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ONITORT

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This trainingwould never have been possiblewithout the help ofmany experiencedpersons,whopatientlyansweredmyquestions,andpointedme in the rightdirection inmyattemptstoexploretheinnerworkingsofsteamgenerationunit. ManythankstoTeam leaderBoilerArea,SaqibKhan,HRManagerHaroonRashidandwholeboilerteamwhohadmadethistrainingsessionavery learningandexcitingexperienceforme. Iamgrateful towholeboiler teamandAES Lalpir team for theirkindandgeneroussupporttheyhaveextendedtomeduringmytraining.

2

CONTENTS

ENERGYCONVERSIONINPOWERPLANT................................................................................3

RANKINECYCLE......................................................................................................................4

RANKINE CYCLE WITH REHEAT..4 REGENERATIVE RANKINE CYCLE..5

CLASSIFICATIONOFBOILER....................................................................................................6

MAIN PARTS OF BOILER ...................................................................................................7

ECONOMISER8

WATER WALL TUBES.8

STEAMDRUM....8

SUPER HEATERS9

REHEATER...9

ATTEMPERATOR.10

BLOW DOWN.10

WATER CIRCULATION IN BOILER12

BCPSTARTUPPROCEDURE....................................................................................................................13

BCPSHUTDOWNPROCEDURE................................................................................................................15

AIRANDGASSYSTEM:.........................................................................................................16

STACK..................................................................................................................................19

FLUEGASRECIRCULATION....................................................................................................21

PERFORMANCEWITHOILFIRING.........................................................................................22

SOOTBLOWING...................................................................................................................23

FIRINGEQUIPMENTSSTARTUPPROCEDURE........................................................................24

FIRINGEQUIPMENTSSHUTDOWNPROCEDURE...................................................................25

AUXILIARYSTEAMSUPPLYSYSTEM......................................................................................30

AUXILIARYBOILER................................................................................................................33

STEAM CONVERTER .........................................................................................................34

APPENDIX...38

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4

RANKINE CYCLE The Rankine cycle is a thermodynamic cycle which converts heat into work. The heat is

supplied externally to a closed loop, which usually uses water as the working fluid. This cycle generates about 80% of all electric power used throughout the world.

There are four processes in the Rankine cycle; these states are identified by number in the diagram to the right.

Process 1-2: The working fluid is pumped from low to high pressure, as the fluid is a liquid at this stage the pump requires little input energy.

Process 2-3: The high pressure liquid enters a boiler where it is heated at constant pressure by an external heat source to become a dry saturated vapor.

Process 3-4: The dry saturated vapor expands through a turbine, generating power. This decreases the temperature and pressure of the vapor, and some condensation may occur.

Process 4-1: The wet vapor then enters a condenser where it is condensed at a constant pressure and temperature to become a saturated liquid. The pressure and temperature of the condenser is fixed by the temperature of the cooling coils as the fluid is undergoing a phase-change.

In an ideal Rankine cycle the pump and turbine would be isentropic, i.e., the pump and turbine would generate no entropy and hence maximize the net work output. Processes 1-2 and 3-4 would be represented by vertical lines on the Ts diagram and more closely resemble that of the Carnot cycle. The Rankine cycle shown here prevents the vapor ending up in the superheat region after the expansion in the turbine, which reduces the energy removed by the condensers.

RANKINE CYCLE WITH REHEAT

In this variation, two turbines work in series. The first accepts vapor from the boiler at high pressure. After the vapor has passed through the first turbine, it re-enters the boiler and is reheated before passing through a second, lower pressure turbine. Among other advantages, this prevents the vapor from condensing during its expansion which can seriously damage the turbine blades, and improves the efficiency of the cycle.

5

REGENERATIVE RANKINE CYCLE

The regenerative Rankine cycle is so named because after emerging from the condenser (possibly as a sub cooled liquid) the working fluid is heated by steam tapped from the hot portion of the cycle. On the diagram shown, the fluid at 2 is mixed with the fluid at 4 (both at the same pressure) to end up with the saturated liquid at 7. The Regenerative Rankine cycle (with minor variants) is commonly used in real power stations.

Another variation is where 'bleed steam' from between turbine stages is sent to feed water heaters to preheat the water on its way from the condenser to the boiler.

The primary functions of the boiler are to provide superheated steam to the HP turbine and reheated steam to IP turbine. The boilers at Lalpir are Forced circulation, Radiant and Reheat water wall type boiler with the steam generating capacity of 1200 ton/hr at 541oC and reheat capacity of 947.5 ton/hr at 538oC. The boilers are classified into many groups on the basis of orientation, fuel, circulation, etc that are discussed below.

6

CLASSIFICATION OF BOILER

Boilers are generally classified into two types as

1- Fire tube Boiler 2- Water tube Boiler

1-FIRE TUBE BOILER

In fire tube boiler the hot combustion gases are passed through a series of tubes, the tubes are submerged in the boiler water and act as the medium of heat transfer. Fire tubes boilers are generally classified as shell boilers since water and steam are contained within a single shell that also houses the steam producing elements. The practical limit on operating pressure for standard fire tube boiler in the US is 250 psi (about 16 bars). This is primarily due to structural consideration. The auxiliary boiler is of fire tube type.

2-WATER TUBE BOILER:

James Barlow invented the first water tube boiler in 1793. As opposed to the fire tube design, where the combustion gases travel through the tubes submerged in the boiler water, the water tube boiler passes combustion gases over tubes, containing water. The hot gases transfer the heat necessary to raise the water temperature to the boiling point. The two major heat transfer areas existing in these boilers are

1- Radiant heat transfer areas 2- Convection heat transfer areas

7

MAIN PARTS OF BOILER

The main parts of the steam generation unit are briefly discussed below.

Fluegasesarereleasedtoatmospherethroughstack.

Waterdrum.

GRF

BCP

FURNACE.

1

2

34

57

6

8

1. PrimarySuperheater2. SecondarySuperheater3. TertiarySuperheater4. PrimaryReheater5. SecondaryReheater6. Economizer7. SteamDrum8. Desuperheater

8

ECONOMISER

In order for the boiler to absorb as much of the generated heat as possible, feed water first enters the boiler through the economizer section. The economizer section is a series of tubes that are normally located in the boiler "back pass," where flue gases pass before exiting the boiler and entering the air heaters. When firing drum type boilers, care must be taken to avoid over heating the economizer which can cause extensive damage to the boiler.

Economizers are nearly always a counter flow, water to gas type, with the water flowing up. This is done to maximize heat transfer, ensure a full section, and reduce the chance of water hammer. The tubes are arranged in horizontal bundles with the outlet at the top.

Water is then routed through economizer links to the next boiler component. Approximately 17-20% of total heat absorption in the boiler takes place in the economizer. As the feed water flows through these tubes, the thermal efficiency of the boiler is improved and less waste heat is lost to the stack. As a final result, less fuel is required to produce a given amount of steam.

