ENHANCING THE PERFORMANCE OF BOILERS IN THERMAL

POWER PLANT

A Project Report submitted in the partial fulfillment of the requirements for the award of thedegree of

BACHELOR OF TECHNOLOGYIN

MECHANICAL (MANUFACTURING & MANAGEMENT)ENGINEERING

By

M RAJ KUMAR(101FA08027)P SHANKAR(101FA08042)

V RAGHU(101FA08057)V VINOD BABU(101FA08058)

Under the esteemed guidance ofSri K CHANDA (AGM), TPP

B NAGESWAR RAO Assistant professor

DEPARTMENT OF MECHANICAL ENGINEERINGVIGNAN UNIVERSITY

GUNTUR

CERTIFICATEThis is to certify that this project work entitled “ENHANCING THE

PERFORMANCE OF BOILERS IN THERMAL POWER PLANT” is the

bonafide work submitted by M Raj kumar,P Shankar,V Raghu,V Vinod babu under my

guidance in partial fulfillment of requirements for the award of Bachelor of technology in

“MECHANICAL ENGINEERING”, VIGNAN University, Guntur during the academic year

2013-2014.

Project Guide Head of the DepartmentSri.K Chanda Dr. K.Vidhu A.GM (OPR) Assistant ProfessorDepartment of TPP Department of Mechanical EnggVisakhapatnam steel plant Vignan University Vizag. Guntur.

CONTENTSCHAPTER No. CHAPTER PAGE No.

1. Introduction1.1 Brief Description About TPP 91.2 Salient Technological Features of TPP 10

2

1.3 Process Flow Chart of TPP 131.4 Design Capacity 14

1.5 Summary 15

2. Boiler

2.1Boiler Overview 16

2.2 Constructional Details 17

2.3 Practical Observation 24

3. Energy Performance Assessment Of Boilers

3.1 Introduction 25

3.2 Purpose Of The Performance Test 25

3.3 Scope 25

3.4 Reference Standards 25

3.5 The Direct Method Testing 26

3.6 The Indirect Method Testing 28

3.7 Practical Work 34

3.8 Factors affecting boiler performance 39

3.9 Summary 40

4. Heat Recovery And Performance Enhancement

4.1 Introduction 41

4.2 Heat Recovery from flue gas 41

4.3 Flue Gas Desulphurisation 44

4.4 Best Practices 46

4.5 Discussion 51

5. Conclusion 52

6. References 53

1. INTRODUCTION

The Visakhapatnam Steel Plant (VSP) is a 3 Mt Integrated Steel Plant under the corporate

entity, Rashtriya Ispat Nigam Limited (RINL). VSP is the first shore based Integrated Steel

Plant in the country. The plant produces steel through the BF-BOF route. VSP has the

distinction of being the first integrated steel Plant in the country to adopt 100% continuous3

casting. Currently the plant is operating at 4.0 MT of hot metal, 3.56 MT liquid steel and

3.17 MT of saleable steel representing capacity utilization of over 115%.

Steel industry being energy intensive in nature from raw material stage to finishing stage

about 470-480 KWH of electricity is used. For every tonne of steel produced and Steel

industry requires about 250-260 MW of electricity for running various drives in the plant.

RINL realized that electrical energy demand in integrated steel works can be met through

installation of captive power plant and support from Grid. RINL has captive power plant of

247.5 MW, and an additional 39 MW installed capacity for waste energy recovery, to meet

energy requirements in VSP.

1.1BRIEF DESCRIPTION ABOUT TPP

Steel industry is a power intensive industry and requires uninterrupted power supply to

critical loads. This requires a dependable and reliable captive power source which can cater to

all important loads of the plant all the time for safe and smooth operation of the steel plant.

