Power Plant Gyan

Steam turbine condenser losses

2023-04-28T18:00:00.000+05:30

The condenser in a steam turbine system plays a critical role in the power generation process by converting the exhaust steam from the turbine back into water, which can then be reused in the boiler. However, the condenser itself can experience losses, which can impact the overall efficiency of the system.

Condenser losses can be broadly classified into two categories: thermal losses and mechanical losses.

Thermal losses occur due to the temperature difference between the condensing steam and the cooling water. This temperature difference can lead to heat transfer losses and reduce the efficiency of the system. Factors that can impact thermal losses include the temperature and flow rate of the cooling water, the surface area of the condenser tubes, and the design of the condenser.

Mechanical losses occur due to the resistance of the condenser components, such as the tubes, baffles, and pumps, to the flow of steam and cooling water. This resistance can lead to pressure losses and can impact the overall performance of the system. Factors that can impact mechanical losses include the design of the condenser, the materials used in its construction, and the operating conditions of the system.

To reduce condenser losses and improve the efficiency of the steam turbine system, it is important to optimize the design and operation of the condenser. This can include using high-efficiency tubes and heat transfer surfaces, optimizing the flow of steam and cooling water, and ensuring proper maintenance of the system. Additionally, advanced control systems can be used to monitor and adjust the operating conditions of the system, further reducing losses and improving efficiency.

Losses in steam turbine

2023-04-27T18:00:00.003+05:30

There are several types of losses that occur in a steam turbine, which can impact its overall efficiency. These losses include:

1. Friction Losses: Friction losses occur due to the resistance between the moving parts of the steam turbine, such as bearings, seals, and other components. These losses can lead to increased wear and tear on the turbine components and can reduce its efficiency.

2. Windage Losses: Windage losses occur when the rotating blades of the turbine interact with the surrounding air, creating turbulence and resistance. This can result in increased power requirements and reduced efficiency.

3. Blade Profile Losses: Blade profile losses occur due to the shape and design of the turbine blades. The shape of the blades can impact the amount of steam that can flow through the turbine and can lead to increased losses.

4. Leakage Losses: Leakage losses occur due to steam escaping from the turbine, either through the sealing components or through the blade clearances. This can result in reduced efficiency and can impact the performance of the turbine.

5. Condenser Losses: Condenser losses occur due to the inefficiencies of the steam condenser that is used to convert the exhaust steam back into water. These losses can be significant and can impact the overall efficiency of the steam turbine.

Reducing these losses can improve the overall efficiency of the steam turbine. This can be achieved through the use of improved materials, better design, and more advanced control systems. Proper maintenance and operation of the steam turbine can also help to minimize these losses and improve its performance.

Oxygen trimming in coal fired boiler

2023-04-26T18:32:00.005+05:30

Oxygen trimming is a process used in coal-fired boilers to optimize combustion efficiency and reduce emissions. The term "oxygen trimming" refers to the control of the amount of excess oxygen in the combustion process by adjusting the air flow and fuel flow rates.

In a coal-fired boiler, air is typically supplied to the combustion chamber through a series of air registers. The amount of air supplied is typically greater than the amount of oxygen required for complete combustion of the coal. This excess air is referred to as "excess oxygen."

Oxygen trimming involves monitoring the level of oxygen in the flue gas and adjusting the air and fuel flows to maintain the desired level of excess oxygen. By reducing the amount of excess oxygen, combustion efficiency can be improved, which in turn reduces the amount of fuel required to generate a given amount of steam or heat.

In addition to improving combustion efficiency, oxygen trimming can also reduce emissions of nitrogen oxides (NOx), which are formed during high-temperature combustion in the presence of excess oxygen. By reducing the amount of excess oxygen, the peak temperatures in the combustion process are reduced, which can result in lower NOx emissions.

Overall, oxygen trimming is an effective method for optimising combustion efficiency and reducing emissions in coal-fired boilers.

Why canister vent is provided in condensate extraction pump?

2023-04-21T21:33:00.008+05:30

A canister vent is provided in a condensate extraction pump in a thermal power plant to prevent the buildup of air and other gases in the pump casing. As the pump operates, air and other gases can enter the casing and collect in the top of the casing, reducing the efficiency of the pump and potentially causing damage.

The canister vent is a small opening in the top of the pump casing that is connected to a vent pipe. The vent pipe is typically routed to a location where the air and other gases can be safely vented to the atmosphere.

By providing a canister vent, the air and other gases that collect in the top of the pump casing can be continuously vented to the atmosphere, preventing the buildup of pressure and ensuring that the pump operates efficiently. This helps to prevent damage to the pump and reduces maintenance requirements.

In addition, the canister vent also helps to prevent the formation of a vacuum inside the pump casing. A vacuum can occur when air and other gases are not properly vented from the pump, leading to a loss of suction and reduced pump efficiency. The canister vent helps to prevent this by allowing air and other gases to escape from the pump casing, ensuring that the pump operates effectively and efficiently.

TURBINE TRIP PROTECTIONS

2021-07-13T10:39:00.001+05:30

There are the following turbine trip protections are given:-

Emergency push button trip from desk & operator work station (OWS)

Channel-1
Channel-2
Channel-3

Fire Protection (Channel-1 & Channel -2) from control desk & OWS Channel-1,Channel-2 & Channel-3. & MBLD 1 & 2 (from MOT room & TG floor)
Condenser vacuum low trip 2/3 (2 out of 3 logic).
Lubricating Oil pressure very low 2/3 (2 out of 3 logic).
HP exhaust steam temperature. Very high 2/3 (2 out of 3 logic).
Axial shift Very high 2/3 (2 out of 3 logic).
HP Casing top bottom differential Temperature Very high (2 out of 2 logic) & load greater than 20% of rated load
IP casing Front & Rear Top-bottom differential Temperature Very high (2 out of 2 logic) & load greater than 20% of rated load.
Cold gas temperature after H₂ cooler high (2 out of 3 logic).
Seal oil temperature after cooler high (2 out of 3 logic).
Liquid level in main leads high (2 out of 3 logic).
Hot air temperature exciter high (2 out of 3 logic).
Primary water temperature after cooler high (2 out of 3 logic).
Stator water winding outlet flow low (2 out of 3 logic).
Main bushing R flow low (2 out of 2 logic)
Main bushing S flow low (2 out of 2 logic)
Main bushing T flow low (2 out of 2 logic).
Boiler trip to Turbine trip.
Generator trip to Turbine trip
MOT level very low (2 out of 3 logic) (Through Fire Protection logic)

FIRE PROTECTION

Fire Protection

Fire Protection – Channel-1 & channel -2 can be initiated from Push buttons on turbine desk.
HMI panel.
Push buttons in MOT room
Push buttons at TG Floor
MOT level very low

If Fire Protection channel-1 or channel-2 acts, following operations take place

Emergency trip of turbine.
Oil system shutdown
Control Fluid System shutdown
Vacuum breaker opens if Generator breaker is close.

***

BOILER FEED PUMP OPERATING INSTRUCTION

2021-07-12T22:04:00.003+05:30

PREPARATION FOR STARTING

Check the Deaerator is filled to normal working level.
Check that the control air and electrical supply are available for the instrumentation, leak-off equipment and valve.
Check that the recirculation valve and isolating valve are open.
Check that all the instrumentation tapping points and isolating valve are open and that all drains equalizing valves are shut.
Open feed pump drive end and non-drive end mechanical seal cooler circulation water inlet and outlet isolating valve.
Check that the pump set discharge isolating valve is open.
Crack open the pump set suction isolating valve.
Open the booster stage air vent valve and vent any trapped air or gases from the pump casing.
Shut the booster pump air vent valve when water issues freely from it.
Note the interconnecting pipework and the boiler feed pump discharge pipework should also be primed and vented.
Vent the feed pump mechanical and the cooler
Fully open the pump set suction valve.
Ensure that the clarified cooling water and the raw cooling water are available for the pump set.
Prepare the drive motor for starting.
Prepare the hydraulic coupling and the lube oil system for starting.
Ensure that all instruments and coolers have been primed and vented.
Check that the lube oil is flowing freely through the following flow indicators.
Booster pump DE & NDE bearing drain flow.
Booster pump side and hydraulic side motor bearing drain flow.
Feed pump DE & NDE bearing drain flow.
Check that the D.M. water from the booster pump mechanical seals is flowing freely through the flow indicators.
Check that the D.M. cooling water from the feed pump mechanical seal coolers is flowing freely through the flow indicators.

STARTUP

Ensure that the hydraulic coupling auxiliary lubricating oil pump is running.
The following condition must be fulfilled before the pump set driving motor can be started.