WATER WALL TUBES

The water wall tubes are a series of parallel tubes that are welded together at the membrane (the flat piece of metal between tubes) to make up the gas tight walls of the fire box. On controlled circulation boilers, these tubes have generally orifice at the feed header to ensure proper distribution of flow through all of the water wall tubes. Ample water flow through these tubes is critical because of their direct exposure to the boiler flames.

The tubes are normally welded into the headers. On some smaller boilers it is not uncommon to have the tubes "rolled" into tapered holes in the headers, especially the drum. This type of construction results in a much weaker union that is more susceptible to damage from rapid temperature changes than is the welded construction type (under extreme cooling the tubes can actually pull out of the drum).

The boiler water first begins to boil and change into steam in the water wall tubes. Approximately 32% to 35% of the total heat absorbed by the boiler is done in the water walls. After water changes to steam, it returns to the steam drum(s). The steam drum normal level is typically half water and half steam. The steam at this point is not superheated and has small droplets of water in it.

STEAM DRUM

A steam drum is a standard feature of a water-tube boiler. It is a reservoir of water/steam at the top end of the water tubes. The drum stores the steam generated in the water tubes and acts as a phase-separator for the steam/water mixture. The difference in densities between hot and

9

cold water helps in the accumulation of the "hotter"-water/and saturated-steam into the steam-drum.

There are various separators in the drum to remove the droplets from the steam before the steam is sent to the primary superheater. These separators are normally arranged in stages, with the first stage commonly using centrifugal force to throw the droplets of water from the steam and allow them to run back into the water. From these separators the steam is then routed into a series of chevron-shaped plates of steel with relatively close tolerances between them.

As the steam passes through the torturous path presented by the chevron plates the majority of the remaining water is removed.

STEAMDRUM

SUPER HEATERS

Steam produced from a boiler without a superheater will either be dry saturated or, more likely, wet. In works where steam is transmitted over long distances, the inevitable heat loss from pipe surfaces causes the steam to become even wetter at the point of use unless a superheater is fitted to the boiler plant. This is a separate battery of pipes placed near the boiler furnace through which steam passes to receive additional heat by either convection or radiation. The superheater increases the surface area capable of accepting heat and the production of heat also slightly increases the thermal efficiency of the boiler. Steam flow must be maintained through the superheater to prevent the tubes being burning out and a thermometer should be fitted on the outlet header so that the operator can determine the degree of superheat.

RE HEATER

Reheater receive steam from HP turbine exhaust called cold reheat steam and heat it up close to SH steam temp. called hot reheat. In this way reheat system add some amount of energy to cold reheat steam, this increase the cycle efficiency. Reheat system transfer the heat of flue gases leaving the boiler to cold reheat steam.

10

ATTEMPERATOR

The spray attemperator nozzle is located in a special device installed in the piping connecting the superheaters. The attemperator body is constructed of a hardened, wear resistant material designed to withstand the tremendous forces of erosion present in this area. In addition, there is considerable thermal stress in this area due to the injection of cooler water, causing the construction to be segmented to allow rapid expansion and contraction of the components.

The spray attemperator works by the process in which water is sprayed into the header and it immediately flashes into steam. That implies that some of the enthalpy of the steam already in the header is transferred to the spray water. The more water that is sprayed into the header, the more the enthalpy drop in the steam's heat value. This loss in enthalpy results in a lower temperature.

There is also a spray attemperator located at the inlet of the reheat section. Use of the steam attemperator for cooling the reheater is usually, and preferably, not necessary because of the efficiency loss associated with its use. Normal temperature control of the reheat section is either done with dampers, by burner tilts, or fuel bias

BLOW DOWN

Another item of significant importance located in the drum is the blow down line. It takes its suction from slightly below the normal operating level. It is at this point with chemical addition that the suspended solids are gathered and blown out of the drum.

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11

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13

headers (in some cases referred to as mud drums) or to supply the suction header of the boiler water circulating pumps.

On controlled circulation units the boiler water circulating pumps are designed to ensure flow through the water wall tubes. This reduces the possibility of hot spots and the resultant tube metal overheating problems. Natural circulation type boilers do not use these pumps. The advantage of a controlled circulation boiler is the much faster allowable heat up rate and load change rate.

Since circulation through the water walls is not totally dependent upon a change in density, the boiler may be fired much harder and still remain within the proper temperature allowances. The downside for controlled circulation boilers is the operating costs. The boiler water circulating pumps are a sizable consumer of in-house power.

14

ADVANTAGES OF FORCED CIRCULATION OVER NATURAL CIRCULATION

Steam generation rate is higher. Greater capacity to meet load variation. Quick start-up quality from cold condition. Lower scaling problem due to high circulation velocity. More uniform heating of all parts reduces the danger of over-heating & thermal stresses In forced circulation boilers orifices are fixed in the inlet of each water wall of to distribute

the water to the water wall tubes according to the heat absorption rate across the tubes.

On a typical natural circulation boiler, start-up time is limited to a saturation temperature rise of 550C/hr. This limitation minimizes metal stresses associated with differential temperature across the thick steam drum metal. This temperature differential exists because circulation is dependent upon the density ratios of steam and water. Therefore, not all tubes start generating at the same time, so the drum surfaces are heated unevenly.

The forced circulation units have an even distribution of temperature. The circulating pumps and the drum force the circulation and recirculation flows. The saturation temperature rise rate is 1100C/hr, which is twice of a natural circulation unit.

In case of loss of power or cooling water flow, BCP cooling water outlet header shut off valve will close and shut off valve to open atmosphere will open to allow service water to drain after passing through BCP coolers.

BCP PRE START UP CHECKS 1st BCP pre-start-up Local checks.

Check suction valve open. Check discharge valve open. Check cooling water flow normal. (min. 15 m3/hr) Fill BCP cavity through BCP purge cooler and vent it thoroughly. Check pump casing and drum metal temperatures are almost equal. If not open casing vent to equalize the pump casing and drum metal temp. Check BCP cavity temperature is

15

c) When air free water is discharged through vent v/v, close filling v/vs. d) Re-open service v/v, this v/v must never be closed during boiler operation.

3) Vent the p/p as follows;

a) Open vent v/vs. b) When air free water is discharged, close the vents. c) Open the p/p suction v/v & stems of the discharge v/v.

4) Energize the motor. The current will drop from full starting current after a few seconds to approx. the value corresponding to the operating point on the makers test curve.

5) Ensure that the boiler is still full; energize the second duty p/p on line & run up to the speed. 6) Perform the operational checks below;

a) Amperage b) Motor cavity temperature on alarm thermometer c) Differential pressure d) Low pressure cooling flow & temperature e) Vibration f) Drum level g) Valve & gland leakage

7) Perform operational checks on the newly energized pump in detail.

BCP SHUTDOWN PROCEDURE.

Caution: Low pressure cooling water flow & motor temperature must always be within the specified limits, whenever the circulator is on hot standby.

1) Press the stop button on the control console. 2) Ensure that suction v/v & low pressure cooling line valves are open. 3) Close service v/v & open by-pass v/v to provide circulation of high temp. boiler water

through the pump casing, suction & discharge line.