Thermal Power Plant (TPP) in Visakhapatnam Steel Plant serves the above purpose, TPP has

a nameplate generating potential of 286.5 MW including auxiliary limits to cater to the plant

load requirements and to export surplus power to APTRANSCO as and when required. The

vital functions of TPP along with major equipment for the same are listed below:

1.To maintain average Power Generation level of 238 MW from TPP, GETS &

BPTS and be able to export surplus power when agreed upon with buyer.

The main Generating units are:

Main TPP of 247.5 MW capacity consisting of 3 X 60 MW sets and 1 X 67.5 MW

set.

4

Back Pressure Turbine Station (BPTS) of 15 MW capacity located in Coke Ovens

area having 2 X 7.5 MW units.

Gas Expansion Turbine Station (GETS) of 24 MW capacity located in Blast Furnace

area having 2 X 12 MW units.

BPTS and GETS are referred to as the Auxiliary Units of TPP.

2.To supply uninterrupted Cold Blast air to Blast Furnace as per BF flow requirements

Turbo Blowers of 6067 NM3 / min ensure uninterrupted Cold blast to the Blast

Furnace (2 working + 1 standby)

1To produce DM Water to meet both internal and Plant needs

Consists of 6 streams of De-mineralizing units of ( 5 X 125 + 1 X 110) M3/Hr

capacity

2.To supply process steam to the plant.

3.To supply chilled water to the plant.

1.2 SALIENT TECHNOLOGICAL FEATURES OF TPP UNITS

BOILERS

Thermal Power Plant has 5 Boilers each of 330 T/hr Steam capacity at 101 ATA and 540oC.

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 MW of

power, supply steam to 2 Turbo Blowers and process needs. Boiler’s outlet flue gas is passed

through Electro Static Precipitators to control air pollution. The fly ash and Bottom Ash

generated are pumped in slurry from to Ash Pond through on ground pipe lines. The clarified

water is re-circulated back to ash system.

TURBO GENERATORSThermal 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:-5

i. Electro Hydraulic Turbine Governing system.

ii.Controlled extractions at 13 ATA and 4 ATA for process steam needs in TG 1, 2 & 3.

iii.Central admission of steam to reduce axial thrust.

iv.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.

TURBO-BLOWERS

VSP has 2 Blast Furnaces. To meet the Blast air requirement, 3 Turbo Blowers, each of 6067

NM3/min 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 inner coolers.

AUXILIARIES OF TPP

These include coal conveyors, cooling towers & pump house no: 4 for cooling water system,

pump houses for ash water, ash slurry, fire water and fuel oil & HSD, air compressor station,

emergency diesel generators, electric switch gear for power distribution; ventilation and air

condition equipment etc. The entire power generated at Back Pressure Turbine Station and

Gas Expansion Turbine Station is transmitted over 11 KV cables to power plant, stepped up

through a 220 KV transformer at LBSS-5 and transferred to Plant Grid.

CHEMICAL WATER TREATMENT PLANT (CWTP)

Chemical Water Treatment Plant located in TPP zone produces high purity De-mineralized

water and soft water. There are six streams of De-mineralizing units each capable of

producing 125 cubic meters per hour and two softening units of 125 cu. meters per hour each.

DM Water is supplied to TPP, Steel Melt Shop, CDCP Boilers at Coke Ovens, and Rolling

Mills. Soft water is supplied to Chilled Water Plant I, II and SMS mould cooling. The return

condensate from Thermal Power Plant, Chilled Water Plant No:1 and Chilled Water Plant

No:2 is polished at CWTP in 2 streams, each of 100 cub. meter/hr capacity. All the de-

mineralized water produced / polished at CWTP is de-aerated and dosed with Ammonia

before pumping to consumers. 6 de-aerators are installed at CWTP for this purpose.