Pump set suction valve fully open.
Recirculation valve open.
Lube oil pressure at a minimum of 2 bar.

Deaerator level not low-low.
D.M. cooling water pressure to pump set normal.
Start the boiler feed pump set driving motor.
NOTE:- simultaneously with the starting of the boiler feed pump set, a cooling water valve will automatically open to supply D.M. cooling water to the drive motor air coolers and the hydraulic coupling working oil coolers.

RUNNING CONDITION:-

When the pump set is running normally there circulation valve ensures a minimum flow of 100 t/hr through the pump set.
A scoop tube on the hydraulic coupling is controlled by a pneumatic actuator to automatically vary the speed of the boiler feed pump according to the load requirement, from a differential pressure transmitter across the feed regulating valve.
The auxiliary lubricating oil pump should be stopped.

ROUTINE CHECKED:-

Check that the driving motor ammeter reading is normal.
Check that all the pressure and temperature reading are normal.
Check that the lubricating oil is flowing freely through the following indicators
Booster pump DE & NDE bearing drain flow.
Booster pump side and hydraulic side motor bearing drain flow.
Feed pump DE & NDE bearing drain flow.
Check that the DM cooling water from the booster pump mechanical seal is flowing freely the flow indicators.
Check for any undue noise or vibration.
Check for joints and valves gland for leakage.
Check the security of all fastening, paying particular attention to the holding down bolts.

STAND BY CONDITION:-

When a pump set is required for standby duty, it should be prepared as follows.
Set the selector switch to auto condition.
Open the discharge valve.
Start the auxiliary lubricating oil pump.
NOTE: - The scoop of the standby pump set will follow the scoop tube of the running pump set.

TRIP CONDITION

The operating feed pump set will trip when any of the following abnormal condition exists.
Deaerator level low-low.
Lube oil pressure in common header low.
Differential temperature rise between the discharge and suction of the feed pump, above the pre-set value.
Hydraulic coupling working oil temperature high.

***

NATURAL DRAFT HYPERBOLIC COOLING TOWER IN THERMAL POWER PLANT

2021-07-05T20:31:00.005+05:30

Typical power-plant cycles which incorporate the natural-draft hyperbolic cooling tower are shown in the schematics.

~~FIGURE~~

Introduction:-

Note that only 40% of heat-energy input is converted to power in the fossil-fuel plant, while 45% is discharged to condenser cooling water; the remaining 15% is lost up the stack & in the ash.

A nuclear plant is even less efficient, converting only about 33% of its heat energy input into power, with 62% discharged to cooling water & 5% lost.

Remember, nonetheless, that heat discharges from electric power plants are among the lowest of all energy-conversion processes.

A natural draft hyperbolic cooling tower are evaporative in design, they contain no fans.

Working principle:-

Flow of air through shell is created by the density difference between atmospheric air and that inside the tower which has been warmed by the hot water from plant condensers.

As with the mechanical-draft-type, two basic airflow schemes in relation to water flow are cross flow & counter flow.

In counter flow design provides the more efficient means for heat transfer because coolest water contacts coolest air initially, although uniformity of air and water distribution achieved in cross flow type may offset this advantage.

In the cross flow design, air flow is normal to water movement, and usually more fill is required to transfer a given amount of heat; however, the cross flow tower has a lower air-pressure drop. Selection of either arrangement depends primarily upon operating conditions required.

Heat transfer, of course, takes place within the tower's fill area: with cross flow towers, this section is outside the shell.

Typically, the area consists of wood, asbestos-cement or plastic fill, glass-reinforced polyester grids for supporting the fill; poured or precast support beams and support columns; and asbestos-cement or polyvinyl chloride (PVC) drift eliminators, placed behind the fill to separate water droplets that may become entrained in the air stream.

Basic fill arrangements are splash packing and film packing (sketches above).

Function of both is to generate as much air/water interface as possible with minimum air-pressure loss.

In the splash type, usually selected for cross flow towers, hot water falls over wave shaped fill in such a way that the droplets are constantly reforming, and thus presenting a fresh surface to the cooling air.

In the film type, most often found in counter flow towers. The sheet-like fill consists of multiple vertical surfaces down which hot water flows in extremely thin continuous films; cooling air passes over these films. Film-type fill occupies less volume, generally requires less shell height, but is more subject to clogging; splash packing is somewhat easier to repair or replace, if necessary.

A distribution system dispenses inlet hot water evenly over the fill. Typically system for a cross flow tower consists of vertical risers and an open water-distribution basin (left sketch above). Condenser hot water is pumped through risers to the basin" from which water flows through holes set in a precast-concrete slab. A nozzle is installed in each hole, with an integral splash plate that distributes hot water evenly over the fill surfaces below" For a counter flow tower, risers feed a closed-pipe system; cross piping contains nozzles for even distribution of water to the fill.

The basin at the bottom of the tower collects the cooled water for return to plant condensers.

It is sized to hold enough water to parried tower operation for several hours without having to add makeup water.

A drain system is normally integral with the basin, for removal of silt deposits; this system also acts to control basin water level in case of flow surges.

Cold-water return is most often a sloped canal at bottom of the collecting basin, which feeds into circulation pumps. Screens are placed ahead of the pumps to prevent debris and other foreign matter from entering return system.

A hyperbolic tower, then, is an hour, glass-shaped structure sitting on "stilts" in a shallow basin of water. The stilts, or diagonal support columns, provide an open area through which air enters the shell. In a counter flow tower, the fill is located above the columns inside the shell; in a cross flow tower, the fill is external to the shell and forms an annular ring around the base. A canopy seals the ring to the shell.

In either type of tower, hot water from plant condensers is pumped to the

Top of the fill, and flows or splashes down through the fill to the basin, while air sweeps either up or across the fill area. Above the fill the 300 feet or more of the tower is empty, functioning merely as a chimney.

***

CONDENSATE EXTRACTION PUMP (CEP) IN A THERMAL POWER PLANT

2021-07-04T20:46:00.002+05:30

CONDENSATE EXTRACTION PUMP (CEP)

Its Importance in Thermal Power Plant

It handles water from hot well.
The characteristic of that pump is that it handles water from vacuum.
Berceuse the condenser and the hot well are in vacuum bellow atmospheric pressure.
No other pump has this characteristic to handle in such condition.
It takes water from vacuum pressure and delivered above atmospheric pressure.
It is a vertical turbine type pump which is multi stage.
It deliver water from hot well to deaerator.

They may be used to pump the condensate produced from latent water vapors in any of the following mixtures:

Steam condensed (exhaust from LP turbine) in condenser
Make up water (dumped in condenser hot well from condensate storage tank)
Flash box water
LPDFT water
HPDFT water
Drip from ejector
Drip from LPFWH

CEP for a 200 MW unit:-

Each unit has been equipped with three nos. of condensate pumps installed vertically at minus four meter level in to the turbine hall. Two pumps is required to run on the full load of turbine and one pump mill remains 50% stand by.
This group is characterized as having bearings lubricated with the pumped liquid.
These pumps are popular in multi-stage construction.
The impellers discharge into a vertical support column housing the rotating shaft.
These pumps are often installed into deep well water applications.
The impellers are commonly mixed flow types, where one stage feeds the next stage through a bell shaped vertical diffuser.
Electrically powered (6.6 kV)centrifugal pumps.

FUNCTION:-

Condensate pump takes suction from condenser and delivers condensate water to deaerator through main ejectors, gland coolers and L.P.heaters.

TECHENICAL DATA FOR A CEP IN A 200 MW UNIT:-

PUMP

Multistage (9 stage), vertical turbine type centrifugal pump, low specific speed.

Medium head

Medium capacity

Direction of rotation: clock wise viewed from motor end.

Type: BHRC 28

Size 300x250

Discharge: 281 tons/hour

RPM: 1489

BHP: 256

Motor HP: 300

CAUTION: not to run bellow 193 M barometric heat.

MOTOR:

3 phase, 50 Hz, cosΦ=0.84

Voltage: 6600v

Power 220KW, H.P.:300

Weight : 3000kg

***

Cooling Towers

2021-07-03T12:00:00.144+05:30

In a power plant large amount of heat is rejected which is a byproduct. This heat can not ignored & it is rejected from the primary system (CW system) to a secondary system (atmosphere).

Physically atmosphere is treated as a heat sink in which heat is dumped with the help of air or water.

Cooling system are three distinct types:-

Once-through cooling:- Waste heat is transfer with the help of cooling water which is receive & discharge to a rivers or lakes sea.
Evaporative cooling:- Waste heat is dissipated to the atmosphere by evaporation of a small portion of the cooling water. it require cooling towers.
Dry cooling:-Heat is dissipated directly to the atmosphere. it require air cooled heat exchangers.

