1. INTRODUCTION TO THERMAL POWER PLANT

The captive Thermal Power Plant (TPP) of Visakhapatnam Steel Plant has got an in

plant capacity to generate 247.5 MW of power at its main TPP and about 39 MW of power

from its auxiliary power generation situated at Back Pressure Turbine Station and Gas

expansion Turbine station. Main TPP has got 3 generators of 60 MW each and one

generator of 67.5 MW. The power produced is used for the steel plant loads (about 215

MW) and the excess power around 30 to 40 MW is sold to the APTRANSCO. The plant

has 5 Boilers of 330 T/Hr (at 101 KSCA and 540O C) steam capacity out of 5 boilers, four

boilers are operated normally and one as standby/capital repair. The boilers are having very

good tube failure record with less than 2 failures per year. The boilers are operated within

the norms and water chemistry is maintained well.

Thermal power plant always get synchronised with AP Transco grid. Power

generation is maintained always at optimum level and whatever excess generation is there

that will be export to AP Transco grid. In case of any problem in our plant we import the

power from AP Transco grid. And there is a provision to de-synchronise automatically

from grid whenever frequency fluctuations are high in AP Transco grid which will save our

plant from total power failure. During that period our plant will run on isolation mode.

After frequency getting stabilised, once again we have to synchronise our plant with AP

Transco grid.

Thermal Power Plant has 5 Boilers each generating of 330 T/hr. steam at 101 KSCA

and 540o C. The boilers are of BHEL make, capable of firing combination of fuels namely

Coal, Coke Oven Gas, Blast Furnace Gas and Oil. Crushed coal is conveyed from Raw

Material Handling Plant to TPP through conveyors. The coal is pulverized in Bowl Mills

and fired in the furnace. Normally, 4 Boilers are kept in full load operation to produce 247.5

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MW of power, supply steam to 2 Turbo Blowers and process needs boilers outlet flue gas it

passes through Electro Static Precipitators to control air pollution. The Fly ash and bottom

ash generated are pumped in slurry form to ash pond through on ground pipelines. The

clarified water is re-circulated back to ash system.

(i) TURBO GENERATORS

Thermal Power Plant has 4 Turbo Generators, three of 60 MW capacities each and the

fourth 67.5 MW. Special features of the turbo sets are:-

i. Electro Hydraulic Turbine Governing System.

ii. Central admission of steam to reduce axial thrust.

iii. Forced air cooled generators

Power is generated and distributed at 11 kV for essential category loads. Excess

power from TG-1, 2 and 3 is transferred to 220 kV Plant Grid through step up/down

transformers. All the Power Generated from TG-4 at 11 kV is stepped up through a 220 kV

transformer and transferred to plant grid. Impulse reaction turbine is used. Impulse has 1st

stage, input steam at 540O C. Steam passes through this stage pressure changes from 101

ata to 20-30 ata. Reaction has 40 stages. After coming from the impulse stage, steam

passes through all these stages pressure decreases to 0.1 Kg/cm2. So velocity changes

kinetic energy is converted into mechanical energy. The generators are of salient pole type.

(ii) TURBO BLOWERS

VSP has two Blast Furnaces. To meet the blast air requirement 3 Turbo Blowers

each of 6067 NM3/ Min @ 6.5 Kg/cm2 capacity, are installed at TPP. These Blowers are of

axial type and are the largest blowers installed in India. To meet the varying needs of Blast

Furnace, the blowers are provided with adjustable stator guide blades in the low pressure

compression stages. The Blowers are provided with suction filters, pre-coolers and

intercoolers.

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(iii) CHEMICAL WATER TREATMENT PLANT (CWTP)

Chemical Water Treatment Plant located in TPP Zone produces high purity

Demineralised Water and Soft Water. There are six streams of Demineralising units each

capable of producing 125 cubic meters per hour and two softening units of 125 M 3/hr

each. DM water is supplied to Chilled Water Plant-I, II and SMS mould cooling. The return

condensate from Thermal Power Plant, chilled water Plant No. I and Chilled Water Plant

No. II is polished at CWTP in 2 streams, each of 100 M3/hr. capacities. All the

demineralised water produced/polished at CWTP is deaerated and dosed with Ammonia

before pumping to consumers. 6 Deaerators are installed at CWTP for this purpose.

(iv) CHILLED WATER PLANT NO.2 (CWP-2)

Chilled Water Plant No. 2 in TPP zone is having nine chillers, each having a chilling

capacity of 337 M3 of water per hour. The chillers operate on liquid absorption technique

having Lithium Bromide cycle. The chilled water is supplied to TPP, Blast Furnace and

Sinter Plant for air conditioning purpose at 7O C. The return water temperature is 16O C.

Steam and cooling water requirements are met by TPP and Pump House No. 4 respectively.

(v) COKE DRY COOLING PLANT (CDCP) BOILERS

In VSP, hot coke produced in the Coke Oven Batteries is cooled b y circulating

Nitrogen in Coke Dry Cooling Plant. The hot circulating gas is passed through Waste Heat

Boilers in which steam is produced at 40 KSCA pressure and 440O C temperature. There are

four Waste Heat Recovery Boilers each of 25 T/hr. capacities in each Coke Dry Cooling

Plant. There are three CDCP for 3 Coke Oven Batteries these Boilers are once through

forced circulation Boilers deaerators and Boiler feed pumps, serving all the three plants, are

located at CDCP-I.

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(vi) BPTS & CWP-1

The 40 KSCA steam generated in CDCP Boilers is utilized for driving 2 nos. of 7.5

MW Back Pressure Turbines for generation of power. The 2.5 ata exhaust steam is utilized

for production of Chilled Water in CWP-1. The 7 ata extraction steam is used for process

requirements of CO & Coal Chemical Plant zone. The CWP-1 has 5 chillers installed, each

capable of cooling 337 M3 of water per hour from 18 to 10O C. The Chilled water is

supplied to Gas Coolers and for air conditioning needs of CO & Coal Chemical Plant zone.