CHILLED WATER PLANT NO: 2 (CWP-2)

Chilled Water Plant No: 2 located 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

6

Sinter Plant for air conditioning purpose at 7oC. The return water temperature is 16oC. Steam

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

COKE DRY COOLING PLANT (CDCP) BOILERS

In VSP, hot coke produced in the Coke Oven Batteries is cooled by 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 440oC temperature. There are three Coke

Dry Cooling Plant four Waste Heat Boilers. Boiler is of 25 T/hr Capacity. These are once

through, forced circulation Boilers, Deaerators and Boiler Feed Pumps, serving all the 3

plants, are located at CDCP-1.

BACK PRESSURE TURBINE STATION AND CHILLED WATER PLANT NO:1

(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 zone. The CWP-1 has 5 chillers installed, each capable of cooling 337 Cu.

Meters of water per hour from 18 C to 10 C. The Chilled Water is supplied to Gas Coolers

and for air conditioning needs of COCCP Zone. BPTS and CWP-1 are housed in a single

building located near Battery No: 3 of CO & CCP Zone.

GAS EXPANSION TURBINE STATION (GETS)

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

kg/sq.cm. The high pressure of BF Gas after passing through the Turbine is fed to Gas

distribution net work and is used as heating fuel in TPP & other units of VSP. Each Blast

Furnace is connected to a Gas Expansion Turbine of 12 MW capacity 7.5 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.

1.3 DESIGN CAPACITYThe design capacity and current levels of operation 2006-07 figures are given in the table

below:

7

S.No. EQUIPMENT DESIGN CAPACITYCURRENT LEVELS OFOPERATION (2008-09)

01. Boilers 5 X 330 T= 1650 T/Hr. Steam capacity at 101 ATA and 540oC temperature.

1153 Tons/Hr.

02. Turbo Generators 3 X 60 MW + 1 X 67.5 MW = 247.5 MW

204.93 MW (under floating conditions)

03. Turbo Blowers 3 X 6067 NM3/min. 5815 NM3/min

04. CWTP 5 X 125 M3/Hr.1 X 110 M3/Hr.DM Water production 2 X 125 M3/Hr.Soft Water production

345.50 M3/Hr.

55 M3/Hr.

Chilled Water Plant-2

9 Chillers each 337M3/Hr. chilling capacity

1240 M3/Hr.

05. CDCP Boilers 12 X 25 T/Hr at 40 ATA and440oC temperature.

144.89 Tons/Hr.

06. BPTS 2 X 7.5 MW 11.64 MW

Chilled Water Plant-1

5 Chillers each 337M3/Hr. chilling capacity

1006.2 M3/Hr.

07. GETS 2 X12 MW 10.35 MW (due to low Gas pressure & flow at Turbine inlet).

1.4PROCESS FLOW CHART OF TPP

1.5 Summary

The thermal power plant unit of the steel plant is the major unit of the plant. The heart of this

unit is the boiler operation to generate required amount of electricity from steam. The steam

required to produce electricity is very high when compared to any other boilers. Beside that8

the plant should constantly produce the required amount of steam to generate uninterrupted

power supply to the whole industry. So the boilers are the primary requirement of the plant to

generate power and it should also run efficiently to meet the plant requirements.

2. BOILER

2.1 BOILER OVERVIEW

A steam generator or boiler is, usually, a closed vessel made of steel. Its functions is to

transfer the heat produced by combustion fuel (liquid, solid, or gaseous) to water, and

ultimately to generate steam. The steam produced may be supplied:

1.To steam engines or turbines (turbo generators)

2.At low pressures for industrial processes work

3.For producing hot water, which can be used in vapour absorption processes

In TPP, 5 boilers are installed with a capacity of 330 ton /hr each with 101 ATA and 12

auxiliary waste heat recovery boilers installed capacity 25 ton/hr each 40 ATA, to supply

steam to turbo generators for power generation and 13 ATA, 7 ATA steam for different

processes throughout the plant.