In once through cooling system water is taken from natural resources & after cooling process hot water is dumped in to the again in natural resources so there is a thermal effect on the natural water resources.

So once through cooling is then replaced by evaporative cooling in which natural draft of mechanical draft cooling towers are used. A cooling towers recirculate water, which can be an advantage that better control of water quality is possible than once through cooling system. But in evaporative cooling temperature of cooling water is not too low as compare to once through cooling. So the quantity of cooling water is more required as compared to once through cooling. Also air is not an efficient cooling medium. In evaporative cooling makeup water is required.

Design inputs for cooling towers:-

Water flow
Water temperature
Local weather conditions, siting
Environment closely studied.
Energy conservation attempted in tower design & operation.
Optimum water usage.
Increased heat-transfer capability.
Improved with the turbine/condenser circuit.
Hyperbolic towers
Evaporative mechanical draft towers
Large and small towers
Dry and wet/dry towers
Cooling-tower maintenance
Chemical treatment and noise control.

Cooling system terms:-

Approach:-Difference between cold-water temperature & measured wet-bulb temperature.
Blow down: - Water discharged from the system to control concentration of salts or other impurities in the circulating water.
Cold-water temperature: - Temperature of the circulating water leaving the tower.
Cooling range: - Difference between the hot-water temperature and the cold-water temperature.
Cycles of concentration: - Compares dissolved solids in makeup with solids in the circulating water. Since chlorides are soluble, for example, cycles of concentration are equal to ratio of chlorides in circulating water to chlorides in makeup.
Drift: - Water lost from the tower as liquid droplets entrained in the exhaust air. It is independent of water lost by evaporation. Eliminators control this loss in cooling towers.
Heat load: - Heat removed from the circulating water within the tower. It may be calculated from the range and the circulating water flow and is generally expressed in kj/hr.
Hot-water temperature:-Temperature of circulating water entering the distribution system.
Makeup:-Water added to the circulating water system to replace water lost from the system by evaporation, drift, and blow down & leakage.
pH:- Number between 0 and 14 indicating degree of acidity (below 7) or alkalinity (above 7): 7 denotes a solution that is neutral.
Pumping head: - Minimum pressure required to lift water from basin level to the top of the tower and force it into the water-distribution system. Pumping head is equal to static head plus friction loss and pressure drop through the distribution system.
Recirculation (recycle):- That portion of the exhaust air which re-enters the tower. Unit: percent of total entering-air quantity which is exhaust air.
TDS: -Total dissolved solids contained in solution in cooling-system water.
Water loading:- Circulating water flow expressed in litter/squire meter of effective horizontal wetted area of the tower, a factor in the unit's ability to meet design cold-water temperature.
Wet bulb temperature: - Temperature indicated by a psychrometer. Also known as the thermodynamic wet-bulb temperature or the temperature of adiabatic saturation.

***

Purposes of Condensate System

2021-07-02T21:03:00.004+05:30

The purposes of the Condensate system are to:

Condense steam from the main turbine and TDBFP and collect steam drains in to the main condenser.
Remove non-condensable gases from the main condenser.
Purify and preheat water prior to injection into the boiler.
Supply the driving head to pump water from the main condenser to the boiler.
Provide injection path for High Pressure Coolant Injection system to the bpoler
Provide injection path for Reactor Core Isolation Cooling system to the boiler.
Provide a path for returning Reactor Water Cleanup system to the boiler.

There are the following system involved in condensate system.

CST (condensate storage tank)

Condenser

Hotwell

CEP (Condensate extraction pump)

Main ejector

Gland steam condenser

Deaerator level control valve

Excess return to CST

CEP minimum re-circulation line

Drain cooler

LPH-1 (Low pressure feed water heater-1)

LPH-2 (Low pressure feed water heater-2)

LPH-3 (Low pressure feed water heater-3)

Deaerator

FST (Feed storage tank)

LP heaters drains & vents

LPDFT (Low pressure drain flash tank)

HPDFT (High pressure drain flash tank)

***

STEAM TURBINE OPERATION

2021-07-01T13:58:00.003+05:30

Steam turbines are started based on operating instructions which is developed by original equipment manufacturer.

Start-up includes a sequence of actions followed as according to various parameters.

During start-up of turbine maintaining the limit values of operating parameters.

Start-up of turbine is a complicated operation as it consists of starting of various equipment and auxiliary systems.

Turbine start up is a transient & non-stationary actions like,

Transient heating
Varying steam flows
Acceleration of rotors

Three basic phases can be distinguished in the process of steam turbine unit

Turbine preparation to start-up,

Running-up to idle run and synchronization,

o Turbine to start-up begins with turning gear or barring gear.

o The turning gear operated by electric (electric turning gear) or hydraulic (hydraulic turning gear)

o Before start up of turbine it is thermally stablished

o its deflection line must coincide with the gravity deflection line.

o Rotor cooling down during standstill would be leading to its thermal bent due to faster cooling from the bottom, which would lead to rubbing and damage of labyrinth seals of blades & shaft.

o Prior to cold start, the turbo-set rotating system should be rotated using turning gear as long as possible.

o The turning gear can be switched off only when the highest temperature of HP & intermediate pressure (IP) inner casing is lower than 100⁰C.

o If needed, the turning gear can be switched off for 15 min after a day of barring, and after 2 days of barring – for about 30 min on the condition that vacuum is broken and gland steam supply is switched off.

o The maximum time of turning gear standstill depends of the type of turbine.

o Prior to repeated switch on of the turning gear, turbine rotor must be manually turned by one revolution in order to check if rubbing has not taken place. If rubbing is found it is necessary to wait until the rotor rotates freely and only then the turning gear can be repeatedly switched on.

Before starting of barring gear turbine lub oil system should be started.
The turning gear can be switched on only when all jacking oil pumps are in operation.
After starting the oil system and turning gear, the condensation system can be started, that is cooling water, air ejection and condensate pumping systems.
Simultaneously, gland steam system is started to prevent air in-leakage.
Gland steam must have appropriate temperature and pressure which must be controlled during start-up.
Prior to supplying steam to the turbine, the steam supply pipelines have to be drained and heated up.
In case of turbines with cooling water preheating and low-pressure (LP) bypass, prior to supplying steam the regeneration and dumping systems have to be started.

Run-up to idle run and synchronization

One can distinguish three major types of start-ups:
• From a cold state – when HP and IP inner casing temperature is lower or equal 170C,
• From a warm start – when HP and IP inner casing temperature is lower or equal 430C,
• From a hot state – when HP and IP inner casing temperature is greater than 430C.

Low NOx Burners

2021-01-23T18:00:00.003+05:30

A low NOx burners is a multi fule burners as :-

Coal

Gas

Oil

A low nox burners have following benifits

This burner provide most effective NOx reduction without affecting boiler performance.

With high rate of firing there are some NOx are formed.

As per air quality index it should be exist within prescribed limit.

Heavier oil leads to higher nitrogen content. Lightoil contain less nitrogen.

Thelow nox burners are modified axial flow burners with

Reduced excess air

More split air stream

Gas recirculation at time.

Working principal of low nox burners

Lower excess at r reduce the tendency of form nox due to the scareity of oxygen.

As the air stream is split the combustion takes place in stage and this protected combustion does not permit flame temperature to reach this peak.

So flame starve of both temperature and free air which suppracing the nox forming tendancy.

This reduce more than 50% nox reduction.

For achieving 70% NOx reduction flue gas from furnace are recirculated and reduce the burner temperature.

The mass flow in burners is maintained in this way for adequate turbulence but with no addition of oxygen.

For reducing nox followings methods are used.

Supply the combustion air at several stages.

Seprating primary and secondary air stream by flue gas to slow down combustion.

Adjusting the fuel feed positions.

Coal Pulverizer System

2020-11-19T06:06:00.003+05:30

Coal pulverizer system is classified in two types

Direct fired system.

Stored fired system.

DIRECT FIRE SYSTEM:-

In it coal leaving from each mill goes directly to the combustion process.

Air dry the fuel and evaporated the moisture also increase the fuel temperature. This hot fuel air mixture goes for combustion in to the furnace.

STORAGE FIRE SYSTEM:-

In this system coal is separated from air or gas.

In this system moisture is separated and not participate in combustion process.

Stored ground coal is injected in to the furnace with new air.

Requirement of direct firing system:-

Raw coal feeder- this regulate the coal quantity in to the mill.

Heat source:- this dry the coal and preheat the air and fuel.

Primary air fan:- this supply the air to the mill.

Piping:- direct the coal and primary air to and from the mill.

