SAG in electrical power transmission.

What is  Sag.?

In electrical power transmission and mechanical design of overhead transmission line.

SAG.

A perfectly flexible wire of uniform cross-section, when string between the two supports at the same level, will form a catenary. However, if the sag is very small compared to the span, its shape approximation a parabola.

 The difference in level between the point of support and the lowest point on the conductor is known as sag 

The factors affecting the sag in an overhead line are given below.

1. Weight of the Conductor,

 This affect the sag directly. Heavier the conductor, greater will be the sag. In locations where ice formation takes place on the conductor, this will also cause increase in the sag.

2. Length Of the Span.

This also affect the sag. Sag is directly proportional to the square of the span length Hence other conditions, such as type of conductor, working tension, temperature etc. remaining the same a section with longer span will have much greater sag.

3. Working Tensile Strength.

The sag is inversely proportional to the working tensile strength of conductor if other conditions such as temperature, length of span remain the same. Working tensile strength of the conductor is determined by multiplying the ultimate stress and area of cross section and dividing by a factor of safety.

4. Temperature.

All metallic bodies expand with the rise in temperature and, therefore. The length of the conductor increases with the rise in temperature, and so does the sag.

Reference from .

Transmission and distribution of electrical power by-J.B.Gupta.

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What should be a Marking On Circuit Breakers...?

Marking On Circuit Breakers

Each circuit-breaker shall be marked in a durable manner.

a)  The following data shall be marked on the circuit-breaker itself or on a nameplate or nameplates attached to the circuit-breaker, and located in a place such that they are visible and legible when the circuit-breaker is installed;

1. Rated current (In).
2. Suitability for isolation, if applicable, with the symbolic Indication of the open and closed positions, with O and I respectively, if symbols are used.

b) The following data shall also be marked externally on the circuit-breaker, except that they need not be visible when the circuit-breaker is installed;

1. Manufacturer’s name or trade mark;
2. Type designation or serial number;
3. IEC 60947-2 if the manufacturer claims compliance with this standard;
4. Utilization category;
5. Rated operational voltage
6. Rated impulse withstand voltage;
7. Value (or range) of the rated frequency
8. Rated service short-circuit breaking capacity at the corresponding rated voltage;
9. Rated ultimate short-circuit breaking capacity at the corresponding rated voltage
10. Rated short-time withstand current, and associated short-time delay, for utilization category B;
11. Line and load terminals, unless their connection is immaterial;
12. Neutral pole terminals, if applicable, by the letter N;
13. Protective earth terminal, where applicable, by the symbol
14. Reference temperature for non-compensated thermal release, if different from 30 ‘C.

c) The following data shall either be marked on the circuit-breaker as specified in item b), or shall be made available in the manufacturer’s published information:

1. Rated short-circuit making capacity,
2. Rated insulation voltage, if higher than the maximum rated operational voltage,
3. Pollution degree if other than 3;
4. Conventional enclosed thermal current if different from the rated current,
5. IP Code, where applicable
6. Minimum enclosure size and ventilation data (if any) to which marked ratings apply;
7. Details of minimum distance between circuit-breaker and earthed metal parts for circuit-breakers intended for use without enclosures;
8. Suitability for environment A or environment B, as applicable,
9. R.M.S. sensing, if applicable

D)  The following data concerning the opening and closing devices of the circuit-breaker shall be placed either on their own nameplates or on the nameplate of the circuit-breaker; alternatively, if space available is insufficient, they shall be made available in the manufacturer’s published information:

1. Rated control circuit voltage of the closing device and rated frequency for alternating current
2. Rated control circuit voltage of the shunt release and/or of the under-voltage release, and rated frequency for Alternating current;
3. Rated current of indirect over-current releases;
4. Number and type of auxiliary contacts and kind of current, rated frequency and rated voltages of the auxiliary switches, if different from those of the main circuit.
5. Terminal marking.

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8 Major Advantages of Distribution Automation

8 Major Advantages of Distribution Automation

________________________________________________________________________________________________________

Economic Challenges

More and more electric utilities are looking to distribution automation as an answer to the three main economic challenges facing the industry:

1. The rising cost of adding generating capacity,
2. Increased saturation of existing distribution networks and
3. Greater sensitivity to customer service.[/info_box]

Therefore, utilities that employ distribution automation expect both cost and service benefits.

These benefits accumulate in areas that are related to investments, interruptions and customer service, as well as in areas related to operational cost savings, as given below:

1. Reduced line loss

The distribution substation is the electrical hub for the distribution network.

A close coordination between the substation equipment, distribution feeders and associated equipment is necessary to increase system reliability. Volt/VAR control is addressed through expert algorithms which monitors and controls substation voltage devices in coordination with down-line voltage devices to reduce line loss and increase line throughout.

2. Power quality

Mitigation equipment is essential to maintain power quality over distribution feeders.

The substation RTU in conjunction with power monitoring equipment on the feeders monitors, detects, and corrects power-related problems before they occur, providing a greater level of customer satisfaction.

3. Deferred capital expenses

A preventive maintenance algorithm may be integrated into the system. The resulting ability to schedule maintenance, reduces labour costs, optimizes equipment use and extends equipment life.

4. Energy cost reduction

Real-time monitoring of power usage throughout the distribution feeder provides data allowing the end user to track his energy consumption patterns, allocate usage and assign accountability to first line supervisors and daily operating personnel to reduce overall costs.

5. Optimal energy use

Real-time control, as part of a fully-integrated, automated power management system, provides the ability to perform calculations to reduce demand charges.

It also offers a load-shedding / preservation algorithm to optimize utility and multiple power sources, integrating cost of power into the algorithm.

6. Economic benefits

Investment related benefits of distribution automation came from a more effective use of the system. Utilities are able to operate closer to the edge to the physical limits of their systems. Distribution automation makes this possible by providing increased availability of better data for planning, engineering and maintenance.

Investment related benefits can be achieved by deferring addition of generation capacity, releasing transmission capacity and deferring the addition, replacement of distribution substation equipment. Features such as voltage/VAR control, data monitoring and logging and load management contribute to capital deferred benefits.

Distribution automation can provide a balance of both quantitative and qualitative benefits in the areas of interruption and customer service by automatically locating feeder faults, decreasing the time required to restore service to unfaulted feeder sections, and reducing costs associated with customer complaints.

7. Improved reliability

On the qualitative side, improved reliability adds perceived value for customer and reduce the number of complaints. Distribution automation features that provide interruption and customer service related benefits include load shedding and other automatic control functions.

Lower operating costs are another major benefits of distribution automation.

Operating cost reduction are achieved through improved voltage profiles, controlled VAR flow, repairs and maintenance savings, generation fuel savings from reduced substation transformer load losses, reduced feeder primary and distribution transformer losses, load management and reduced spinning reserve requirements.

In addition, data acquisition and processing and remote metering functions play a large role in reducing operating costs and should be considered an integral part of any distribution automation system. Through real time operation, the control computer can locate the faults much faster and control the switches and reclosures to quickly reroute power and minimize the total time-out, thus increasing the system reliability.

8. Compatibility

Distribution automation spans many functional and product areas including computer systems, application software, RTUs, communication systems and metering products. No single vendor provides all the pieces. Therefore, in order to be able to supply a utility with a complete and integrated system, it is important for the supplier to have alliances and agreements with other vendors.

An effective distribution automation system combines complementary function and capabilities and require an architecture that is flexible or “opens” so that it can accommodate products from different vendors.

In addition, a distribution automation system often requires interfaces with existing system in order to allow migration and integration, still monitoring network security.

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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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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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