BPTS and CWP-1 are housed in a single building located near Battery No. 3 of CO& Coal

Chemical Plant zone.

(vii) GAS EXPANSION TURBINE STATION (GETS)

Both the Blast Furnace of VSP are designed to operate at a high top pressure of 2.5

kg/cm2. The high pressure BF Gas is cleaned in Gas Cleaning Plant and expanded in Gas

Expansion Turbine driving electric generators. The BF Gas after passing through the

Turbine is fed to gas distribution network and is used as heating fuel in TPP and other units

of VSP. Each Blast Furnace is connected to a Gas Expansion Turbine of 12 MW of power is

expected to be generated by each of the turbine at full production level. GETS is located in

BF zone, between the two furnaces.

(viii) STEAM TURBINES

Steam Turbine in Thermal Power Plant converts heat energy of steam to useful work

and then the steam is condensed in a condenser which is carried by condensate extraction

pump and Boiler Feed Pump back to the Boiler. Thermal Power Plant uses a dual phase

cycle to enable the working fluid to be used again and again. The cycle used is ‘Rankine

Cycle’ modified to include superheating of steam, regenerative feed water heating.

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2. BOILER & ITS THEORY

A boiler is defined as a pressure vessel, which transfers heat from a heat source to a fluid.

The heat source is typically combustion; however electric resistance boilers can be included

into the boiler definition. The fluid in a boiler is typically water (liquid or steam) A furnace

is also an appliance, which transfers heat from a heat source to a fluid, with the primary

differences being that it is not a pressure vessel and that the fluid is air. Boilers are

typically classified by: working temperature and pressure, fuel type, fluid type (state), and

material of construction. Commercial boilers, the type of boiler which people are the most

familiar with, provide hot water for space heating and/or domestic hot water heating. These

boilers are typically low pressure, natural gas fired, hot water boilers.

The water tube boiler is composed of drums and tubes. The tubes always being

external to the drums serve to interconnect them. The drums store water and steam. In

contrast with the fire tube boilers, the drums in the water tube boilers do not contain any

tubular heating surface. Therefore, they can be built in smaller diameters and consequently

they will with stand higher pressures. The tubes inter-connecting the water and steam drums

constitute the entire heating surface. Normally these boilers have natural water circulation

due to convection current set up on application of heat. The initial cost of water tube boiler

is higher compared to the fire tube boiler for the same capacity. More common today are

water-tube boilers, in which water runs through a rack of tubes that are positioned in the hot

gases from the fire.

In a real boiler, things would be much more complicated because the goal of the

boiler is to extract every possible bit of heat from the burning fuel to improve efficiency.

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(i) LOCATION OF HEATING SURFACE IN WATER TUBE BOILERS

A high-pressure boiler is not a simple assembly of certain components like: burners,

superheaters, air heaters and others. The functions of these components are inter-related.

The quality of coal used and the operating conditions has great influence on the selection of

these components and more than that they influence the philosophy of the general design.

The location of the heat transfer surface (evaporator, super-heater and re-heater) in a

boiler is very important and it depends upon the required duty from the boiler. The most

commonly used furnace layout for pulverized fuel boilers is shown in figure. In the zone-I,

heater transfer is predominantly by radiation as the flame in this zone is diffused yellow-

flame which radiates much more than the premixed blue flame. As the burned gases move

upward and secondary air is added, the effect of radiation is reduced and convection

becomes predominant as the flame (hot gases) changes from diffused to premixed. The

space marked by (R+C) receives heat by convection as well as radiation provided suitable

heat transfer surface is introduced into the path. The heat transfer in the zone-II and zone-III

takes place mainly by convection. Zone-II is identified as high temperature and zone III as

low temperature zone.

Fig.1 Heat Transfer zones

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It is essential to provide an opportunity to fuel and air to come in intimate contact for a

longer time to achieve the complete combustion. This opportunity decrease as the reaction

proceeds towards the completion. Therefore, it is always essential to supply excess air to

ensure complete combustion. The boiler efficiency decreases with an increase in excess air.

The demand for excess air is considerably reduced in pulverized fuel firing system by

creating turbulence to air, which increases the surface contact between fuel and air.

Hot turbulent air coupled with low excess air produces a very high flame temperature. At

this temperature, ash always remains in molten condition. Metal surface temperatures of all

heat transfer surfaces (as they carry water or steam) are less than the ash fusion temperature

(AFT). In order to avoid the solidification of molten ash on the metal surfaces, the use of

convection heat transfer should be avoided as long as the gas temperature are higher than

AFT. Till then the heat transfer must be by radiation only as in zone-I. The exit gas

temperature should be as high as possible to provide a high temperature potential for the

heat transfer surfaces located in these zones (zone-II and Ill), but at the same time, it should

be lower than AFT to avoid slag deposition. About 50% of the total heat generated is

absorbed in the radiation zone. This value increases with fall in AFT or fall in excess air

supply. Therefore, the maintenance problem becomes more severe if lowest possible tube

metal surface temperature relative to superheats and, therefore, the evaporator is most

suitable component to be located in zone-I (radiant zone).

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Fig.2 GENERAL ARRANGEMENT OF BOILER

The gas temperature is fairly high in zone II and main mode of heat transfer is

convection. Therefore, the slagging problem in this zone should not be neglected.

Sometimes locating panels and platens before zone II, bring down the gas temperature to

safer level. These panels and platens can be evaporator or super heater. Panels are the heat

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transfer surfaces at a considerably greater distance from each other. Therefore, they permit

large radiant heat absorption. Platens are heat transfer surface which are closer to each other

and heat absorption in platens take place by convection and radiation simultaneously.

Superheater elements are more expensive than evaporator because of their high metal

surface temperature. It is desirable to locate the superheater surfaces in this region to reduce

its total surface area requirement. Therefore, zone-II (high temperature convection zone) is

highly preferable to locate the superheater.