Burner:- this mix the coal and primary air from the pulverizer to the burners.

What is Boiler Specifications ?

2020-10-03T01:38:00.002+05:30

Boilers are specified by four parameter as listed:-

Steam flow rate or evaporation
Steam outlet pressure
Steam outlet temperature
Feed water inlet temperature

Steam Flow or Evaporation or Boiler Output:-

This is the amount of steam generated from the FW supplied at a certain temperature.

It is the capacity or the rating of the boiler expressed in ton per hours.

Boiler ratings are better designated by the heat duty than evaporation.

Super heater outlet pressure:-

It is the pressure at which steam is available for further consumption.

Usually it is approximate 5% higher than process or turbine inlet pressure to account for the piping loss.

In fixed-pressure boilers, this pressure is held constant as the turbine inlet valves vary the steam pressure to the inlet nozzles.

SH Outlet Temperature:-

Super heater outlet temperature is the temperature at which the steam leaves the super heaters.

It is the highest temperature gain by the steam in a boiler.

RH steam is sometimes slightly higher than the superheat steam in utility boilers.

Feed Water Temperature:-

Feed water temperature varies from as low as 85°C for very low-capacity boilers and as high as 270°C in very high-pressure power plants with several stages of feed heating.

Feed water temperature 270°C attained with the help of feed heating system.

CIRCULATION

2020-09-14T17:40:00.002+05:30

Circulation is the flow of water, steam or both through the tube circuits of a boiler (from boiler drum,boiler down comer, riser water walls).

Adequate circulation is necessary for all the circuits to remove the heat from the boiler furnace and cool the heating surfaces by carry the heat.

Due to carry the heat from the the metal surfaces the temperature of metals remain cools within a specific limit.

Sufficient circulation in provided in steam water circuit to avoid any salts deposits on the inner metallic surface of boiler.

In a circuit if the fluid enters at the inlet and leaves the outlet to the next circuit it is a once through system. If part of the fluid from the outlet of the circuit is returned to the inlet of the same circuit it is a re circulation system.

In a boiler the following circuits always adopt once through system.

Economiser
Super heaters
Re heaters

In these circuits the inlet pressure of the fluid effects the circulation. The water walls or evaporator circuits of a boiler will have either a once through or re circulation system. Many boilers for these circuits adopt only re circulation system.

CIRCULATION TYPES :

In the evaporating circuits of a steam-generating unit, the circulation may be produced naturally by the action of the force of gravity, mechanically by means of pumps or by a combination of the two. Accordingly there are three types of circulation as follows:

Natural circulation
Forced circulation
Assisted circulation.

NATURAL CIRCULATION :
This is adopted in re circulation systems. Water from the economiser circuit enters a drum and joins the circulation system. Water entering the drum flows down through the down comer pipes kept in non heating zone and enters the bottom of the water wall tubes, that is the evaporator section. As these tubes are heated by furnace radiation, a part of the water is converted to steam and the mixture flows back to the drum. In the drum the steam is separated. Remaining water mixes with the incoming water from the economiser and the cycle is repeated.

This sort of steam generation is adopted to

prevent the dissolved salts in water, precipitating and depositing scale on the surface of tubes when all the water in the tube is evaporated to steam.

Ensure the inner walls of the tubes are continuously wetted with water and to have nucleate boiling throughout the tubes.

The circulation in this case takes place on the thermo-siphon principle. The down comers contain relatively cold water, whereas the water wall tubes contain steam water mixture, whose density is comparatively less. This density difference is the driving force for the mixture to over come the frictional resistance. Circulation takes place at such a rate that the driving force and frictional resistance are balanced.

As the pressure increases the difference in density between water and steam reduces. Thus the hydrostatic head available will not be able to overcome the frictional resistance for a flow corresponding to the minimum requirement of cooling of water wall tubes. Therefore natural circulation is limited to boiler with drum operating pressure around 175 kg/cm².

ASSISTED CIRCULATION:

Beyond 175 kg/cm² of pressure in a re circulation system, circulation through the evaporator is to be assisted with mechanical pumps to overcome frictional losses in the tubes. A pump called Boiler circulation pump will be placed between the drum and water wall tubes inlet to do this function.

In such a system some times to regulate the flow through various tubes in accordance to the amount of heat received orifice plates will be used at the inlet of the tubes. Such a system is known as Controlled Circulation.

FORCED CIRCULATION :

In the once through systems of sub critical pressure or in boilers operating above critical pressure, the water from the feed supply is pumped to the inlet end or ends of the heat absorbing circuits. This is called forced circulation. Evaporation or change of state gradually takes place along the length of the circuit and when evaporation is complete, further progress through the heated circuits results in superheating the vapor. Conventionally this type of forced circulation requires no steam and water drum.

CIRCULATION NUMBER :

The circulation number is the ratio of the quantity of water-steam mixture flowing through the circuit to the quantity of steam produced in the circuit. In other words if 10 kg of water is circulated for each kg of steam generated, the circulation number is 10. The circulation number for a boiler will be decided considering many factors especially to ensure nucleate boiling is maintained for all operating conditions.

Higher circulation number reduces the chance of scale formation in evaporating tubes and DNB but needs more evaporating surface.

The general practice adopted for circulation number in various boilers is:

i) Natural Circulation Industrial boiler 10 to 15

ii) Natural Circulation Utility boiler 7 to 9

iii) Assisted Circulation boilers 2 to 4

iv) Forced Circulation/Once through boiler 1

***

Furnace Safeguard Supervisory System (FSSS)

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Introduction :-

The Furnace Safeguard Supervisory System (FSSS) is designed for

To assure the execution of a safe, orderly operating sequence in the start up & shut down of fuel firing equipment.
To prevent errors of omission and commission in following such a safe operating procedure.
The system provides protection, should there be a malfunction of fuel firing equipment and associated air systems.
The safety features of the system are designed for protection in most common emergency situations.

Basic Functions of FSSS:-

Prevent any fuel firing unless a satisfactory furnace purge sequence has first been completed.
Prevent start-up of individual fuel firing equipment unless certain permissive interlocks have first been satisfied.
Monitor and control the proper component sequence (manual or automatic) during start-up and shutdown of fuel firing equipment.
Make continued operation of fuel firing equipment subject to certain safety interlocks remaining satisfied.
Provide components status feedback to the operator.
Provide flame supervision when fuel-firing equipment is in service and initiate fuel trip upon certain adverse operating conditions.
Provide master fuel trip when certain adverse operating conditions exists.

FSSS is provided for a natural circulation, HO fired boiler with coal as primary fuel and light oil (LO) as the start-up fuel.
Heavy oil (HO) is used as fuel for warm up and stabilization.
The system provides three elevations (AB, CD, EF) of high-energy arc (HEA) igniters, oil guns with atomizing steam in all four corners.
Only AB elevation has LO firing guns with atomizing air.
CD & EF elevation
This boiler has six elevations (B,B,C,D,E,F) of coal firing with 24 coal nozzles.
Mill system includes bowl mill, seal air fan, primary air fan, coal feeder, hot air gate, mill inlet / outlet gates hot /cold PA control dampers.
Discriminating scanners are provided for sensing flame of both coal and oil.

Boiler Trip Conditions :

Both ID fans OFF.
Both FD fans OFF.
Total Air flow (secondary + primary) less than 30% of MCR.
Furnace pressure very high (+150 mmwc).
Furnace pressure very low (-175mmwc).
Drum level very high (+225mm) 10secs delay.
Drum level very low (-225mm) 5 secs delay.
Loss of all fuel trip.*

{*Loss of fuel trip generates when all coal feeders OFF and (all LONV closed or LOTV closed) and (all HONV closed or HOTV closed). Logic is armed from any oil nozzle valve not open.

Loss of reheat protection 10 secs delay. **

(**Loss of Reheat protection generates when any coal feeder proven and generator Circuit Breaker open and (any HPBP or LPBP valve < 2%). When turbine is in service either of the HPCV or HPBP and either of the IPCV or LPBP both valves should be open > 2% and any feeder proven.)

Loss of 220V dc > 2secs.
Loss of unit critical supply (24V dc).
Loss of 110V AC > 2secs & loss of fireball. ***

{***Loss of 110vAC & loss of fireball happens when all feeders OFF and 110vAC fails in an oil elevation in service or in a coal elevation with mill ON condition.}

Generator class-A trip.
Flame failure trip. ****

****Flame failure logic exists in coal firing condition only. Coal elevation not in service votes for flame failure. If running coal elevation monitoring fireball scanner not showing 2/4 flame and is not supported by ¾ oil guns then it will also vote. If any feeder running and all coal elevation vote for flame failure then flame failure logic acts and boiler trips on flame failure.)