16

AIR AND GAS SYSTEM:

The air and gas system is collection of different components that supplies combustion air to boiler and discharge flue gases away from the boiler through the stack

FORCED DRAFT FANS

The boiler has two forced draft fans that provide air for combustion pushes the flue gases out through the stack. They have inlet vanes to control the flow of air.

GAS AIR HEATERS

A number of metal plates are connected together to form a rotating heating element, which extracts the heat of flue gases leaving the boiler and transfer them to the combustion air. The cold end of the GAH is more vulnerable to corrosion because there are more chances of condensation of SO2 which causes corrosion.

Dew point is a temp. at which condensation is occurs. If condensation is allowed to take place in the presence of sulphur laden flue gas sulfuric acid can be produced which will damage the AH elements. Therefore air is pre heated with the help of steam air heater before sending it in the air heater.

The air heater has the following advantages,

-- It increases the boiler efficiency by raising the temperature of combustion air.

--The heated air increases the temperature of air /fuel mixture close to ignition so easily burned.

GAS RE CIRCULATION FAN (GRF)

One of the many ways to reduce NOx emissions is to use flue gas recirculation, a method that recycles some of the exhaust gases back to the furnace. For this purpose two GRFs are installed on each unit.

SPECIFICATIONS

Forced Draft Fan

Type Air foil double inlet

Capacity (volume) 12620 m3/min

Suction pressure 1040 mm aq

Delivery pressure 1100 mm aq

17

Control system inlet vane system

Speed 980 rpm

Motor capacity 3000 KW

Ignitor Fan

Type Turbo fan

Capacity (volume) 300 m3/min

Delivery pressure 100 mm aq

Speed 1500 rpm

Motor capacity 11 KW

Gas Recirculation Fan

Type Air foil double inlet

Capacity (volume) 3700 /5600 m3/ min

Delivery pressure 360 /410 mm aq

Control system inlet damper system

Speed 980 rpm

Motor capacity 610 KW

18

AIR AND GAS PATH

FURNACESECONDARY

PASS

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FLUEGASESARETHROWNTO

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FLUEGASESARERECIRCULATEDINTO

THEFURNACEFORNOxREDUCTION.

GASAIRHEATER

19

STACK

A stack is a structure for venting hot flue gases or smoke from a boiler, stove, furnace or fireplace to the outside atmosphere. Chimneys are typically vertical, or as near as possible to vertical, to ensure that the gases flow smoothly, drawing air into the combustion in what is known as the stack, or chimney, effect. The space inside a chimney is called a flue.

Chimneys are tall to increase their draw of air for combustion and to disperse pollutants in the flue gases over a greater area so as to reduce the pollutant concentrations in compliance with regulatory or other limits.

CHIMNEY DRAUGHT

When coal, oil, natural gas, wood or any other fuel is combusted in a stove, oven, fireplace, hot water boiler or industrial furnace, the hot combustion product gases that are formed are called flue gases. Those gases are generally exhausted to the ambient outside air through chimneys or industrial flue gas stacks (sometimes referred to as smokestacks).

The combustion flue gases inside the chimneys or stacks are much hotter than the ambient outside air and therefore less dense than the ambient air. That causes the bottom of the vertical column of hot flue gas to have a lower pressure than the pressure at the bottom of a corresponding column of outside air. That higher pressure outside the chimney is the driving force that moves the required combustion air into the combustion zone and also moves the flue gas up and out of the chimney. That movement or flow of combustion air and flue gas is called "natural draught/draft", "natural ventilation", "chimney effect", or "stack effect". The taller the stack, the more draught or draft is created. There can be cases of diminishing returns where a stack that is overly tall in relation with the heat being sent out of the stack where the flue gases cool prior to reaching the top of the chimney. This condition can result in poor drafting and in the case of wood burning appliances the cooling of the gases prior to exiting the chimney can cause creosote to form near the top of the chimney.

Designing chimneys and stacks to provide the correct amount of natural draught or draft involves number design factors, many of which require trial-and-error reiterative methods.

As a "first guess" approximation, the following equation can be used to estimate the natural draught/draft flow rate by assuming that the molecular mass (i.e., molecular weight) of the flue gas and the external air are equal and that the frictional pressure and heat losses are negligible:

where

Q = chimney draught/draft flow rate, m/s

A = cross-sectional area of chimney, m (assuming it has a constant cross-section)

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G = grav

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20

21

FLUE GAS RECIRCULATION

One of the many ways to reduce NOx emissions is to use flue gas recirculation, a method that recycles some of the exhaust gases back to the burner.

Flue gas recirculation has the following effects

The heat content of the exhaust air contributes to heat recovery The reduced oxygen content of the exhaust gases lowers the flame temperature in the

combustion zone, thereby reducing NOx formation The reduced flame temperature lowers heat transfer, potentially limiting the maximum

heating capacity of the unit (it would not be unusual for a boiler retrofitted with flue gas recirculation to produce a 10% reduction in maximum steam generating capacity).

NOx is one of the primary air pollutants emitted from combustion processes and environmental regulations are the only driver forcing industry to install NOx control systems. Most of the NOx formed during combustion of gas and light oil is from high temperature oxidation (or fixation) of atmospheric nitrogen and is referred to as Thermal NOx. NO is the major constituent of thermal NOx and its formation can be modeled by the Zeldovich equation:

[NO] = k 1 exp (-k2/T) [N2] [O2]1/2 t

where, [ ] = mole fraction, ks = constants, T = temperature, and t = residence time.

The equation indicates that NOx formation is an exponential function of temperature and a square root function of oxygen concentration. Thus, by manipulating the temperature or oxygen concentration, the formation of thermal NOx can be controlled. Systems manipulating the oxygen concentration are referred to as stoichiometry-based combustion control techniques (e.g. Low NOx Burners or LNBs) and those reducing the temperature are referred to as dilution-based combustion control techniques (e.g. Flue Gas Recirculation or FGR). LNBs control NOx emissions by providing air staging to create an initial, fuel-rich zone (partial combustion zone) followed by an air-rich zone to complete the combustion process. Some burner designs incorporate fuel staging that result in lower levels of NOx. Since NOx formation is a square root function of oxygen concentration, the reduction capability of stoichiometry-based technologies is limited. According to the theory, NOx formation should increase with oxygen concentration or with the amount of excess air. In practice, however, increasing the amount of air lowers NOx formation due to reduction in flame temperature.

Reduction in NOx due to fuel staging or varying the oxygen levels can be as high as 40%. NOx reduction due to dilution with flue gas can be as high as 80%. Newer LNB designs such as ULNBs attempt to capture the concept of dilution by incorporating internal recirculation to obtain lower levels of NOx.