The gas temperature in zone II is relatively low so the cost of the superheater increases if

located in this zone. Even though, some part of the superheater can be located at the

beginning of this zone if the sufficient space is not available in zone II. The zone III is a

more appropriate and economical for locating the heat recovery unit like economizer and

preheater. The required superheat temperature in a power plant increases with an increase in

operating pressure. Usually beyond 100 atm, reheat becomes essential. The total amount of

heat generated in the furnace is distributed among evaporator, superheater, re-heater,

economizer and preheater and their percentages depend upon the working condition (part or

full load) of the plant and highest operating pressure used.

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3. BOILER ACCESSORIES

The common equipment's used in thermal power plants to increase the thermal efficiency

are economizers, superheaters and air pre-heaters. The heat carried with the flue gases is

partly recovered in air pre-heaters and economizers and reduces the fuel supplied to the

boiler. The preheating of air with the gases increases the combustion efficiency and reduces

the fuel consumption. The erosion loss due to condensation in the later stage of turbine

(efficiency loss also) is also partly reduced by increasing the temperature of steam above

saturation. The adoption of these devices as far as economical justification is concerned

depends upon the capacity of the plant. Practically all-large capacity power plants can

justify the installation of heat reclaiming device from flue gases.

The adoption of one or both equipment's (economizer and air preheater) depends upon the

economical justification. It is also equally essential to maintain the performance of these

equipments by preventing corrosion and fouling from inside and outside; otherwise the gain

from these equipments reduces rapidly with respect to time. Using proper materials for the

equipments and controlling the flue gas temperature to avoid the condensation of corrosive

gases carried by the exhaust gases generally prevents the corrosion.

(i) ECONOMIZER

The purpose of the economizer is to preheat the boiler feedwater before it is

introduced into the steam drum and to recover some of the heat from the flue gases leaving

the boiler. The economizer is located in the boiler rear gas pass below the rear horizontal

superheater. Each section is composed of a number of parallel tube circuits. All tube circuits

originate from the inlet header and discharge into the outlet header through economizer

intermediate headers and economizer hanger tubes (in the case of top supported

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economizer with hanger tubes).

Feed water is supplied to the economizer inlet header via the feed stop and check valves.

The feedwater flow is upward through the economizer, that is, in counter flow to the hot

flue gases. Most efficient heat transfer is hereby accomplished. Any difficulty with steam

generation within the economizer is eliminated by the upward water flow. From the outlet

header the feedwater is let to the drum via the economizer outlet links.

The economizer is a feed water heater deriving heat from the flue gases discharged from the

boiler. The justifiable cost for economizer depends on the total gain in efficiency. In turn,

this depends on the gas temperature going out of the boiler and feed water temperature to

the boiler. Regenerative cycle inherently gives high feed water temperature; therefore the

adoption of economizer must be studied very carefully.

Fig.2 ECONOMISER

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(ii) OPERATION

Before starting up the boiler economizer should be inspected and cleared of foreign

materials, if any. All access doors should be bolted tight. Check the door occasionally for

tightness.

Always use only deaerated water of boiler feeding. This is essential to keep down the inside

corrosion of pressure parts including economizer. If external steam is available deaerating

steam must be admitted before start up of the boiler, otherwise at the earliest opportunity

when own steam is available. Feedwater temperature must also be maintained at the

specified level either with the help of feed water heaters or heating the water in feed tank.

Low feedwater temperature may result in external corrosion of economizer and also higher

heat absorption than normal in convection super heaters.

The economizer circulation system if provided should be kept in service when there is fire

in the boiler with no feed flow. The unbalance is gas flow between different paths will

result in different water outlet temperature from economizer and hence gas flow has to be

equalized. Steaming in economizer is harmful to economizer unless otherwise it is designed

as steaming type and keeping water on economizer outlet feedwater temperature should

prevent hence steaming. To prevent steaming, during design stage, sufficient margin is kept

between the predicted economizer outlet water temperature and saturation temperature for

the corresponding pressure.

Frequency with which soot blowers are used (if provided) depends entirely on local

conditions. Observation of the increase in draft loss blowing will determine the frequency.

In many cases it has been found that blowing the economizer soot blower is not necessary

for Indian coals.

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(iii) DESIGN REQUIREMENTS FOR AN ECONOMIZER

The design requirements must satisfy the following conditions: The heat transfer

surface should be minimum.

• It must be able to extract maximum possible heat from exhaust gases.

• The height of the tube banks should be minimum so the cleaning on load can be done

efficiently.

• The gas side pressure loss should be minimum to reduce the running expenses of Induced

Draft fans.

• There must be uniform water flow to avoid the steam formation in the economizer. The

pressure loss of waterside must be also minimum to reduce the running expenses of the

pump.

• It must in dimensionally with the preceding unit, usually the primary super heater.

• There must be connection from steam and water drum to the economizer inlet header, to

permit the free circulation of water around the economizer to prevent the overheating and

boiling during the period when there is no feed-flow during early pressure rising stages.

(iv) TYPES OF ECONOMIZERS

Basically there are two types of economizers as discussed below:

(1) Plain Tube Type Economizer. Plain tube types are generally used in boiler, which

is working under natural draught. The tubes are made of cast iron to resist corrosive action

of the flue gases and their ends are pressed into top and bottom headers.

An economizer consists of a group of these cast iron tubes located in the main flue between

the boiler and the chimney. The waste flue gases flow outside the economizer tubes and

heat is transferred to the feed water flowing inside the tubes. The external surfaces or the

tubes are continuously cleaned by soot deposition, which is a bad conductor of heat.

(2) Gilled Tube Type Economizer. A reduction in economizer size together with

increase in heat transmission can be obtained by casting rectangular gills, the bare

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tube walls. Cast-iron gilled tube economizers can be used upto 50 bar working pressure and

such economizers are indigenously available. At higher pressure steel tubes are used instead

of cast-iron but cast iron gilled sleeves are shrunk to them.

Economizers also may have bare or finned tubes. Bare tubes are specified for dirty

fuels but the use of finned tubes in high fouling fuel applications has increased significantly

over the past few years. The choice of finned tubes for an application depends on cost,

reliability of the bond between fin and tube, temperature and material limitations and extent

of corrosion and fouling as well as on heat transfer and pressure drop requirements.