Both emergency push buttons pressed.

Purge Permissive :

No boiler trip condition persists.
All HAGs closed.
All PA fans OFF.
All feeders OFF.
All HONV closed.
All LONV closed.
HOTV closed.
LOTV closed.
All scanners sensing no flame.
Aux air dampers modulating.
Air flow > 30% & < 40% MCR.

If all these conditions are fulfilled then ‘PUSH TO PURGE’ light glows. Press ‘PURGE START’ button. 300 secs purge timer starts. Boiler trip circuit resets after purge complete provided no permissive missed in that period of 300 secs.

Selection Of Light Oil / Heavy Oil Firing :

Oil elevation AB is provided with HO / LO firing. Permissive for changeover are follows:

Both pairs of oil gun stopped.
All HO/LO nozzle valves closed.
HO/LO start permit available.

LOTV LOGICS:

If MFR reset and LO header pressure adequate then LOTV can be operated.

Protections (OR logics):-

MFT (2/3).
Light oil header pressure very low.
Atomizing air header pressure very low.
NO light oil elevation in start or stop.
LOTV is commanded to close by hard wire circuit on loss of +24V DC.

HOTV LOGICS :

Once MFR resets and all HONV close and HORV open and HO header pressure and temperature is adequate then HOTV can be open / close.

Protections:

MFT.
HONV not closed and atomizing steam pr very low and no oil elevation in start / stop > 2 secs.
HONV not closed and HO header pressure very low >2 secs.
HO header temp very low and any HONV nozzle valve not closed >2 secs and HORV valve not open.

LIGHT OIL ELEVATION START:

Select light oil firing. Then check following conditions:

No master fuel trip.
LOTV open.
Pulverizer / feeder start permit available. i.e. nozzle tilt horizontal and air flow >30% and <40% or any feeder ON

PAIR MODE/ELEVATION MODE LOGIC:-

For both LO and HO oil guns are put into service by sequence control logic.

Pair Mode:-

Pressing pair start (1-3 or 2-4) PB, provided the above conditions are satisfied will initiate a 70 secs start time to place the associated light oil guns in service. Second oil gun gets start command after 15 secs.

Elevation Mode:-

When associated coal feeder is in service, oil guns acts under elevation mode. I.e. all four guns put in or out by single command.

When any of the pair ON PB pressed two things happens a) Elevation start command is issued for corner 1&3 b) A 40 secs counting period is started to established an elevation start command for corner 2&4. After 70 secs if ¾ nozzle valves are not proven then “unsuccessful elevation start” alarm is initiated. This will stop corner 1&3 and after 40 secs stop corner 2&4.

This pair mode & elevation mode logic is same for both HO & LO elevations.

CORNER TRIP LOGIC (HO):-

Oil gun not engaged.
Lo selected .
Ho man isolation valve not open.
Local maintenance switch.
Steam atomizing man isolation valve not open.
Corner start time / scavenge time expired & (corner no flame or HONV not open or steam valve not open).

Similar logic will be there for light oil guns.

START-UP LOGIC:

STEP 1: Open steam / air atomizing valve

STEP 2: If atomizing valve opens then advance HEA igniter

STEP 3. If HEA rod advanced then open HONV / LONV and spark HEA igniter for 15 secs

STEP 4: If HEA rod retracted and oil valve open in condition and disc scanner shows Flame then end step sequence.

If flame does not stable within 15 secs from oil valve open then corner trip Initiated. All the valves of that corner closed and HEA igniter withdrawn.

SHUT-DOWN LOGIC:

STEP 1: Close HONV/LONV.

STEP 2: After oil valve closes, open steam / air atomizing valve.

STEP 3: After atomizing valve opens, HEA advances & scavenge valve opens. After advancement of HEA sparks for 15 secs.

STEP 4: After scavenge time of 300 secs atomizing and scavenge valve close.

HORV OPERATION:-

Any HONV not close condition is the protection close for HORV.

All HONV close is Open permissive.

MILL LOGICS:-

Seal Air Fan:

MFT and electrical trip are the protections for this drive.

This can be run when no protection present.

SAF outlet damper can be opened by operator after 40 sec of SAF ON.

Seal air to Pulverizer inlet damper is automatically open when SAF ON and SAF outlet damper open.

It closes by Pulverizer trip command (30secs pulse ).

HAG Logics:-

Mill outlet temp >110o C for >=30 secs and MFT are the protection close.

When no protection is present it can be opened and if PA fan OFF then it can be closed also.

Mill Discharge Gate:-

This can be opened any time by open command.

But it can be closed when PA fan OFF & PA general shut off damper closed.

Mill Lube Oil Pump:-

When one pump running and lube oil pressure low or flow low occurs then 2nd pump will takes start.

When Mill running and running pump for any reason gets OFF, 2nd pump will take start.

Mill Inlet Gate:-

This can be open any time by open command. Off permissive is Feeder OFF.

PA General Shut Off Damper:-

If PA fan ON and mill discharge valve open then it can be opened. Pa fan OFF closes this damper automatically.

PA Fan Permissives:-

No MFT
PA inlet damper in min position
PA general s/o damper closed
Ignition permit available *

{*Ignition permit available when adjacent oil elevation has 3/4 oil gun in service or adjacent coal feeder has feeding >50% (18 tph). }

Coal elevation start permit available **

{**One running FD fan can give start permit to 1st three coal elevation. 2nd FD fan is required for 4th coal elevation.}

PA lube oil system o.k.
Cold air damper <5%
Mill release available ***

{*** Mill release : Available when PA fan ON or (CAD<5% and PA general shut off damper close & burner all manual isolation valves open and feeder inlet / outlet gate open and HAG, CAG open and mill lube oil o.k. and mill gas pressure not low or not very low.}

No pulverizer trip
Seal air system o.k ****

{**** Seal air system O.K. will be available when seal air fan ON & SAF o/l damper open and SA to pulverizer inlet damper open and seal air to hot PA DP >100 mmwc.}

PA breaker in service

PA Fan Protections :

Pulverizer trip
2/3 MFT
PA fan electrical trip
PA fan lube oil system failed (lube oil pressure 0.4 kgf cm-2 < more than 60 secs)
Loss of FD fan trip (for D, E, F elevation)

Mill Permissives:-

Mill release available.
PA fan ON >20 secs.
PA general s/o damper open.
Ignition permit available.
Coal elevation start permit available.
Pulverizer / feeder start permit available.
Pulverizer outlet temp not low (>65degC).
Mill both discharge valves open.
Pulverizer breaker in service.

Pulverizer / feeder start permit:-

Burner tilting horizontal and total air flow < 40% or any feeder running > 53 secs.

Pulv Trip Logics:-

1.Pulv ON and (seal air to hot PA DP low (<100mmwc) >70 secs or seal air fan OFF >60 secs).

2. 2/3 MFT

4. MILL ON and PA fan OFF

5. Mill outlet temp>110 o C and feeder ON 6. Mill release not available

7. Electrical trip

8. Any mill discharge valve not open>3 secs

9. Ignition permit not available and Ignition permit required.

10. Mill gas pressure very low

11. Mill lub oil pressure very low>3 secs or (both lube oil pump OFF or lube oil flow low)>5 secs.

Feeder Permissives:-

1. Coal on belt

2. Feeder in remote

3. Pulverizer / feeder start permit

4. Ignition permit

5. Coal elevation start permit

6. Mill outlet temp not high and not low.

Feeder protection:-

1. Ignition permit not available and Ignition permit required

2. Mill outlet temp high

3. 2/3 MFT

4. No coal on belt

5. Feeder discharge plugged

6. Pulverizer trip

“Ignition permit required” signal is generated when feeder status (ON / OFF) changes and it lusts for 3 minutes.

Flame scanner:

We have 5 elevations (AB, BC, CD, DE, EF) of optical scanner, which can convert flame frequency and amplitude to a current signal.

Coal and oil flame is discriminated by different flame frequency i.e. coal flame frequency 3.5 to 10 Hz and oil flame frequency 24 to 30 Hz.

It thresholds the amplitude and gives flame / no flame switching signal to FSSS.

Secondary Air Damper Control:

Coal air damper:- A, B, C, D, E, F modulates as a function of coal feeding in auto mode.

Oil air damper:- AB, CD, EF Opens 70% when oil gun in service. Else acts as aux air damper.

Aux air damper:- BC, DE Modulates in auto to maintain wind box to furnace DP. DP set point is a function of boiler load.

Over fire dampers:- Modulates in auto as a function of boiler load to prevent SOx, NOx. When MFT operates, all these dampers are forced to 100% open and stays there for 5 mins.