22

PERFORMANCE WITH OIL FIRING Steam generators have been fired with both distillate fuel oils and residual oils. The

design of the boiler does not change much for distillate oil firing compared to gas firing. The fouling factor used is moderately higher, 0.0030.005 ft2 h _F=Btu, compared to 0.001 ft2 h _F=Btu for gas firing; rotary soot blowers located at either end of the convection section are adequate for cleaning the surfaces for distillate oil firing. With heavy fuel oils, retractable soot blowers are required. Economizers also use rotary blowers in oil-fired applications. Solid fin tubes of a fin density of three or four per inch may be used if distillate fuels are used, but if heavy oil is fired it is preferable to use bare tubes or at best 23 fins=in. The emissions of NOx will be higher on the basis of fuel-bound nitrogen, because it can contribute to nearly 50% of the total NOx. Flue gas recirculation has less effect on NOx in oil firing than in gas firing. With residual fuel oil firing, there are several aspects to be considered. 1. High temperature corrosion due to the formation of salts of sodium and vanadium in the ash has been a serious problem in with heavy oil boilers fired. The furnace exit region is a potentially dirty zone prone to deposition of molten ash on heating surfaces. The use of superheaters in such regions presents serious performance concerns. Retractable steam soot blowers are required, with access lanes for cleaning. Tubes should preferentially be widely spaced at the gas inlet region to avoid bridging of tubes by slag. Vanadium content in fuel oil ash should be restricted to about 100 ppm to minimize corrosion potential. 2. Superheater materials used in heavy oil firing applications should consider the high temperature corrosion problems associated with sodium and vanadium salts. The metallurgy of the tubes should be T22 or even higher if the tube wall temperature exceeds 1000_F. A large corrosion allowance on tube thickness is also preferred. This is yet another reason for preferring a convective superheater design to a radiant superheater. 3. Furnace heat flux will be higher in oil firing than in gas firing. Therefore one has to check the circulation and the furnace design. 4. One of the problems with firing a fuel containing sulfur is the formation of sulfur dioxide and its conversion to sulfur trioxide in the presence of catalysts such as vanadium, which is present in fuel oil ash. Sulfur trioxide combines with water vapor to form sulfuric acid vapor, which can condense on surfaces whose temperature falls below the acid dew point. Sulfuric acid dew points can vary from 200 to 270_F depending on the amount of sulfur in the fuel. If the tube wall temperature of the economizer or air heater falls below the acid dew point, condensation and hence corrosion due to the acid vapor are likely. I have seen a few specifications where a parallel flow arrangement was suggested for the economizer to minimize acid dew point corrosion. Because the feed water temperature governs the tube wall temperature and not the flue gas temperature, only maintaining a high water temperature avoids this problem. One could use steam to preheat the feed water or use the water from the exit of the economizer to preheat the incoming water in a heat exchanger. Experience and research show that acid corrosion potential is maximum not at the dew point but at slightly lower values, about 1520_C below the dew point. Hence one may use a feed water temperature even slightly lower than the dew point of the acid vapor in order to recover more energy from the waste gas stream. In waste heat boiler economizers, other acid vapors such as hydrochloric acid or hydrobromic acid may be present.

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The dew points of these are much lower than that of sulfuric acid, so care must be taken in the design of economizers or air heaters in heat recovery applications. SOOT BLOWING

Soot blowing is often resorted to in coal-fired or heavy oilfired boilers. In packaged boilers, both steam and air have been used as the blowing media, and both have been effective with heavy oil firing. Rotary blowers are sometimes used with distillate oil firing. Steam-blowing systems must have a minimum blowing pressure of 170200 psig to be effective. The steam system must be warmed up prior to blowing to minimize condensation. The steam must be dry. Increasing the capacity of a steam system is easier than increasing that of an air system. With an air system, the additional capacity of the compressor must be considered. Also, because steam has a higher heat transfer coefficient than air, more air is required for cooling the lances in high gas temperature regions compared to steam. Moisture droplets in steam can cause erosion of tubes, and often tube shields are required to protect the tubes. The intensity of the retractable blower jet is more than that of the rotary blower jet, and its blowing radius is larger, thus cleaning more surface area. However, one must be concerned about the erosion or wear on the tubes.

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FIRING EQUIPMENTS START UP PROCEDURE

DIESEL OIL IGNITERS

1. Start the Diesel Oil Igniters pump and maintain the Igniter Oil header pressure @ 11.5 Kg/Cm2 through Igniter oil header pressure controller.

2. Ensure that the Igniter oil header pressure is 5.5 Kg/Cm2 at igniters floor. 3. Start the igniter draft fan and to make sure that the igniters combustion air is supplied in

order. 4. Make sure that the igniter oil leak test is completed. 5. Make sure that the differential pressure between the wind box containing the igniters and

the furnace is 75 mmAq. 6. Check the Igniters diesel oil system circuit for leaks using the igniters shut off valve. 7. Ensuring no leak in igniter Diesel oil system, fully open the igniters shut off valve. 8. Increase the Diesel oil temperature by using the igniter warming valve. If the Diesel oil

temperature drops to 15 0C, use the igniter oil heater for increasing the temperature of Diesel oil.

9. Make sure that the air flow rate is excess of 30%. 10. Ensure igniter oil atomizing air is available and moisture is removed. 11. Light up the igniter from CCR. 12. Confirm the ignition flame stability. 13. Adjust the wind box inlet damper if necessary.

DIESEL OIL BURNER

1. Start the diesel oil transfer pump. 2. Keep the diesel oil header pressure12 Kg/Cm2 and keep the diesel oil header pressure 23

Kg/Cm2 for low load operation. 3. Slightly open the diesel oil shut off valve to check the diesel oil lines for leaks. 4. Fully open the diesel oil shut off valve if there is no leak. 5. Diesel oil burners are A1-A4. These burners can be taken for both Diesel Oil firing and

HFO firing. 6. Ensure Diesel Oil leak test is completed. 7. Ensure that igniters are firing. 8. Diesel oil burners are set in place. 9. Wind box inlet dampers are set properly. 10. Air pressure differential between the wind box and the furnace is proper. 11. Select the Diesel oil select valve and atomizing air select valve from control room. In

case of load operation select the atomizing steam select valve from CCR.

HEAVY FUEL OIL BURNERS

1. Start the HFO firing pump. 2. Do the warming of HFO through the HFO warming valve and ensure that the HFO

heaters in service. 3. Slightly open the HFO line shut off valve to check the lines for leaks.

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4. Fully open the HFO shut off valve if there is no leak. 5. Open the fuel oil corner valves for in order to maintain a proper flow through each

corner. 6. In parallel with above warm the burner atomizing steam lines by opening the warming

valves for them. Simultaneously building up the pressure in the lines. 7. Open the atomizing steam root valve and maintain the 2ry Aux steam header temperature

between 150 0C -185 0C. 8. For lighting off the Fuel oil burner make sure that the boiler is in condition ready for

lighting off its fuel oil burners. Open its steam trap bypass valves for getting the atomizing steam temperature.

9. Make sure atomizing steam header pressure is not less then 10.5 Kg/Cm. 10. Make sure fuel oil pump discharge pressure is not less then 33.5 kg/Cm2. 11. Light off the fuel oil Burner from CCR board. 12. The burner are lighted off in the following order

Igniters are lighted off Oil Guns advances Atomizing steam valves open. Fuel Oil inlet valves opens. Flame detector checks the flame of burners.