A wide variety of materials are available for finned tube construction. The choice for

each depends on corrosion problems. Finned tubes are constructed from carbon steels,

stainless steels and high-grade corrosion resistant alloys. 150 to 200 fins per meter are

commonly used on the economizer tubes used in clean fuel applications. 80 fins/metre are

used when dry solid fuels are used and 120 fins/metre are used when oil fuels are used.

When high fouling fuels are used, ample clearance is left between fins; mainly to avoid the

bridging effects caused by soot deposits. Fin thickness ranges from 0.5 mm to 5 mm. Thick

fins offer greater heat transfer efficiency than thin fins and reduce total heat transfer surface

requirements. In addition to this, thicker fins have greater resistance to gas side erosion and

lower fin tip temperature. This is very important in material selection

(v) OTHER ADVANTAGES OF THE ECONOMIZER

There are several indirect advantages obtained by installing an economizer with a boiler

plant as listed below:

(1) The feeding of the boiler with water at a temperature near the boiling point reduces

the temperature differences in the boiler, prevents the formation of stagnation pocket of the

cold water and thus reduces greatly the thermal stress created in the pressure parts of the

boiler and promotes better internal circulation.

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(2) Due to the reduction in the combustion rate of the furnace, the boiler will be more

efficient and the actual fuel saving will be greater than the theoretically calculated.

(3) The flow of flue gases over the economizer tubes acts indirectly as grit arrested and

large portion of the soot and fly ash is deposited on the tubes and scraped of into the soot

chamber. This reduces the omission of soot and fly ash.

(vi) AIR PRE-HEATERS

The heat carried with the flue gases coming out of economizer are further utilized

for preheating the air before supplying to the combustion chamber. It has been found that an

increase of 20O C in the air temperature increases the boiler efficiency by 1%. The air

heater is not only considered in terms of boiler efficiency in modern power plants, but also

as a necessary equipment for supply of hot air for drying the coal in pulverized fuel systems

to facilitate grinding and satisfactory combustion of fuel in the furnace.

The use of preheater is much economical when used with pulverized fuel boilers

because the temperature of flue gases going out is sufficiently high and high air temperature

(250 to 350°C) is always desirable for better combustion. Air heaters are usually installed

on steam generators that burn solid fuels but rarely on gas or oil fired units. By contrast,

economizers are specified for most boilers burning liquid or gas or coal whether or not an

air heater is provided. The principle benefits of preheating the air are:

(1) Improved combustion,

(2) Successful use of low grade fuel (high ash content)

(3) Increased thermal efficiency,

(4) Saving in fuel consumption and

(5) Increased steam generation capacity (kg/m2 -hr) of the boiler.

The air preheater must provide reliability of operation, should occupy small space, must be

reasonable in first cost and should be easily accessible.

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4. SUPERHEATER

Consideration for protecting superheater is a controlling factor in determining how

rapidly a natural circulation unit should be brought up to pressure. The saturated

temperature increase must not exceed 110°C per hour during start-ups. The superheated

elements should be heated as evenly as possible and the maximum temperature of the flue

gas entering the first gas touching superheater elements ("Furnace Exit Gas Temperature")

should be carefully monitored and controlled during start-ups. The furnace exit gas

temperature is normally measured by means of a start-up thermocouple probe traversing

about half the width of the furnace. The point of maximum temperature must be determined

each time the firing pattern is changed. The maximum furnace exit gas temperature should

be limited to 540O C until the steam now is established through superheater.

To assure clearing the superheater element loops of condensate, provision must be

made for adequate flow of steam through the superheater while starting up. Drain and vent

valves in the outlet headers and/or the main steam line should be opened before the unit is

fired and kept open until the unit is steaming under load. These starting vents may be

throttled gradually as drum pressure increases, provided sufficient flow through the

superheater is assured at all time. When the turbine is synchronized and carrying load an

adequate steam flow will be assured, the superheater start up vents may be closed.

While carrying load, protection in the event of a sudden interruption of steam now is

provided by the superheater safety valves, which are set to "pop" before the drum safety

valves. If the flow of steam from the boiler is suddenly stopped, the superheater safety

valves will open first and re-establish the flow. It is imperative that all fuel be tripped

immediately when such interruptions of steam flow occur. Care must be exercised to avoid

carry-over of water and solids to the superheater and turbine. Steam samples should be

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taken at frequent intervals for the purpose of detecting evidence of carry-over.

Steam conductivity records are commonly used for this purpose. Sampling connections are

normally provided in the superheater connecting tubes, leaving the steam drum. Carry over

may be caused by abnormal high water level, especially if the steaming rate is high. If

carrying-over suspected, steps should be taken immediately to investigate and eliminate the

conditions causing this carry-over. If the investigation indicates that the carrying-over is not

result of improper water condition, the steam internals and the water level control indicating

equipment should be inspected at the first possible opportunity.

Fig.4 WATER WALL PLATEN

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Fig.5 SUPER HEATER PLANTEN

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Fig.6 SUPER HEATER FINISH 1 & 2

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Fig.7 LOW TEMPERATURE SUPER HEATER

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5. SOOT BLOWERS

Soot blowers should be operated as often as necessary to keep the external

heating surfaces clean a high economizer exit gas temperature and/or erratic steam

temperature control action may be an indication of the need for lowing soot. Recording and

comparing this exit gas temperature at various loads and furnace conditions can establish a

proper soot blower's schedule. It will be found more difficult to use the soot blowers

effectively if, during a period of neglect, a considerable amount of fly ash or slag is allowed

to build up. Never use soot blowers on a cold boiler. Always be sure that the combustion

rate is high enough when blowing soot so that the fires are not extinguished. If the soot-

blowing medium is steam, proper drainage of the soot blower piping system is very

important in preventing pressure parts erosion. There should be no water pockets whatever

in the piping. A 8 mm X 3 mm hole is often drilled through the seat of the drain valve so as

to permit continuous drainage of any condense formed. Let the steam blow freely long

enough to heat the lines thoroughly before operating the soot blowers.