Scanner Fan:-

Two scanner air fans (AC, DC) are provided. Normally AC fan is running if it trips or scanner duct to furnace DP low (150mmwc) comes then DC fan takes start. Scanner fan normally takes suction from FD fan discharge and supply air to the flame scanner duct. One emergency damper is provided in the suction. In case of both FD fan OFF, this damper will provide alternate suction.

Mill Fire Fighting Inerting System:-

After mill trip, fire fighting inerting command can be given. It closes Mill inlet / outlet gates, general s/o damper, seal air to mill inlet damper. After that all the steam valves to mill open for 30 secs. After 30 secs steam valve closes and cycle stops.

***

NORMS FOR EMISSION OF SOx, NOx, SPM & MERCURY FROM THERMAL POWER PLANTS

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The notification from MoEF & CC dated 7th December-2015 amends existing norms related to emission of SPM and introduces new norms for emission of SO2, NOx and Mercury from Thermal Power Plants (TPPs).
It also specifies modified limits for specific water consumption by TPPs.
To convert existing once through based condenser cooling system to recirculation type.
Different limits are specified based on capacity of power plant and year of installation.

NEW REGULATIONS ON EMISSION

A summary of new regulations on air emission is given in below:

Date of
Installation

PM

SO2

Nox

Mercury (Hg)

Before
31-12 -2003

100 mg/Nm3

600 mg/Nm3 for <500MW

600 mg/Nm3

0.03 mg/Nm3 for >=500MW

200 mg/Nm3 for >=500MW

After 01-01-2003 & Upto 31-12-2016

50 mg/Nm3

600 mg/Nm3 for <500 MW

300 mg/Nm3

0.03 mg/Nm3 for >=500MW

200 mg/Nm3 for >=500MW

0.03 mg/Nm3

On or after 01-01-2017

30 mg/Nm3

100 mg/Nm3

100 mg/Nm3

0.03 mg/Nm3

NEW REGULATION ON WATER USE
All plants with Once through Cooling (OTC) shall install Cooling Tower (CT) and achieve specific water consumption up to maximum of 3.5 m3 /MWh within a period of two years from the date of publication of notification.
All existing CT-based plants reduce specific water consumption up to maximum of 3.5 m3 /MWh within a period of two years from the date of publication of notification.
New plants to be installed after 1st January 2017 shall have to meet specific water consumption up to maximum of 2.5 m3 /MWh and achieve zero waste water discharged.

MOEF & CC HAS SUBSEQUENTLY ISSUED AN AMENDMENT DATED 28 TH JUNE 2018 FOR STACK HEIGHT POST FGD AND WATER CONSUMPTION WHICH IS MENTIONED BELOW:

INDUSTRY

PARAMETER

STANDARDS

TPS with FGD

stack height /limit in meters

Power Generation capacity :
100 MW and above
H = 6.902 (QX0.277)0.555
Or
100 m Whichever is more

Less than 100 MW H = 6.902 (QX0.277)0.555 Or 30 m Whichever is more

Q = Emission rate of SO2 in kg/hr*
H = Physical stack height in meter
*Total of the all units connected to stack
Note: These standards shall apply to coal /lignite based Thermal Power Plant.

All monitored values for SO2 and NOx shall be corrected to 6% Oxygen, on dry basis.
Specific water consumption shall not exceed maximum of 3.0 m3/MWh for new plants installed after the 1st January 2017 and these plants shall also achieve zero waste water discharge.
Seawater based plants are exempted from conversion of once through to Cooling Tower based system

The SO2 reduction technology shall be done considering following factors:

1: Sulphur Content in Coal.
2: SO2 removal Efficiency requirement of particular plant.
3: Availability of Reagent (if Any).
4: Disposal and handling of By-product.
5: Locational/Geographical factors of the plant.
6: Plant life.
7: Space requirement for FGD facility

AUXILIARY POWER CONSUMPTION for FGD:

Auxiliary Power Consumption (APC) is estimated to be maximum 1% for FGD operations. In case GGH (Gas to Gas Heater) is used maximum 0.3% additional APC may be required.

Generator cooling system

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Generator cooling system

INTRODUCTION

In a big turbo-generators where a huge mass of metal is used. As as current flows through conductors large heat is generated in the winding of stator and rotor of generator. When turbo generator is started then heat generation in metallic parts are starting if this heat is not removed from the generator then this is chance to failed the generator winding.

As in generator large amount of heat is generated and is not possible to dissipate this heat from natural system. So forced cooling system is adopted. in force cooling system air or hydrogen gases are used.

In smaller turbo-generators, the cooling is by air circulation. In bigger turbo generator hydrogen cooling system came in the field.

So efficient cooling & ventilation system is required for generator to keep temperature of winding bellow certain limits.

For the cooling of generator following system is adopted

Air cooling system - In this air is forced into the generator due to which large amount of heat is removed. Air is forced circulated inside generator. This air is pick up the heat from conductors of the generators and further air is cooled in a heat exchange in which cooling water is flowing. In generator small ducts are provided in which air is flowing. The heat dissipation with air cooling system is limited. It is used in small size generator. This system is some limitations like it is not possible to use in a large size of generator. The air should be clean and free from dust & moisture (So instrument air is supplied through a line).There is an optimum rating of the generator beyond which air cooling system is not economical because of air have a limit of heat for heat transfer. In air cooling system is simple and there are no any special arrangement is required.
In air cooling system two methods are used:-

Open cooling system- In this cooling system air is drawn from the atmosphere and after cooling exhausted in to the atmosphere.
Closed cooling system - In air cooling system stator and rotor of the generator is cooled by air. this air is circulated within the generator with the help of fans installed on the generator rotor. cold air pick up the heat from winding and rotor and cold down in a water cooler installer in side the generator casing. In generator coolers cold DMCW is flowing.

Air cooling system is used in small size units.

Hydrogen cooling system-In hydrogen cooled system hydrogen gas is used as a medium for cooling. Hydrogen gas is filled at a higher pressure than atmosphere(generally 3.5 to 4.0 ksc). this hydrogen gas is then circulated within the turbo generator with the help of fans mounted on the generator rotter. after cooling down of stator and rotor with the help of hydrogen gas, heated hydrogen gas is cools down in hydrogen coolers. In hydrogen coolers cold DMCW water is flowing. this DMCW further cooled down with the help of ACW system.
Mix of hydrogen & water cooling system- In it DM water is used for stator winding cooling & rotor is cool down with the help of hydrogen gas at a pressure range 3.5 to 4.0 ksc. For stator cooling a separate system is installed called as primary water system.this system is more complex. In this two system is installed as

Hydrogen cooling system
Stator water cooling system

Hydrogen cooled Generator

Water Cooled Generator
As hydrogen cooling is not sufficient to extract heat generated in large turbo alternators of sizes 500 MW or more. For such large machines, the volume of hydrogen gas required may be so large that its use may become uneconomical.
In such cases, the direct water cooling is used. In very large turbo-generators, rotors are direct hydrogen cooled and stator winding are direct decriminalized water cooled. Water is circulated by an AC motor centrifugal pump. Cartridge filters are used to filter water. These filters are designed to prevent metallic corrosive particles generated in winding and piping from entering into winding hollow conductors.

Advantages of Water Cooling Over Hydrogen Cooling
Water cooled system is faster and more efficient because the thermal conductivity of water is higher than that of hydrogen.
The duct area of water is smaller to allow more space for conductors in the slot.
Disadvantages of Water Cooling
The water, which is used for cooling should be highly purified so that the conductivity of water does not increase.
Water cooling is more expensive than hydrogen cooling.
The cooling system is adopted according to size & capacity of generator.This cooling system prevent that no hot spot is occur at the winding.

Generator consists of the following components:

Stator
Stator frame
End shields
Stator core
Stator winding
Hydrogen coolers
Rotor
Rotor shaft
Rotor Winding
Rotor retaining rings
Field connections
Bearings
Shaft seals

The following additional auxiliary systems are required for generator operation:-

Oil system
Gas system
Primary water system
Excitation system

some important notes
This is shield is gas tight.
For sealing of small clearance gap between frame with end shield is silicone gel is used which focally inserted.
This gel is inserted when the generator is assembled on site.
At each overhauling of generator a new seal is created.
When the generator is running excessive heat is generated within the generator conductor & this heat is not coming out from the generator.
In generator heat is generated in both stator and rotor conductor.
So cooling is required for the efficient operation of generator.

For the cooling of generator stator and rotor conductor following methods are used:-
a. Generator hydrogen cooling system
b. Stator water cooling system
c. Rotor water cooling system.

