 132kv, 220kV and important 11kv, 6.6kV, 3.3kV

Substations.

4 Double Bus bar with Double breaker System

 Double Bus Bar with Double breaker system is as shown below in figure 

a. Merits

1. Each has two associated breakers

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

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

4. High reliability

b. Demerits

1. Most expensive

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

c. Remarks

1. Not used for usual EHV substations due to high cost.

2. Used only for very important, high power, EHV substations.

5 Double Main Bus & Transfer Busbar System

Double main bus & transfer bus system is as shown below in figure

a. Merits

1. Most flexible in operation

2. Highly reliable

3. Breaker failure on bus side breaker removes only one ckt. From service

4. All switching done with breakers

5. Simple operation, no isolator switching required

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

7. Bus fault does not remove any feeder from the service

b. Demerits

1. High cost due to three buses

c. Remarks

1. Preferred by some utilities for 400kV and 220kV important substations.

6 ONE & HALF BREAKER SCHEME

a. Merits

1. Flexible operation for breaker maintenance.

2. Any breaker can be removed from maintenance without interruption of load.

3. Requires 1 1/2 breaker per feeder.

4. Each circuit fed by two breakers.

5. All switching by breaker.

6. Selective tripping.

b. Demerits

1. One and half breakers per circuit, hence higher cost

2. Any breaker can be removed from maintenance without interruption of load.

c. Remarks

1. Used for 400kV & 220kV substations.

2. Preferred.

7 RING OR MESH ARRANGEMENT

a.      Merits

Bus bars gave some operational flexibility.

b.      Demerits

1. If fault occurs during bus maintenance, ring gets separated into two sections.

2. Auto-reclosing and protection complex.

3. Requires VT’s on all circuits because there is no definite voltage reference point.

4. Breaker failure during fault on one circuit causes loss of additional circuit because of breaker failure.

These VT’s may be required in all cases for synchronizing live line or voltage indication

c.       Remarks

 Most widely used for very large power stations having large no. of incoming and outgoing lines and high power transfer.

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