(i) SECOND AIR DAMPER SYSTEM

All the secondary air dampers should be connected to the power cylinders and made

operable from control room. Preferably they should be in auto operation the wind box to

furnace differential pressure, which can be judiciously set to suit combustion conditions (if

some to the damper are in the delinked condition and the air flow distribution around the

four corners will not be equal). The fuel air should be opened to ensure a flame front within

1 to ¬1.5m from the burner tip. A thumb rule for ensuring this is to see the flame through

the peephole in the front and rear wall adjacent to the burner nozzle elevation and watch for

the disappearance of the block coal stream. The auxiliary air dampers should be modulated

to maintain a furnace to wind box differential of 50-70 mmwc, again as to avoid tendency.

These properties vary with the coal and hence periodic adjustments are required.

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6. AIR AND FLUE GAS SYSTEM

All dampers and gates, especially the control dampers with actuators are to be

serviced and kept in good operating condition. These dampers playa vital role in airflow and

draft control in the furnace. Draft measurements and temperature measurements are also

equally important for the performance monitoring. Providing draft measurements at FD fan

outlet and outlet of Air Per-Heater and ID Fans.

(i) TANGENTIAL FIRING

In the tangential firing system the furnace itself constitutes the burning fuel

and air are introduced to furnace through wind box assemblies located in the furnace

corners. The fuel and air steams from the wind box nozzles are directed to the firing circle

in the centre of the furnace. The rotative or cyclonic action that is characteristic of this type

of firing is most effect in turbulently mixing the burning fuel in a constantly changing air

and gas atmosphere.

Fig.8 TANGENTIAL FIRING

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Fig.9 CYCLONIC EFFECT

(ii)WIND BOX ASSEMBLY

The fuel burning equipment consists of 4 wind box assemblies located in the furnace

corners. Each wind box assembly is divided in its height into a number of sections called

compartments. Some compartments are provided with coal nozzles, oil guns or gas spuds.

The rest of the nozzles are called auxiliary air nozzles. The compartments are provided

with lower type of dampers. The dampers of 4 corners operate in unison on elevation basis.

Each set of dampers are operated by pneumatic damper drives remote manually from the

secondary air damper control system in conjunction with furnace safe guard supervisory

system. Some of the intermediate air nozzles are provided with air cooled oil guns and gas

spuds. The spuds can be used to fire CO Gas. The eddy plate oil igniters are provided

adolescent to the oil guns or gas spuds. These igniters are used to light up the oil guns or

gas spuds.

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Fig.10 FURNACE PLAN

(iii)SETTING AUTOMATIC WIND BOX DAMPER CONTROL

Auxiliary dampers are controlled by automatic wind box damper controls. Normally

the wind box to furnace differential pressure is controlled at pre-determined value to

maintain proper air flow distribution and velocity through the compartments. At loads

above 30% MCR load, the wind box to furnace differential pressure is increased to a value

depending up on the fuel being fired.

(iv) FUEL COMPARTMENT DAMPERS

The fuel compartment dampers are the ones situated behind coal nozzles, CO

spuds/oil guns. These are designed to operate from a minimum opening to maximum

opening, according to the fuel firing rate. The point of minimum opening and the maximum

opening are independently adjustable. The minimum opening is decided based on the

requirement for starting the burners, ignition stability and it should also ensure that flame

does not sit on the nozzle itself. The flame should be around 200 to 500 mm away

from the nozzles to avoid heating up of the wind box nozzle which will result in to warpage

to wind box.

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(v) FUEL COMPARTMENT DAMPERS

The fuel compartment dampers are the ones situated behind coal nozzles, CO

spuds/oil guns. These are designed to operate from a minimum opening to maximum

opening, according to the fuel firing rate. The point of minimum opening and the maximum

opening are independently adjustable. The minimum opening is decided based on the

requirement for starting the burners, ignition stability and it should also ensure that flame

does not sit on the nozzle itself. The flame should be around 200 to 500 mm away from the

nozzles to avoid heating up of the wind box nozzle which will result in to warpage to wind

box.

The optimum setting the damper controller for a particular unit must be based on the

conditions that are present on that particular unit. It depends primarily on the fuel being

burnt. In general the factors which determine the settings are:

• Ignition stability

• Ignition point relative to fuel nozzle

• Overall combustion conditions in furnace

On coal fired units the characteristics of the fuel itself will dictate how the damper

controller is set. The volatile matter content, moisture content and ash content all of which

affect ignition will determine the setting. With high volatile coals, it will probably be

necessary to characterize the dampers to reach 100% open at some fuel input less than

100% say 50% to 60 % and to open the dampers at minimum feeder speed to some

minimum position such as 20%. On very low volatile coals it may be necessary to restrict

the maximum opening to considerably less than 100% at 100% fuel input (for instant to

40% opening) and perhaps even not start opening the dampers unit fuel input is to

some point higher than minimum (for instant 30% to 40% feeder speed).

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It must be kept in mind that the final setting must not produce hazardous conditions

either from ignition instability or from ignition point being too close to the fuel nozzles at

all possible operating conditions of load, numbers of mills in service etc.

Fuel compartment dampers are normally closed on all elevations until each elevation

is lit off, at which time the particular elevation fuel damper control is put on automatic and

follows the pre-set characteristic with fuel input. The BFG compartment fuel air dampers

are controlled remote manually and adjusted by operator depending on firing conditions.

(vi) BURNER ARRANGEMENT

The tangentially fired boiler, four tall wind boxes (combustion air boxes) are

arranged one at each corner of the furnace. The coal burners or coal nozzles are located at

different levels or elevations of the wind boxes. The numbers of coal nozzle elevations are

equivalent to the number of coal mills. The same elevation of coal nozzles at four corners

are fed from a single coal mill. The coal nozzles are sandwiched between air nozzles or air

compartments i.e., air nozzles are arranged between coal nozzles one below the bottom coal

nozzle and one above the top coal nozzle. In this unit there are seven number of coal

nozzles per corner and eight number of air nozzle per corner. As a special design below

the standard bottom end air nozzle on BFG fuel nozzle is located per corner.