9

2.1 process flow chart

2.2 CONSTRUCTIONAL DETAILS

2.2.1 General specifications:

Make : BHEL, TRICHY.Type of unit : single drum, natural circulation, 3 stage superheated

balanced draught, multi fuel firing, non-reheatType of furnace : fusion welded dry bottomType of super heater : radiant and convectionType of economizer : plain tube in lineSteam Temperature Control : spray-type

2.2.2 The process in the boiler can be clearly understood by knowing the following

concepts:

Air / flue gas path

Water / steam path

Fuels and firing

Combustion in furnace

A.Air / flue gas path:

Air used for combustion of lignite or any other fuel applied in power generation, should be

preferably hot. Air pre-heaters are arranged in the flue gas ducts for preheating the air,

utilizing the heat in waste gases. FD fans suck atmosphere air and pass it through ducts of

rotary air heaters then temperature of air is raised up to 370°C.

The air then aid for combustion with fuels in tangential firing zone in furnace rises to

temperature of 1250°C and effects heat transfer through radiation dominantly. The direct

effect of radiation is absorbed by water wall platen then flue gas reduced to 980°C. Flue gas

from the furnace sweeps through the super heaters and then proceeds along the convective

shaft zone, where economizers and air heaters are arranged in the following manner along the

gas path:

1. low temperature super heater

2. economizer

3. tubular air heater

10

B. Water / steam path:

Water from DM plant pumped by BFP will enter economizer through Feed Regulating

Station, where manual and motor control valves operates according to the flow requirements

of boiler. Economizer heats water by exchanging of heat of flue gases established above air

preheater. After economizer water directly enters in to steam drum. Four of the 6 down

comers will form bottom ring at the base of boiler to form water walls which extends and

formed as furnace walls for the boiler. Headers, which collects steam from water walls pushes

mixture of water and steam in to drum by natural difference of density. Steam separator in

drum separates steam and water. Steam then again enters steam walls and then flows through

the below mentioned sequence:

low temperature super heater

platen super heater

final super heater

Finally steam enters 101 ATA headers.

C.Fuels and firing:

A coal fired unit incorporates oil burners also to a firing capacity of 25% of boiler load for the

reason of:

a) To provide necessary ignition energy to light off coal burner

b) To stabilize the coal flame at low boiler / burner loads

c) As a safe start up fuel and controlled heat input during light off

Light fuel oil: The fuel for the ignition is light fuel oil. Normally LFO is used for cold start

ups and it is sometimes referred as ‘warm-up fuel’. Being a distillate, LFO burns clean ad

complete in a cold furnace without any un-burnt oil conveyors. LFO has the advantage of

being low viscous at ambient temperatures requiring no heating, and it can be air atomized.

Heavy fuel oil: HFO recommended as startup fuel in a cold boiler if steam is available for

following services:

a) For atomizing the HFO at the oil gun

b) For tank heating, main heating and heat tracing of HFO

c) To preheat the air at the steam coil air pre-heater

11

Coke oven gas: Coke oven gas is supplied to the boiler from coke oven batteries. This gas

can be used for warming up and for load carrying. This gas gives stable flame normally

without any need for support by igniters. There are totally 32 COG gas spuds arranged in four

elevations in the auxiliary air compartments.

Blast furnace gas: This is supplied from blast furnaces. The calorific value of the gas is low

and hence needs support at low loads when the burnt separately. Also as no reliable flame

scanning can be obtained with this gas flame, an auxiliary firing either oil or coal firing is

resorted to whenever there is need for BFG firing. Also the gas is characterized by its high

level of toxicity and hence utmost care should be taken for handling this gas.

Pulverized coal fuel: Each boiler having 7 mills and they work according to the fuel

requirement and availability of BFG and COG. The coal grinded to very fine by the mill

grinders and of required grade powder only enters boiler by pneumatic transfer of primary air

which is coming from TAH at 370 C. Capacity of mills is 17 ton/hr and volumetric type. Cold

air arrangement is also there if the temperature of coal is too high. From each mill four outlets

will be there for each corner in a single elevation.