13. Check the fuel oil burner for proper operation 14. The wind box inlet air dampers are automatically controlled to proper openings

respectively when the fuel oil burners are lighted off. 15. For each burner one Fuel air damper and two aux air dampers are provided. Two

additional over fire air dampers are provided on the top of each elevation of wind box dampers, these are also controlled on auto operation.

16. Once with four or more heavy fuel oil burners in firing operation, the HFO warming valve automatically close.

17. When the Boiler load exceeds 50% add one more HFO transfer pump in operation. 18. Light off the heavy fuel oil burner elevations in the following order.

B1 and B3 B2 and B4 C1 and C3 C2 and C4 A1 and A3 A2 and A4 D1 and D3 D2 and D4

FIRING EQUIPMENTS SHUT DOWN PROCEDURE

HEAVY FUEL OIL BURNERS

1. Put the igniter of the burner which is going to taken out of service. 2. Shut down the fuel oil Burners by switches in CCR. 3. Check that the burners surely shut down by means of the Burner Off indicating lamps. 4. The burners are shut down in the following order.

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Fuel Oil inlet valves closes. Burner gun purge valve opens for 3 minutes. Burner purge valve closes. Atomizing steam valve closes. Burner retracts, air cylinder works to retract the gun.

5. Turn off the igniter after one minute of purging completion. 6. Close the HFO isolating valve of burner. 7. After shut down the HFO burners close the HFO shut off valve. 8. In case of long shut down, remove burner guns from the cylinders and clean the burner

tips, then store them in a proper place.

DIESEL OIL BURNER

1. Light off the igniter and ensure that they are properly working. 2. Shut down the warm up diesel oil burners. 3. Diesel Oil inlet valve closes. 4. Diesel oil purge valve opens for three minutes. 5. Diesel oil purge valve closes and atomizing air valve closes. 6. Then oil gun is retracted. 7. Close the Diesel oil burner fuel isolating valve. 8. Close the diesel oil shut off valve after shutting down the Diesel Oil burners.

DIESEL OIL IGNITERS

1. Off the diesel oil igniter. 2. After shutting down all the igniters close the igniter oil shut off valve. 3. Close the igniter diesel oil isolating valve.

BURNER GUN REPLACEMENT PROCEDURE

1. Take burner gun out of service 2. Put burner gun on sub group from CCR 3. Close burner Gun HFO Isolating valve 4. Close burner Gun HSD Isolating valve 5. Close burner gun atomizing steam isolating valve 6. Close burner gun atomizing air isolating valve 7. Open burner aspirating air isolating valve and open its safety latch as well. 8. Take the tag out of gun cleaning. 9. Replace the gas kits of fuel and atom steam side by after removing the old with new ones

and cleaning the surface. 10. Open gun bolt and take it out from furnace and put the cleaned gun inside. 11. Tight the burner gun bolt and better to test the integrity of gas kits by taking the burner

gun in service.

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HFO FLOW DIAGRAM

HFOTANK

SUCTIONSTRAINER

HFOTRANSFERPUMP

SUCTIONHEATER

STEAM

CONDENSATEDISCHARGESTRAINER

HFOentersintoringheaderanddistributedto

allburners.

DISCHARGEHEATER

SHUTOFFVALVE

FCV

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Specifications

High Speed Diesel

Sr.No Parameter Set point

1 Heating Value 10555 Kcal/Kg

2 Specific Gravity 0.87 max. @ 60/60 Deg. F

3 Flash Point 540C

4 Sulphur 1.0% by Wt max.

5 Ash 0.01% by Wt max.

6 Carbon 0.02% by Wt max.

7 Sediment 0.01% by Wt max.

8 Water 0.05max by Vol %

9 Pour Point 3 0C Max

10 Cloud Point 6 0C Max

1 Fuel medium High Speed Diesel

2 Capacity of igniter 100 L/Hr

3 Oil Pressure 5 Kg/Cm2

4 Igniters wind box differential pressure 75 mmAq.

5 Atomizing air pressure 5.5 Kg/Cm2

Diesel Oil Burner

1 Fuel medium High Speed Diesel

2 Max Capacity per burner 4700 Liters/hr When on Warming

3 Max Capacity per burner 6912 Liters/Hr For Low load operation

4 Oil Pressure 10.5 Kg/Cm2 When on Warming

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5 Oil Pressure 21 Kg/Cm2 For Low load operation

6 Atomizing Air Pressure 5 Kg/Cm2 When on Warming

7 Minimum allowable pressure of

Diesel oil atomizing air 4 Kg/Cm2

8 Atomizing Steam Pressure 10.5 Kg/Cm2 For Low load operation

HFO Burner

1 Metal Temperature of Burner Tip 100-150 0C When Burner is in operation

180-300 0C When Steam Purge is going on

800-1000 0C 2-3 minutes after steam purge is stopped

2 HFO Burner pressure 7 to 21 Kg/Cm2 Depending upon load From Low to High Load

3 Atomizing Steam Pressure 10.5 Kg/Cm2

4 Low burner fuel oil pressure alarm < 7Kg/Cm2

5 Fuel Oil firing system trip 6 Kg/Cm2

6 Minimum allowable pressure of Below this pressure MFT of HFO

Atomizing steam 7Kg/Cm2 burner will operate

7 Furnace purge time 5 minutes

8 Air flow for purging

30 % of total air low at MCR

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AUXILIARY STEAM SUPPLY SYSTEM

SOURCES OF AUXILARY STEAM

There are four sources to charge the auxiliary steam header: -

From auxiliary Boiler From 3ry Super heater inlet header From Cold reheat line From other unit (tie valves)

From Auxiliary Boiler Auxiliary steam header to be charged from auxiliary boiler if both units are in shut

down condition.

From 3ry Super heater inlet header Auxiliary steam header will be charged from 3ry superheater inlet header during unit

start up and remain in service up to generator load 160 MW.

From other unit (tie valves) If any unit is out of service and other unit is in operation then auxiliary steam header

will be fed from running unit through tie valves.

CHARGING AUX. STEAM HEADER FROM AUXILARY BOILER

Auxiliary steam supply header to be charged from auxiliary boiler if the unit is going to shut down and it is not possible to take the auxiliary steam from other unit (tie vales).

Start the auxiliary boiler and increase steam pressure (refer to auxiliary boiler start up procedure).

After breaking of condenser vacuum and closing of turbine gland steam supply, close the auxiliary steam supply MOV from 3ry super heater side.

When auxiliary boiler steam pressure increases up to 10 Kg/cm2, open its steam outlet valve and charge the auxiliary steam header and supply auxiliary steam to steam converter for HFO heating purposes.

After charging the auxiliary steam header Area Engineer should check the system for any abnormality.