The cold nozzles are of fixed split type which gives stable flame even at low loads.

The air nozzles in between coal nozzles are termed as auxiliary air nozzles and the top most

and bottom most air nozzles as end air nozzles.

The coal nozzle elevations are designated as A to G from bottom to top, the bottom

end air nozzle as EA and the top end air nozzle as EA. The auxiliary air nozzles are

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designated by the adjacent coal nozzles; like AB, BC etc from bottom to top. The four

furnace corners are designated as 1, 2, 3 & 4 in clockwise direction looking from top and

counting front water wall left corners as ‘1’.

Each pair of coal nozzle elevations are served by one elevation of oil burners located

in the in-between auxiliary air nozzles. In this unit, seven mill or seven elevations of coal

nozzles and one elevation of BFG fuel nozzles are provided. The oil guns are located in

elevation AA to serve BFG fuel nozzles and A- elevation coal nozzles, and oil guns in

elevation BC to serve B & C- elevation coal fuel nozzles etc. Thus there are 16 oil guns

arranged in 4 levels.

Heavy fuel oil can be fired at all the 16 oil guns. Light fuel oil can be fired only in

the bottom elevation of 4 oil guns. Oil guns are atomizers are the same for both the fuel and

either of the oils can be fired at elevation – AA oil guns, by opening up the appropriate

valves at the individual oil gun connections.

COG Spuds are located on the top and bottom of oil guns in the auxiliary air

compartments. There are 4 elevations of COG spuds in total. The auxiliary air dampers are

used for regulation of combustion air for the COG burning. Each oil gun COG spud is

associated with an igniter arrangement.

(vii) COMBUSTION AIR DISTRIBUTION

Of the total combustion air supplied by FD fan, a portion called ‘Primary Air’ goes to the

coal mills for drying and carrying it to the coal nozzles. This primary air flow quantity

depends on the coal mill load and number of coal mills in service.

The balance of the combustion air is referred as ‘Secondary Air’. A portion of ‘SA’ is

admitted immediately and around the coal fuel nozzles (annular space around the casting

27

insert) in to the furnace. The rest of the SA is admitted through auxiliary air nozzle and end

air nozzles. The total air control is dictated by boiler load and controlled by FD fan vane

regulation and also the fuels fired.

The proportioning of air flow between the various nozzles is done based on boiler load,

individual burner load and type of fuel fired by a series of air dampers. Each of the coal

fuel nozzles and auxiliary and end air nozzles are provided with a lower type of regulating

dampers, at the air entry to individual nozzle or compartment. In the contract there are 7

coal air dampers, 7 auxiliary air dampers, 2 end air dampers and 1 BFG air damper per

corner.

Each damper is driven by an air cylinder positioned set, which receives signal from

secondary air control system. The dampers regulate on elevation basis, in unison at all

corners. The BFG air dampers and BFG end air damper are manually operated from the

remove according to the firing conditions.

(viii) BFG DAMPERS

At each corner the BFG entry into the furnace is divided into 2 sections. The top

section is provided with a manual damper and bottom section is provided with a self

regulating pneumatic damper. These dampers are part of wind box. The self regulating

damper at the bottom part closes or opens to maintain a constant BFG pressure before the

burner. And hence the velocity of the BFG is maintained at a constant level at the top port

thereby proper mixing and combustion of BFG is ensured. These gives better stability to

the BFG flame and better turn down.

7. PERFORMANCE

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All steam generating equipment is designed for a specific purpose. When supplied with feed

water at a specific temperature, the unit will deliver a definite quantity of steam at the

design pressure and temperature. Operating at conditions, which exceed the design

limitations, will shorten the life of the boiler and its components.

The concentration of solids entrained in the steam leaving the steam drum will depend to a

great extent upon the quality of the feedwater. Suitable make-up water treatment and an

adequate blow down programme should be employed to control the boiler water alkalinity,

silica and concentration of dissolved and suspended solids in the boiler water. Adequate

mechanical deaeration of the feedwater should be provided and steps taken to control the

level of metallic oxides entering the boiler in the feed water.

The quantity of fuel consumed is greatly measured and recorded. The means employed will

depend upon the nature of the fuel and equipment available for measuring. A representative

fuel sample should be obtained periodically. The services of competent laboratory should be

employed to analyze the fuel with respect to chemical constituents, calorific value, viscosity

(liquid fuels) and other physical characteristics, which could have an unfavourable influence

on operation and efficiency.

An analysis of the flue gases leaving the boiler is invaluable as an index complete and

economical combustion. Combustion should be completed before the gases leave the

furnace. The best percentage of excess air to use will depend upon the nature of fuel, the

design of the fuel burning equipment and other factors. The most desirable excess air for

different rates of evaporation must be established for each installation. The presence of

carbon monoxide (CO) in the flue gas indicates incomplete combustion. The Orsat

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apparatus is the most reliable mean of analyzing flue gases and should be used as a check

even when other instruments are provided to furnish this data. For determination of the

percentage CO, CO2 and O2 gas samples should be obtained at the rear pass outlet

upstream of the air heater.

When the heat transfer surface are kept clean, the temperature of the flue gases

leaving the air heater and the draft less through the unit will be substantially a constant for a

given rating and percent excess air. This illustrates the desirability of keeping accurate

records of performance from the starts of operation. Operating data should be recorded in a

form that will facilitate comparison with data taken under similar operating conditions.

When the equipment is new, standards should be established to serve as measures, to

satisfactory operation. Then if operating conditions deviate from this established standards

steps could be taken to determine and correct the cause of the discrepancy.

(i) EFFICIENCY GAIN

Potential efficiency improvement from condensation heat recovery can be

visualized. If the flue gas is cooled from 150°C to the dew point temperature of 60°C, an

efficiency improvement of 3% is possible. Further cooling, resulting in condensation of

water vapour drastically increases heat recovery. At the outlet temperature of 40O C, the

efficiency improvement may be as high as 11%. This indicates the importance of achieving

flue gas condensation. If the flue gas temperature is reduced in this system 250°C to 40°C,

15% increase in efficiency can be achieved.