Tangential firing: In the tangential firing system the furnace itself constitutes the burner fuel

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

furnace corners. The fuel and air streams from the wind box nozzles are directed to a firing

circle in the center of the furnace. The rotative cyclonic action that is characteristic of this

type of firing is most effective in turbulently mixing the burning fuel in a constantly changing

air and gas atmosphere.

Fig. 2.2 Wind box Arrangement

12

C.Combustion in furnace:

Furnace is the place where combustion of the pulverized fuel and oil fuel takes place with the

aid of air supplied. We can say that two processes occur in the furnace simultaneously. One

process is that of a chemical reaction exothermic in nature which releases a lot of heat and the

other process is the transfer of this heat to the medium inside the water walls. So the

efficiency the furnace depends on the utilization of heat energy for evaporation of water and

in reduction of radiation and other losses.

In our boilers the furnace is a dry bottom pulverized fuel furnace having suspension system

of firing. Furnace is screened by water walls on all the four sides. Furnace bottom is hopper

shaped and is immersed in water in the slag bath. The maximum temperature encountered in

the furnace is 1250°C to 1300°C. since ash function temp is 1450°C fly ash collects at the

bottom of the furnace in solid state. 15% of ash falls below in the furnace into the slag bath.

They are cooled by the water in the slag bath and are removed by two slag conveyors.

2.2.3 Water Wall Furnace:

Furnace volume : 2300m3

Heat transfer area : 1230 m2

Area of refractory exposed to furnace: nil

Tube OD * thickness : 63.5 * 4.8 mm2

Tube material : SA 192

Pitch : 76.2 mm

No. of tubes in front and

Rear wall each : 132

No. of tubes in right and

left side wall each : 92

Design metal temperature : 373°C

Design pressure : 121 kg/cm2

Fig. 2.3 Water Wall Furnace

13

2.2.4 ECONOMIZER:

Type : Plain tube inline

Location : II nd pass after LTSH

Number of banks : 2

Tube OD * thickness : 44.5*4.5

Heat transfer area sq m : 2430

No of tubes transverse

to gas flow : 104

No of tubes along : 32gas flow

Design pressure : 124

Design temperature : 371

Fig. 2.4 Economizer

2.2.5 STEAM DRUM:

Type of construction : Welded

Inside diameter : 1524 mm

Thickness

Shell : 75/95 mm

Head : 75 mm

Length : 11800mm

Material : SA 299

Design pressure : 121 kg/cm2

Design material temperature : 323°C

Steam separator : Turbo separator

Steam scrubber : Screen drier, along the length of the drum

Fig. 2.5 Steam Drum

2.2.7 AIR HEATERS:

Primary:

14

Type : tubular

Number off : one

Location : II pass, after economizer

Medium : flue gas inside tubes and primary air outside.

Heat transfer area : 5827 m2

Tube OD * thickness : 51*2 mm2

Tube material : BS 1775 Grade II

Design temperature : 405°C Fig.2.6 Primary Air Heater

Secondary:

Type : Regenerative, bisector

Number off : one

Location : II pass, after tubular air heater

Heat transfer area : 19000

Height of heating element : 2000

Tube material : carbon steel-hot and intermediate Corten steel

Design metal temperature : 455°C

Fig. 2.7 Secondary Air Heater

2.2.8 FANS

Forced Draught Induced DraughtType Axial impulse Double suction radial

15

Number 2 2Flow 56.9 m3/sec 138 m3/secTemperature 50°C 217°CDensity of medium 1.076 kg/m3 0.7107 kg/m3

Speed 1480 rpm 715 rpmDrive Motor MotorMotor type Induction Squirrel cage inductionMotor rating 325 KW 900 KWMotor speed 1480 rpm 740 rpmType of fan coupling Direct, flexible HydraulicType of regulation IGV Speed control through

hydraulic coupling

(a) FD Fan (b) ID FanFig. 2.8 Fans

2.2.9 FEED WATER SYSTEM:

Requirement of the boiler feed water is met by a DM plant. Feed water is deaerated and then

pumped by a feed pump in to a common header from where the feed water is passed through

two HP heaters. Feed water from HP heaters passes through a common header from where

individual boilers are fed.