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CHARGING AUX. STEAM HEADER FROM TERTIARY SUPERHEATER

During unit startup and steam drum pressure is >20 Kg/cm2, auxiliary steam header can be charged from 3ry super heater side. The procedure is as follows: -

Ensure pre start checks have been completed. Confirm auxiliary steam supply sequence is locked on CRT. Check auxiliary steam MOV from 3ry super heater is kept in manual position. Ensure the presence of Area Engineer at local and watching the system closely. Open slowly auxiliary steam MOV from 3ry super heater side by 10~15% and give

sufficient time for warming up the system. After warming the auxiliary steam system, drain traps put in to service and close their by

pass valves, also close the system drains and vent valves. Make sure auxiliary steam PCV has taken the pressure control. Open more (40~50%) auxiliary steam MOV and watch the auxiliary steam header

pressure. When auxiliary steam header pressure reaches up to 15 Kg/cm2 and becomes stable then

open gradually the MOV up to 100%. Check the system thoroughly for any hammering/leakages.

As per requirement open slowly the auxiliary steam supply header outlets to avoid the fluctuation in header pressure.

CHARGING AUX. STEAM HEADER FROM COLD REHEAT LINE

If unit load is > 160 MW auxiliary steam header can be supplied from cold reheat line. Usually this change over is carried out automatically but also can be done manually.

AUTO CHANGE OVER FROM 3RY SUPER HEATER TO COLD REHEAT LINE.

Confirm auxiliary steam supply MOV from 3ry super heater side is on auto. Check auxiliary steam supply MOV from cold reheat side is kept on auto. Check auxiliary steam supply PCV set point adjusted at 16 Kg/cm2. Check unit load is 160 MW load, auxiliary steam from cold reheat side

MOV will open automatically and respective PCVs take steam pressure control. During this change over, watch the auxiliary steam header pressure closely. In case of

PCVs malfunction, auxiliary header pressure will be unstable which is undesirable for unit operation.

AUTO CHANGEOVER FROM COLD REHEAT LINE TO 3RY SUPERHEATER

Confirm auxiliary steam supply MOV from 3ry super heater side is on auto.

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Check auxiliary steam supply MOV from cold reheat side is kept on auto. Check auxiliary steam supply PCV set point adjusted at 15 Kg/cm2. Check unit load is >160 MW and auxiliary steam header is fed from 3ry super heater

side. While decreasing the unit load, at

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Ensure that unit is out of service and there is no need of Aux steam. Close slowly the Aux steam header charging source ( Aux steam tie valve or Aux steam boiler ). Open the Aux steam header drains and vents to depressurize the header.

AUXILIARY BOILER

PRE START UP CHECK LIST

1. Demin water line should be normal. 2. Make sure auxiliary boiler power supply is available. 3. Instrument air supply should be normal. 4. Make sure no any maintenance job is remaining related to auxiliary boiler. 5. Level gauge glass for steam drum should be line up. 6. Level gauge glass for deaerator should be line up. 7. Open auxiliary boiler vent valve. 8. Check deaerator is normal. 9. Make Auxiliary boiler Drum level up to 60% by starting feed pump and second pump on

standby. The level should be confirmed by Local gauge glass. 10. Make sure auxiliary boiler main steam root valve are closed. 11. Make sure auxiliary boiler drain valves are closed. 12. Make sure deaerator drain valve and root are closed. 13. If steam converter condensate is going to LP 2 heater it may be diverted to auxiliary

boiler. 14. Check the level of pilot diesel oil tank. Tank level should be sufficient and Its valve

should be open. 15. Auxiliary boiler diesel oil pump should be available. 16. Release emergency push button. 17. Main control switch should be on off mode. 18. Make sure that steam converter is ready to be taken in service i.e. the level of condensate

receiving tank and steam converter are normal. 19. Make sure steam converter feed pump are available for service. 20. Make sure steam converter chemical dosing system is available for service. 21. Make sure auxiliary boiler chemical dosing system is available for service.

AUXILIARY BOILER START UP PROCEDURE.

1. Make sure again auxiliary boiler drum vent valve are open. 2. Make sure deaerator level is normal and filling lineup is OK. 3. Deaerator filling can be done in two ways. 4. Through demin water control valve. Check inlet and outlet of the control valves are open.

Also please check it root valve. 5. Through steam converter condensate return line LCV. Check inlet and outlet of the

control valves are open. 6. Check pilot tank outlet valve is open. Also check its level. 7. Put the auxiliary boiler feed pump at auto mode, and one pump will be at standby.

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8. Make sure auxiliary boiler drum level is approximately 60%. It can be checked by opening the drain valve of the gauge glass of the boiler drum.

9. Start the auxiliary boiler diesel oil pump. One pump should be stand by. 10. Make sure emergency push button has been released. 11. Adjust the firing rate approximately 40%. 12. Switch ON the control switch. 13. First reset the burner control cabinet inside the control panel and then reset on the control

panel. 14. Switch on the burner switch. The air and gas system will start automatically. Initially

furnace purge will occur for two minute and then igniter will ignite. 15. After 10 Sec main burner will be fired. 16. Close the drum vent valve at 2 bars. 17. Burner will cut in and cut out at 16.5 bar and 17.5 bar respectively. 18. Start chemical dosing system. 19. Open the steam root valve slowly.

AUXILIARY BOILER SHUT DOWN SEQUENCE

1) Switch off the burner switch. Burner will be cut out and furnace purge will occur automatically for five second.

2) Switch off the control switch. 3) Close the steam root valve. 4) Switch off the both feed pumps. 5) Close the inlet isolating valve of makeup water control valve. 6) Stop the diesel oil pump.

STEAM CONVERTER

PRE START CHECKS

o Demin water LCV inlet iso. valve is open o Demineralized water LCV out let iso. valve is open o Demineralized water LCV bypass valve is closed. o Condensate receiver LCV Close/Manual o Feed pump A inlet iso. valve is closed. o Feed pump B inlet iso. valve is closed. o Drain valve on the Feed Pump A inlet line is open. o Drain valve on the Feed Pump B inlet line is open. o Condensate receiver tank drain valve is open. o Drain valve at the pump outlet is open. o Inlet valve the reboiler LCV is open. o Out let valve of the reboiler LCV is open. o Bypass valve of the reboiler LCV is closed. o Reboiler LCV Close/Manual o Cooler inlet valve is open.