The efficiency gain of a specific installation depends upon

(i) Fuel used (H2 content in fuel).

(ii) Flue gas exit temperature from boiler. .

(iii) Amount of low-level heat needed.

(iv) Fuel moisture content.

(v) Air humidity used for combustion.

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The different advantages of high-pressure boilers are listed below:

(1) The tendency of scale formation is eliminated due to high velocity of water through

the tubes.

(2) Lightweight tubes with better heating surface arrangement can be used. The space

required is also less. The cost of foundation, the time of erection and cost are reduced due to

less weight of the tubes used.

(3) Due to use of forced circulation, there is more freedom in the arrangement of

furnace, tubes and boiler components.

(4) All the parts are uniformly heated, therefore the danger of overheating is reduced

and thermal stress problem is simplified.

(5) The differential expansion is reduced due to uniform temperature and this reduces

the possibility of gas and air leakages.

(6) The components can be arranged horizontally, as high head required for natural

circulation. There is a greater flexibility in the component arrangement.

(7) The steam can be raised quickly to meet the variable load requirement without the

use of complicated control devices.

(8) The efficiency of plant is increased upto 40 to 42% by using high pressure and high

temperature steam.

(9) A very rapid start from cold is possible if an external supply of power is available.

Hence the boiler can be used for carrying peak loads or standby purposes with hydraulic

station.

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8. QUICK ESTIMATION OF

BOILER PERFORMANCE PARAMETERS

(i) INTRODUCTION

Boiler engineers and operators frequently assess the performance of their boilers.

The assessment may be for maintenance, troubleshooting, calibration and checking of plant

instruments or for computing operating costs. A method to quickly and accurately estimate

the air and gas side parameter from locally available data is the theme of this article.

Complicated formulae are reduced to simple equations so that estimation of performance

parameters can be done at site with a simple calculator. The amount of data required is also

kept to a minimum.

(ii) THEORETICAL DRY AIR REQUIREMENT

Statistically it has been found out that the theoretical dry air required for a heat

input of one million kCal (MkCal) is fairly constant for a given type of fuel. The

simplification of various equations is based on the following assumption.

Theoretical Dry Air (WTA) - kg/MkCal

1360 -- Coal

1325 – Oil

1300 Gas

(iii) QUALITY & COMPOSITION OF FUEL

The quality and composition of the fuel are a vital requirement for these

calculations. In coal-fired units, the data that is readily available daily is the proximate

analysis and gross calorific value as indicated below.

PROXIMATE ANALYSIS OF COAL (AS FIRE BASIS)

M – Total Moisture %

Ash – Ash %

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VM – Volatile Matter %

FC – Fixed Carbon %

Gross CV of Coal (as fired basis) HHV – kCal/kg)

S.No. Description Values

1. Total moisture 7.2%

2. Volatile matter 22.61%

3. Ash 40.21%

4. Fixed carbon 29.98%

The percentage constituents in coal and the gross calorific value are related by formula

given below. This formula, derived from statistical analysis of different samples, can be

used to check the correctiveness of proximate analysis and HHV reported within a tolerance

of 150 kCal/kg.

Gross CV (kCal/kg) HHV = [83.052* FC + 57.992*VM -14.178* Ash¬ - 43.611*

M + 797.746]. For oil and gas, calculations can be done based on the Gross CV of the fuel.

EXCESS AIR

Excess air is one of the most important parameters in boiler operation. This controls

the efficiency and heat transfer in the boiler. This oxygen content in the flue gas is the

measure of the level of excess air. Normally the boiler excess air is defined at economizer

outlet, which can be considered to the same as that in the furnace. Excess air can be

calculated by the following formula.

Excess Air (%) EAI = [O2 i /(21 – O2 i )] * 100 *kj

O2 i – Oxygen in flue gas at economizer outlet %

k1 – 1.00 for Coal

k2 – 0.95 for Oil

k3 – 0.92 for Gas

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O2 % ON DRY BASIS

All calculations in this article are based on oxygen on flue gas measurements on a

dry basis. Extractive flue gas sampling will give flue gas analysis on a dry basis. In-situ

measurements using zirconium probes will give flue gas analysis on a wet basis. The

following relation can correct wet basis measurements to dry basis:

O2%. - dry basis = [O2% wet basis] / k2

k2 – 0.90 for Coal

k2 – 0.87 for Oil

k¬ – 0.81 for Gas

(iv) EFFICIENCY

The most important boiler performance indicator is the efficiency. The complicated

efficiency calculations in performance test codes have been simplified and are given below.

Only the three main losses are calculated.

Dry gas loss is the most important controllable loss in a boiler. The assumed value

of WTA is used to compute dry gas loss as per the formula given below. Air heater outlet is

considered as the boundary of the boiler. The gas temperature and flue gas O2 % leaving air

heater, along with ambient temperature, is used for computation.

Dry Gas Loss (%) DGL = [0.000529 * WTA * (TGO - TA)] / (21-O2)

TA - Ambient Temperature °C

TGO - Exit Gas Temperature °C

O2 - Oxygen in Flue Gas at Exit %

The second main loss in a boiler is the hydrogen and moisture loss. The operator

does not have a control on this loss. It is totally fuel dependent. Hydrogen in coal is

estimated from proximate analysis using the following statistically derived formulae.

Hydrogen (%) H = -3.45 - 0.0005 * M + 0.023 * Ash + 0.126 * VM -¬ 0.0013 * VM2 +

0.0007 * HHV.

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For Natural gas fired boilers, the hydrogen value can be found out from the fuel gas

analysis. For oil firing, the hydrogen value of the design fuel can be used. Moisture loss

due to hydrogen and moisture in fuel is calculated based on the following formula.

Moisture Loss (%) ML = [(9H + M) * (0.45 TGO + 597.3 - TA)] / HHV

The third important loss in a coal-fired boiler is the loss due to combustibles in ash.