In generator all three methods are used and any of two may be used. It is depend on the designer which system is adopted.
If the generator is small size then air is used as a cooling medium.
This air or hydrogen is circulated by axial fans installed on both sides of the rotor shaft ends & rotated with rotor speeds.
When rotor running then axial fan at both end is forced the gas from both end towards the inner side in axially direction.
The design of rotor is such that some of gas is flow in to the small ducts inside the rotor in axially direction & exit out at radially from holes in conductor.
After this gas is pick up the heat from rotor and mixed with fresh cold gas and again flow outwards in radially direction through stator core and cool the stator core.
The hot gas is cooled by circulating cooling water in generator hydrogen coolers.

Each side of the generator stator frame is closed by end shield.

CIRCULATING WATER SYSTEM

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CIRCULATING WATER SYSTEM

· The circulating water system supply cold water to the condenser.

· The cold water absorbs the latent heat of condensation from exhaust steam in the form of sensible heat.

· Steam exhaust from low pressure steam turbine condenses in a condenser & condensed water reused in the cycle again.

· In a surface condenser, the steam flows over a tube bundle & condensed and cooling water flowing inside the tubes.

· Heat is transferred from steam to water with the help of tubes. Tubes are works as a barrier between cooling water and stem to be condensed.

· Further the temperature of cooling water increases and become warm.

· It is a continuous process in which heat is continues removed from the condenser.

· This warm water reject their heat to the atmosphere through cooling towers or spray ponds or warm water dumped in to the natural water reservoir

· In all thermal power plants surface condenser are used for condensing the steam

· Two different systems are used to flow the water in to the condenser.

o Once through system or open cooling system.

o Closed loop system.

ONCE THROUGH SYSTEM OR OPEN COOLING SYSTEM.
In this system water from a large water reservoir (like sea, or river or lake) is pumped to the condenser.
When water become warm then returned back to the same source at different location.
So this system is used where a large quantity of water is available.

Scheme of once through cooling system…

CLOSED LOOP COOLING SYSTEM

The second is the closed loop cooling system circulating water is in a closed circuit.

The Circulating water removes the heat from the condenser and flows to cooling towers.

In the cooling towers airflow, natural or forced, cools the water and the water returns to the condenser.

Power plants located away from large sources of water utilize this type.

The large concrete hyperbolic towers that you see near thermal power plants are used for cooling the circulating water.

In cooling towers loss of water takes place due to the evaporation to the atmosphere and it replaced by makeup water.

Feed water system

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In a boiler feed water system following sub systems are involved.

FST
Booster pump
Boiler feed pump
Drive of boiler feed pump (motor or turbine)
High pressure feed water heater
Feed regulating station / feed control station
Economiser

Feed Storage Tank

Water is pumped from feed storage tank to the boiler or boiler drum with the help of boiler feed pump. there are two or three boiler feed pumps are installed in a single unit. this is a high pressure pump. the discharge pressure of this pump is greater than that the boiler drum pressure due to which water in flow in to the boiler drum.

Boiler feed pump is a special type of pump. this is a multistage pump. generally a multistage pump is called as a turbine type pump.

FST(Feed Storage Tank) is a part of Deaerator which reserve store the treated condensate water. fst may be an integral part of deaerator or it may be installed bellow the deaerator tank.The FST is installed at a specific height to provide the NPSH to the boiler feed pump.

The treated water is a medium to the boiler called as boiler feed water and this water is free from any dissolved gases and oxygen.

The working pressure and temperature of boiler feed water system is very high.

Heat released by the burning of fuel is supplied to the boiler feed water which supplied to the boiler. So finally feed water is converted in to the steam in the boiler after receiving the heat.

Boiler feed pump

It is a multistage centrifugal pump.

It generate higher pressure against the boiler drum pressure.

The boiler feed pump drive of two types

Electric motor driven boiler feed pump.

Turbine driven boiler feed pump.

Boiler feed pump always keep hot stand by. If any pump failure occurs then standby pump auto start.

Suction pipe of boioer feed pump is connected th the discharge of booster pump.Booster pump suction line is connected to the heat Storage tank.

A suction isolation valve is connected before booster pump. Also a suctio strainer is installed in between suction valve and booster pump. For monitoring the differential pressure a DP monitoring instrument is installed in suction in let and out line.

In a unit feed water balance is as given

Feed water flow = boiler evaporation rate+ boiler blow down.

Feed water flow = fresh makeup water + return condensate water + incoming drip to Deaerator+ steam supplied to Deaerator.

Generally in a plant approximate 70 to 80 % of condensate return.

Diagram

Deaeration of water in Deaerator

Mechanical deaeration takes place in to the Deaerator

In Deaerator all dissolved gases are removed. For best quality chemical treatment is carried out.

Why deaeration is carried out

to remove oxygen carbon dioxide and other non condensable gases in coming from condensate water.

To heat the incoming condensate water at an optimum temperature before supplying to the boiler.

Treated boiler feed water prevent the corrosion in the boiler.

Complete oxygen removal is not possible by mechanical deaeration alone.

With the help of deaerator oxygen concentration in feed water is reached upto 7 ppb or 0.005 cc/l and zero free carbon dioxide.

this oxygen is further removed by the chemical treatment with the help of oxygen scavengers. For oxygen removal oxygen scratches are you which are prepared in separate chemical tank and it dosed in the suction of boiler feed pump.

This provide complete protection of the boiler against oxygen corrosion.

In condensate water oxygen concentration is high.

Oxygen entered at the following points.

LP turbine gland

Valve gland connected to condensers.

Leakage through condenser flanges.

Makeup water additions (as CST is open to atmosphere)

Air leakage to vacuum breaker.

FST is a fully pressurized tank innwhich large quantity of treated condensate water is stored.in smaller system it Deaerator and feed storage tank are integral part.for increasing the temperature of feed storage tank water steam is supply. When steam is supply to FST highly noise is created.

As hot water contain less oxygen for carry.

After downstream of FST ammonia and hydrazen ase added.

A water level indicator is fitted to the FST for measurement of water level.

Why Hydrogen Cooling

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Why Hydrogen Cooling

Lowest density gas yields lowest drag
Highest heat conductivity of any gas
Controlled atmosphere to maintain Clean & Dry
Inexpensive
Easy to detect
Excellent electrical properties
Easy to manage – not readily miscible with CO2 purge gas
Flammable

Hydrogen Flammability Range

Hydrogen has a wide flammability range generally 4% to 75% hydrogen in air is hydrogen flammability range.
So 4% is lower flammability range & 75% is upper flammability range. If hydrogen in air is bellow 4% then no chance of flame & if hydrogen percentage is above 75% then no chance flammable.then always in generator maintain hydrogen purity as higher as possible.above upper flammability level no chance of ignition if system is leak proof. Generator is always under pressure (higher than atmosphere).
Generally in generator casing hydrogen purity is maintain above 96%.

H₂ is lightest gas with 0.09 gm/litre while air is 1.3 i.e. 14.4 times.
Thermal capacity of H₂ as gas is high.
Thermal conductivity of H₂ is 5 times that of air.
Is specific heat is 3.42 at 0°C, as compared to 0.237 of air.
2 H₂ + O₂ mixture ignites on adiabatic compression at 526°C, and 3H₂ + O₂ at 544°C.

Generator Cooling System

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Generator Cooling System

Air cooled generator

In generator large amount of heat is generated and is not possible to dissipate this heat from natural system.
So forced air cooling system is adopted.
In this air is forced into the generator due to which large amount of heat is removed.
Air is forced circulated inside generator.
This air is pick up the heat from conductors of the generators and further air is cooled in a heat exchanger in which cooling water is flowing.
In generator small ducts are provided in which air is flowing.
The heat dissipation with air cooling system is limited. It is used in small size generator.
This system is some limitations like it is not possible to used in a large size of generator.
The air should be clean and free from dust & moisture (So instrument air is supplied through a line).
There is an optimum rating of the generator beyond which air cooling system is not economical because of air have a limit of heat for heat transfer.
In air cooling system is simple and there are no any special arrangement is required.

Hydrogen cooled Generator

In hydrogen cooled system hydrogen gas is used as a medium for cooling.
Water Cooled Generator
As hydrogen cooling is not sufficient to extract heat generated in large turbo alternators of sizes 500 MW or more. For such large machines, the volume of hydrogen gas required may be so large that its use may become uneconomical.
In such cases, the direct water cooling is used. In very large turbo-generators, rotors are direct hydrogen cooled and stator winding are direct demineralized water cooled. Water is circulated by an AC motor centrifugal pump. Cartridge filters are used to filter water. These filters are designed to prevent metallic corrosive particles generated in winding and piping from entering into winding hollow conductors.
Advantages of Water Cooling Over Hydrogen Cooling
Water cooled system is faster and more efficient because the thermal conductivity of water is higher than that of hydrogen.
The duct area of water is smaller to allow more space for conductors in the slot.
Disadvantages of Water Cooling
The water, which is used for cooling should be highly purified so that the conductivity of water does not increase.
Water cooling is more expensive than hydrogen cooling.