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o Cooler outlet valve is open. o Cooler bypass valve is closed. o Cooler inlet line drain valve is open. o Reboiler condensate gauge glass upper iso. valve is open. o Reboiler condensate gauge glass lower isol. Valve is open. o Reboiler vent valve is open. o Primary steam PCV inlet iso. valve is closed. o Bypass valve of the primary steam PCV is closed. o Outlet valve of the primary steam PCV is closed. o Primary steam condensate out let valve is closed. o The manual valve in the secondary steam main leaving the Reboiler (Until system-operating

pressure is approached) is closed. o Cooler gauge glass upper iso. valve is open. o Cooler gauge glass lower isol. valve is open. o Cooler gauge glass drain valve is closed. o Check cooler drain valve is closed. o Primary Condensate to LP-2 heater control v/v inlet isol. valve is open. o Primary Condensate to LP-2 heater control v/v outlet isol. valve is open. o Primary Condensate to Aux. Boiler control v/v inlet isol. valve is open. o Primary Condensate to Aux. Boiler control v/v outlet isol. valve is open. o Primary Condensate to Aux. Boiler control v/v bypass valve is closed. o Primary Condensate to LP-2 heater control v/v bypass valve is closed. o Primary Condensate to Aux. Boiler control v/v is closed. o Primary Condensate to LP-2 heater control v/v is closed. o Primary steam bypass PCV should be on Auto mode with set point at 0 and PCV will be in

closed condition. o Inlet isolation valve of the primary steam bypass PCV is open.

START UP PROCEDURE:

o Start filling of the condensate receiver with the demineralized water through the manual bypass of LCV opened 50 to 60 %

o Condensate receiver tank drain valve (After sufficient flushing) is closed. o Fill the condensate receiver up to 75 % o Place condensate receiver level controller in automatic with the set point at 75 % o Feed pump A inlet valve is open. o Feed pump B inlet valve is open. o Feed pump A outlet valve is open. o Feed pump B outlet valve is open. o Feed pumps line drain valve (After sufficient flushing) is closed. o Open the bypass around the Reboiler LCV is open. o Start Primary feed pump o Cooler inlet line drain valve (After sufficient flushing) is closed.

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o When the level in the Reboiler reaches 60 %, put the LCV on Auto mode with the set point at 70 %

o Close the reboiler vent valves o Open the inlet valve of the primary steam control valve o Move the pressure set point on primary steam supply controller DP01 up in 0.5 ata

increments. o Monitor the primary steam condensate level in the cooler level gauge. When the level

reaches the mid point in the gauge, open the discharge manual valve towards LP heater 2 or Auxiliary boiler and related controller should be put on Auto with the set point at 60 %.

o When the system pressure control loop DP001 has its set point gradually moved up to 10.5 ata the manual isolating valve of the secondary steam can be opened for automatic generation of steam.

o The final set point of the system pressure controller DP001 should be moved to 11.2 ata. o Move the primary steam bypass PCV controller set point to less than 1.0 ata from the

supply steam set point. o After four hours of operation at the final set point, open the manual blow down valve

from the Reboiler to discharge blow down at a rate that will prevent build up of dissolved solids.

SHUT DOWN PROCEDURE:

o Confirm there is no need for heating and tracing steam o Convert the primary steam condensate to atmosphere or blow down o Ask CRE to close the shutoff valve towards LP 2 heater side o Adjust the primary steam bypass controller set point to zero o Put the primary steam supply controller on manual mode and reduce the pressure set

point to 0 with 0.5 ata decreasing trend. o Check primary steam inlet PCV is closed. o Primary steam inlet-isolating valve is closed. o Demineralized water LCV inlet supply isolation valve is closed. o Switch off the feed water pump which ever is running o Put the both feed pumps control switches on off mode o Condensate receiver drain valve is open. o Open Reboiler drain valve o Open Cooler drain valves o Open Reboiler vent valve

MFT can be due to

Both FD Fans trip. Both A.Hs trip.

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Both BCP differential pressure low low for > 3 seconds. HFO burner pressure v. low. (If only HFO burner in service ). D.O burner pressure v. low. (If only D.O burner in service) Atomizing air pressure v. low if D.O burners in service. Atomizing steam pressure v. low if HFO burners are in service. Air flow < 30% for > 3 seconds. Furnace pressure high for >3 seconds. All flame loss. (No flame detected). Both A / C and D / C cooling air fans trip. BMS power loss. APC failure. Turbine trips. R.H protection operates. Generator trip. Boiler manual trips.

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APPENDIX

39

BOILER SPECIFICATIONS

Make Mitsubishi Japan, Model type: A701 MB-FRR (P) Forced circulation

Radiant heat boiler Steam drum pressure design 199 Kg/cm2 Heat surface of each boiler 24,860 m2 Capacity 1200 Ton/hr Main steam working Pressure 176 Kg/cm2 SH outlet temperature 541 oC Feed water inlet Temp 279 oC Economizer outlet Temp 311 oC Economizer inlet Pressure 191.4 Kg/cm2 Sat. Steam Temp 357 oC Reheat outlet Pressure 38.3 Kg/cm2 Boiler Draft system Forced draft Air required for combustion BCMR 12,167 m3 /hr Air Temp at air pre heater inlet 61 oC Air Temp at air pre heater outlet 289 oC Gas Temp entering air pre heater 360 oC Gas Temp leaving air pre heater 165 oC Furnace height 23,630 mm Furnace width front to rear 11,220 mm Furnace volume 2,590 m3 Furnace pressure 450 mmH2O BCP Capacity 2330 m3 /hr Design Pressure 201 Atm Air preheat 2 set per boiler Heat surface 12,470 m2 Hot end baskets material MS (84 baskets /AH) Cold end baskets material CRLS corrosion resistant low alloy steel

(96 baskets /AH) Revolution 1.424 r.p.m Specification of fuel Oil Heavy fuel oil. Type of firing Circular corner firing with tiltable burner

(M-Jet steam atomizing type) No. of burner 4 corner x 4 elevations = 16 burners Fuel consumption at full load 82 Ton /hr Oil pressure 21 Kg max. Atomizing steam pressure 10.5 Kg/cm2 Oil temp and viscosity 110 oC. and cSt 24 and less Heavy fuel oil transfer P/P type and capacity

3 screw horizontal type . 54.7 t/hr (60 oC)

P/P discharge pressure 33.5 Kg/cm2 HFO LHV 18,200 Btu/Lb minimum.

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Viscosity max. 25 cSt. Sp. Gravity 0.98 kg/l Flash point 66 oC Sulfur 3.5 % W Carbon residue 12.5 % W Vanadium max. 60~150 ppm Max. capacity of burner 6.4 t/hr

SET POINTS

Sr. No Description Set Point 1 Furnace Purge Time 5-Minutes Leak Test Time 3-Minutes

2 Leak Test fail

If pressure drop rate is 1 bar in 3 minutes then leak test fail indication come on CRT

3 Gas AH Lube oil Temp Limit Less than 55oc 4 Cooling Air Fan Stop, Drum metal Temp Limit Less than 100oc 5 BCP Motor side cavity Temp Limit Less than 57oc 6 Boiler MFT at Air Flow Less than 30% 7 AOP will start at 2950 RPM 8 JOP Will start at 800 RPM

9 TOP will start at 100 RPM and AOP will stop 10 Turning Gear motor will start at 0-RPM 11 O2 limit at max load 1.0% -2.0% 12 O2 limit at min load 6.0%-6.5% 13 Corrected Nox Limit 130g/GJ (Giga joules) 14 Opacity 10% - 15% 15 Eco Recirc valve opening and closing load 20% load 16 Cold RH drain valve opening and closing load 20% load 17 Super heater electromatic safety valve set point 178.2 Kg/cm2 18 Drum pressure for 2nd BCP start up 30 Kg/cm2 19 BCP cooling water flow More than15 m3 20 Aux steam header normal pressure limit 13- 15.5 Kg/cm2 21 Burner Stabilizing time to keep igniter on 30 sec