This is not applicable to oil and gas fired boilers. The data required for analysis is the

combustibles in bottom ash and fly ash. This analysis is normally done daily in a coal-fired

power plant. For pulverized coal fired, ash distribution is taken as 15 % in bottom hoppers

and 85 % in ESP hoppers. The following formulae compute the loss due to combustibles in

ash:

Wt. Average Combustibles (%)...UW = 0.85 * Ufa + 0.15 * Uba

UW - Combustibles in Fly Ash (%)

Uba - Combustibles in bottom Ash (%)

Combustible Loss (%) UL = [Uw * Ash * 8077] / (100- UW) * HHV]

Another important loss in a boiler is the carbon monoxide (CO) loss. Carbon

monoxide levels in a normally operating boiler will be low (in the range of 150 PPM) and

the loss also will be significantly low. With bad combustion, and low excess air, the levels

can go very high (in the range of 3000 to 10000 PPM). The probability is more in the case

of oil and gas fired boilers. The following formula can be used to compute this loss:

CO Loss (%) COL = [(4.89*10-6 * WTA / (21-O2)]* CO

- [CO - CO in Flue Gas - PPM]

The other losses are fixed in nature and are uncontrollable by the operator. Hence the value

of these losses is assumed to be constant.

Other Losses (%) OL: Assume 1.25 % Ash % > 30

Assume 0.75 % -- Ash % < 30

Assume 0.5 % -- oil & gas

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The boiler efficiency is calculated as follows:

Boiler Efficiency (%) = 100 – DGL – ML – UL – COL – OL

FOR 30% BF GAS :

Data Taken:

Theoretical Dry Air (WTA)= 1342 kg/MkCal

Proximate Analysis of Coal (As fired basis)

¬M – Total Moisture(%) – 7.2%

Ash – Ash (%) – 40.21

VM - Volatile Matter (%) - 22.61%

FC – Fixed Carbon (%) - 29.98

TA – Ambient Temperature (OC) - 37

TGO - Exit Gas Temperature (OC) – 220

O2 – Oxygen in flue gas at exit (%) - 5.79

Gross CV (kCal/kg) - HHV = [83.052 * FC + 57.992 * VM - 14.178 *

Ash - 43.611 * M + 797.746]

HHV = [83.052*29.98+57.992*22.61 –14.178*40.21– 43.611*7.2+797.746]

HHV = 3714.75

Dry Gas Loss (%) – DG1 = [0.000529*WTA * (TGO-TA)] / (21 - O2)

DGL = [0.000529*1342*(220 – 37)] / 21 – 5.79)

DGL = 8.54%

Hydrogen (%) – H = -3.45 – 0.0005*M+0.023*Ash+0.126*VM

- 0.0013*VM2 + 0.0007*HHV

H = 2.25%

Moisture Loss (%) – ML = [(9H+M) (0.45TGO+597.3-TA)]/HHV

ML = [(9*2.25+7.2)(0.45*220+597.3-37)]/3714.75

ML = 4.87 %

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Wt Average Combustible (%) –UW = 0.85*Ufa+0.15*Uba

Ufa – Combustible in fly ash (%) – 4

Uba – Combustible in bottom ash (%) – 2

Wt Average combustible (%) UW = 3.7%

Combustible loss (%) UL – UW*Ash*8077]/(100-UW)*HHV]

UL = [3.7*40.21*8077] / [(100-3.7)*3714.75]

Ut = 3.36%

CO loss (%) COL = (4.89*10-6*WTA*CO) / (21-O2)

CO – CO in flue gas (PPM) – 3000

COL = (4.89*10-6*1342*3000) / (21-5.79)

COL = 1.29%

Other losses (%) OL =1.25 (Assume)

Efficiency h = 100 – DGL – ML – UL – COL – OL

h = 80.69%

FOR 35% BF GAS

Data Taken:

Theoretical Dry Air (WTA)= 1339 kg/MkCal

Proximate Analysis of Coal (as fired basis)

¬M – Total Moisture(%) – 7.2%

Ash – Ash (%) – 40.21

VM - Volatile Matter (%) - 22.61%

FC – Fixed Carbon (%) - 29.98

TA – Ambient Temperature (OC) - 37

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TGO - Exit Gas Temperature (OC) – 229.7

O2 – Oxygen in flue gas at exit (%) – 5.98

Gross CV (kCal/kg)- HHV = [83.052 * FC + 57.992 * VM - 14.178 *

Ash - 43.611 * M + 797.746]

HHV = [83.052 * 29.98+57.99*22.61 –

14.178*40.21 – 43.611*7.2+797.746

HHV = 3714.75

Dry Gas Loss (%) – DGL = [0.000529*WTA * (TGO-TA)] / (21 - O2)

DGL = [0.000529*1339*(229.7– 37)] / 21 – 5.98)

DGL = 9.08%

Hydrogen (%) – H = -3.45 – 0.0005*M+0.023*Ash+0.126*VM

- 0.0013*VM2 + 0.0007*HHV

H = 2.25%

Moisture Loss (%) – ML = [(9H+M) (0.45TGO+597.3-TA)]/HHV

ML = [(9*2.25+7.2)(0.45*229.7+597.3-37)]/3714.75

ML = 4.90%

Wt Average Combustible (%) –UW = 0.85*Ufa+0.15*Uba

Ufa – Combustible in fly ash (%) – 5

Uba – Combustible in bottom ash (%) – 2

Wt Average combustible (%) UW = 4.55%

Combustible loss (%) UL – UW*Ash*8077]/(100-UW)*HHV]

UL = [3.7*40.21*8077] / [(100-4.55*3714.75]

UL = 4.16%

CO loss (%) COL = (4.89*10-6*WTA*CO) / (21-O2)

CO – CO in flue gas (PPM) – 4000

38

COL = (4.89*10-6*1339*4000) / (21-5.98)

COL = 1.74%

Other losses (%) OL =1.25 (Assume)

Efficiency h = 100 – DGL – ML – UL – COL – OL

h = 78.87%

39