Generator Cooling Goals
Minimize drag windage
Keep generator internals clean
Maximize generator output
Minimize electrical, mechanical and corrosion problems
Maintain low dew point for component durability

LABYRINTH SEAL

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Its name from fact from its construction.
Labyrinth seals consist of series of thin strips fixed to the casing or other stationary member and arranged so as to maintain the smallest possible clearance with the shaft.

The labyrinth seals have small restrictions that increase the velocity of leaking fluid only to have it dissipated in the pockets, thereby throttling the fluid.
The tips of the strips are extremely thin so that if rubbing occurs the tip gets worn away without damaging the shaft.
These labyrinth seals do not prevent complete leakage of fluid. These are effective in only reducing leakage.

In it steam in leaking must follow a winding path and change its direction many times.
It is constructed from thin strip at the outer circumference of shaft of turbine at both end.
It is installed at the inner circumferential surface of casing at both end.
There are several types of Labyrinth packing is subjected to a throttling action.
This action produced a reduction in pressure with each groove that the steam passes.
The amount of leakage pass the packing depends upon the clearance between the stationary and the rotating element.
The amount of clearance is depend on type of turbine steam temperature and service condition.
The leak steam from labyrinth packing is piped to some low pressure system or to a low stage on the turbine.
In labyrinth packaging there are two parts

Fixed parts
Rotating parts

For sealing the shaft steam is used between the fixed and moving glands.
Each labyrinth consist of multiplicity of seal to minimize steam leakage.
It consist of seal ring which are under spring force due to in casing it maintain proper position and close clearance are maintain.
During operation it is cooled by steam supplied or by leak of steam.
This steam is maintain the seal temperature constant.
Each ring are decide into groups and after each group a chamber is provided.
Number of of chamber is depend on the steam pressure in the turbine end.
This chamber is work as supply or extract steam for sealing.

CONDENSATE EXTRACTION PUMP

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CONDENSATE EXTRACTION PUMP

SYSTEM DESCRIPTION

Condensate from condenser hot-well is pumped through LP heaters up to deaerator by Condensate Extraction Pumps (3 nos. CEP).
In full load operation two pumps will be in operation and one in standby condition.
CEP is of vertical sleeve type multi stage pump.
So it is called as turbine type pump.
Each pump is directly driven through an electric motor and is delivering to condensate water.
All the CEP are connected to a common header through a non-return valve and motorized discharge valve.
From that discharge header condensate passes through Gland Steam Condenser (GSC) and through a Deaerator control station.
By modulating this valve Deaerator level is maintained according to the set point given.
A recirculation valve is provided before Deaerator level control valve to maintain a minimum condensate flow through the pump & GSC.
The main condensate is passed through Condensate Polishing Unit, GSC, LP heater-1, LP heater-2, LP heater-3 and finally goes to deaerator.

From CEP discharge following water supplies are provided-

DMCW expansion tank makeup.
Vacuum pump separator tank normal make up.
Sator normal make up.
HPDFT & LPDFT spray for desuperheating.
TD BFP Gland seal de super heater
Condenser Exhaust hood spray
LP bypass desuperheating
TD BFP exhaust steam desuperheating
MS to APRDS steam desuperheating.

Make up for condensate system may be taken from Hot well makeup pump or makeup line in CST is installed on deaerator floor.

Special care to be taken during any CEP startup when condenser is under vacuum in any condition.
In this condition open canister vent to condenser slowly and watch the vacuum & then start opening the suction valve slowly.
Ensure vacuum is not dropping.
Charge the suction header slowly.

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Auxiliary Steam common Header Charging

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Auxiliary Steam common Header Charging

SYSTEM DESCRIPTION :

Aux steam system includes four ways of steam source:

Start-up boiler or aux boiler,(If it is available in plant )
Low-temperature reheated steam supply
Main steam steam supply line
Near by unit common header

In normal, each unit aux steam is supplied by CRH steam.

There is interconnection between aux steam headers of all units and also connected to start-up aux boiler.

Parameters of aux steam are:

Aux steam pressure normal range: 8-12 kg/cm2

Aux steam normal temperature: 300-350 deg C.

Initial conditions

Aux boiler is running
hot boxed-up condition
station APRDS

Pre Checks & Charging Procedure:

Ensure that Auxiliary Boiler is ready for Aux Steam header charging from aux. boiler.
Generally temperature maintain before charging from aux boiler between range is 180 to 300 deg C and pressure is 4 to 5 Kg/cm2
All the way from Auxiliary boiler MS stop valve to Start up steam line’s all drain valves should be open.
Auxiliary Steam common header drain valve should be open to atmosphere.

Following MOVs should be in closed condition initially:

i. Start up steam (Open in case of cold startup of aux boiler for aux steam requirement)

ii. Main Steam to Aux. steam header MOV & CV

iii. CRH to Aux. steam header MOVs and CV

iv. Aux steam to Gland sealing

v. Aux steam to Soot blower/fuel atomizing

vi. Aux. steam to Mill fire fighting

Aux steam header to Aux steam common header can be kept open.
Ensure that all the temperature and pressure measuring gauges are healthy.
Each attemperating or pressure reducing valve should be closed.

Steam Charging:

Ensure all the drains related to aux steam system charging are open.
Light-up the aux boiler. Ensure aux steam header is lined up for warm-up.
Open MS equalizing valve first to warm the line if aux boiler is running already for FOPH requirement. Keep observations for any water hammering in the line.
Ensure the aux steam system piping temperature is increasing. Open MS stop valve up to 5 to 10% intermittently after observing steam from all the line drains. Throttle MS stop valve if hammering is noticed wait for complete warm up.
Open start up steam MOV to 10-20% intermittently for initial warm up. Then open this MOV to 100% at a rate of 5-10% each time careful observation for line hammering. Ensure proper warm up of Aux steam common header (i.e. steam is coming from its drain).
Now close/throttle Aux steam common header drain and put trap in service after getting standard temperature. Maintain Aux steam common header temperature/pressure from Aux Boiler.

Aus steam Switchover from Aux Boiler to #3 MS line:

At MS temperature (>350degC) and pressure (>25 Kg/cm2 ) Aux steam header can be charged from MS line.
Normalize/line-up the MS to Aux steam header attemperation system.
Open the drain valve in MS to Aux steam header line and open MS to Aux steam header MIV. Then open upstream MOV of MS to Aux steam header to 100% slowly (keeping water hammering in mind).
Then open the pressure control valve to 5-8%.
After warm up close the drain valve and maintain the required header pressure and temperature while closing/stopping the Aux steam to Aux steam common header by opening CV of MS to Aux steam header.

Aux steam Switchover from MS line to CRH:

When CRH temperature is greater than 300 degC and pressure is greater than 20 Kg/cm2, the aux steam header can be charged from CRH line.
Open the drain valve of CRH to Aux steam header line. First open both the MIVs of main and by-pass line then open both the MOVs of main and by-pass line intermittently keeping water hammering in mind. Close the drain valve after proper warm-up of the line.
Now start charging the Aux steam header via CRH by opening the control valves while closing the MS to Aux steam header CV keeping Aux steam header pressure/temperature constant.
Close the drain valve after proper warm-up of the line.

Date of Installation	PM	SO2	Nox	Mercury (Hg)
Before 31-12 -2003	100 mg/Nm3	600 mg/Nm3 for <500MW	600 mg/Nm3	0.03 mg/Nm3 for >=500MW
		200 mg/Nm3 for >=500MW
After 01-01-2003 & Upto 31-12-2016	50 mg/Nm3	600 mg/Nm3 for <500 MW	300 mg/Nm3	0.03 mg/Nm3 for >=500MW
		200 mg/Nm3 for >=500MW		0.03 mg/Nm3
On or after 01-01-2017	30 mg/Nm3	100 mg/Nm3	100 mg/Nm3	0.03 mg/Nm3

INDUSTRY	PARAMETER	STANDARDS
TPS with FGD	stack height /limit in meters	Power Generation capacity : 100 MW and above H = 6.902 (QX0.277)0.555 Or 100 m Whichever is more
		Less than 100 MW H = 6.902 (QX0.277)0.555 Or 30 m Whichever is more
Q = Emission rate of SO2 in kg/hr* H = Physical stack height in meter *Total of the all units connected to stack Note: These standards shall apply to coal /lignite based Thermal Power Plant.