22 RH Protection

When total fuel flow less than 30% of MCR, HP or LP steam flow Low Low, than RH protection will operate in 10 sec

23 RH Protection When total fuel flow less than 17% of MCR, HP or LP steam flow Low Low,

41

than RH protection will operate in 20 sec

24 Atomizing steam pressure 12 Kg/cm2 25 Atomizing steam Temp 190oc 26 Atomizing steam tripping pressure Less than 5.0 Kg/cm2 27 HFO tank Temp set point 35oc - 45oc 28 HFO suction heater Temp 60oc 29 HFO discharge heater Temp 100oc 120oc 30 DO Burner Pressure V-Low 3.5 Kg/cm2 31 DA Pressure High 9.5 Kg/cm2 32 DA Pressure Low 0.5 Kg/cm2 33 3-Element Drum level selection drum pressure 130 Kg/cm2 34 LP heater cut in load 50-60MW 35 HP Heater cut in load 70-80MW

Sr. No Description Set Point 36 Heaters Cut in Sequence 3,4,5,6,7,8 37 Load reduction if one HP heaters out at MCR 10% 38 Load reduction if all HP heaters out at MCR 20% 39 Maximum burner Tilt degree +/-30o 40 Allowable drum metal temp for boiler draining 75oc 41 Sh Metal Temp Normal/Alarm 550/600 42 RH Metal Temp Normal/Alarm 550/580 43 HP Oil Pressure 22 Kg/cm2 44 Auto Stop Oil Pressure 9.0 Kg/cm2 45 Control Oil Pressure 3.0 Kg/cm2 46 Main Oil Pump suction Pressure 1.5 Kg/cm2 47 Main Oil Pump discharge Pressure 22 Kg/cm2 48 AOP starting on vacuum pulling 550 mmHg 49 AOP starts when lube Oil Pressure drops to 0.85 Kg/cm2 50 AOP starts when main oil pressure drops to 17.0 Kg/cm2 51 TOP stops at condenser vacuum 550 mmHg 52 TOP starts when lube Oil Pressure drops to 0.75 Kg/cm2 53 Turning Gear Speed 2-3 RPM 54 Turning Gear Engage speed 0 RPM 55 Turning Gear Disengage speed 3 RPM 56 Rotor Eccentricity 0.075 mm 57 Bearing Metal Temp Alarm 107oc 58 Bearing Metal Temp trip 113oc 59 Bearing Oil Temp Alarm 85oc 60 Thrust Bearing Wear +/- 1mm 61 Bearing Vibration Alarm 125 mills 62 Bearing Vibration Trip 250 mills 63 Start Up Ejector cut off on auto at 550mmHg 64 Condenser normal Vacuum 710 mmHg 65 Condenser high Vacuum alarm 715 mmHg 66 Vacuum Breaker will open at 400 RPM

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67 Vacuum Breaker will close at , DC power is supplied to Vacuum breaker 100 mmHg

68 Gland steam normal Header pressure 0.35 to 0.45 Kg/cm2 69 Gland Exhauster Vacuum More than 500 mmAq

70 Exhaust Hood spray water Spray will open at 80oc

exhaust hood temp 71 LP Gland steam Temp 150oc to 180oc 72 HP Gland steam Temp 230oc to 290oc

73 Turbine bypass permissive will come at 650 mmHg condenser vacuum 74 Condensate pumps recirc valve opens at 20% opening of DA LCv 75 Condensate Pumps trip at Hot well level -200 mm 76 Condenser spill over open/close level 250mm/100mm

Sr. No Description Set Point 77 2nd condensate pump start load 40%

78 Holding time for CWP discharge valve opening at 40% 1 minute

79 Differential Temp limit across condenser 10-15oc 80 Turbine Trip- Bearing vibration very high 250mm 81 Turbine Trip- Rotor position abnormal +/- 1mm 82 Turbine Trip-Lube Oil press very low 0.5 kg 83 Turbine Trip-Condenser vacuum very low 535 mmHg 84 Turbine Trip-Bearing Temp very high 113oc 85 Over speed 110% & 111% 86 OPC operate set point 107% which is 3210 RPM 87 MOST 111% 88 EOST 112% 89 Stem Free test load 75%

90 IPR set point 10% reduction in main steam flow at rated load 91 Vacuum un loader set point 615mmHg 92 Run Back at upper load limit 10% or up to 320MW

93 No load and speed change will be if actual stress increases to 90oC

94 Drop set 4%

95 Hot Start HP casing regulating zone temp 400oc and 100Kg/cm2 drum pressure.

96 Hot Start If first stage metal Temp more than 350oc

97 Warm start HP casing regulating zone temp 360oc and 80Kg/cm2 drum pressure.

98 Warm start If first stage metal Temp more than 120oc and less than 350oc

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99 SP-1 lube oil temp set 35oc 100 SP-2 lube oil temp set 45oc 101 Turbine Run down time 1 hour and 20 minutes 102 CT basin Normal Level 1900 mm 103 CT basin High Level 1980 mm 104 CT Basin HH Level 2000 mm 105 CT Basin Low Level 1700 mm

106 CT basin Trip level both level transmitter A and B 1250 mm

107 Condensate Pumps discharge pressure 22.5 Kg/cm2 108 Condensate Pumps sealing water pressure 2-3 Kg/cm2 109 AOP oil pressure 2.6Kg/cm2

Sr. No Description Set Point 110 BFP AOP stop time 30 sec after main pump start111 Bearing Oil Pressure at Local 1.2 kg/cm2g- 2.0 Kg/cm2g. 112 Jacking Oil Pump suction Press higher than1.2 kg/cm2g. 113 Jacking Oil Pump discharge Press 140 kg/cm2g 114 BCP Differential Pressure Low 1.8 Kg/cm2 115 BCP Differential Pressure Low Low 0.75 Kg/cm2 116 Start permissive at motor cavity temp 60oc

118 MFT can be due to

Both FD Fans trip. Both A.Hs trip. Both BCP differential

pressure low low for > 3 seconds.

HFO burner pressure v. low. (If only HFO burner in service ).

D.O burner pressure v. low. (If only D.O burner in service)

Atomizing air pressure v. low if D.O burners in service.

Atomizing steam pressure v. low if HFO burners are in service.

Air flow < 30% for > 3 seconds.

Furnace pressure high for >3 seconds.

All flame loss. (No flame detected).

Both A / C and D / C cooling air fans trip.

44

BMS power loss. APC failure. Turbine trips. R.H protection operates. Generator trip. Boiler manual trips.

119 BCP cavity temp limits

BCP cavity temperature limit is 57C.

Normal = 40C High temp. alarm = 57C High high trip = 60C

120 HFO burner header pressure low.