Feed pump:

Number off : 5+2 (stand by)

Type of drive : motor driven through step up gear box

Capacity : 375 cm3/hr

Head : 1441 mlc

Temperature of water : 142°C

Density : 924.3 kg/m3

Speed : 4305 rpm

Power input : 1680 KW

16

Booster pump : Seven

2.3 PRACTICAL OBSERVATIONS:

Only 5 of the 7 mills installed are in operation and the remaining two mills are dismantled

for all boilers and they are used as spare parts for the remaining equipments. The continuous

availability of COG and BOG in varied quantities demands only 4 coal mills in general and

AA, BC elevations are sufficient to supply gaseous fuel for running of boiler. DE, FG

elevations are presently not in use due to inadequate gas supply.

The above observation applies to oil input points also in the respective elevations

Retractable soot blowers are not commissioned and wall soot blowers are operating fewer

times than it intended due to ash accumulation and leak problems.

The efficiency of the boilers should be calculated to check the performance and take required

measures if necessary.

3. ENERGY PERFORMANCE ASSESSMENT OF BOILERS

3.1 IntroductionPerformance of the boiler, like efficiency and evaporation ratio reduces with time, due to poor

combustion, heat transfer fouling and poor operation and maintenance. Deterioration of fuel

quality and water quality also leads to poor performance of boiler. Efficiency testing helps us

to find out how far the boiler efficiency drifts away from the best efficiency. Any observed

abnormal deviations could therefore be investigated to pinpoint the problem area for

necessary corrective action. Hence it is necessary to find out the current level of efficiency

for performance evaluation, which is a pre requisite for energy conservation action in

industry.

3.2 Purpose of the Performance TestTo find out the efficiency of the boilerTo find out the Evaporation ratio

The purpose of the performance test is to determine actual performance and efficiency of the

boiler and compare it with design values or norms. It is an indicator for tracking day- to-day

and season-to-season variations in boiler efficiency and energy efficiency improvements.

3.3 ScopeThe procedure describes routine test for both oil fired and solid fuel fired boilers using coal,

agro residues etc. Only those observations and measurements need to be made which can be

readily applied and is necessary to attain the purpose of the test.

3.4 Reference Standards17

British standards, BS845: 1987The British Standard BS845: 1987 describes the methods and conditions under which a boiler

should be tested to determine its efficiency. For the testing to be done, the boiler should be

operated under steady load conditions (generally full load) for a period of one hour after

which readings would be taken during the next hour of steady operation to enable the

efficiency to be calculated.

The efficiency of a boiler is quoted as the % of useful heat available, expressed as a

percentage of the total energy potentially available by burning the fuel. This is expressed on

the basis of gross calorific value (GCV).

This deals with the complete heat balance and it has two parts:Part One deals with standard boilers, where the indirect method is specified

Part Two deals with complex plant where there are many channels of heat flow.

In this case, both the direct and indirect methods are applicable, in whole or in part.

ASME Standard: PTC-4-1 Power Test Code for Steam Generating UnitsThis consists of:

Part One: Direct method (also called as Input-output method)

Part Two: Indirect method (also called as Heat loss method)

IS 8753: Indian Standard for Boiler Efficiency TestingMost standards for computation of boiler efficiency, including IS 8753 and BS845 are

designed for spot measurement of boiler efficiency. Invariably, all these standards do not

include blow down as a loss in the efficiency determination process.

Basically Boiler efficiency can be tested by the following methods:

1. The Direct Method: Where the energy gain of the working fluid (water and steam) is

compared with the energy content of the boiler fuel.

2. The Indirect Method: Where the efficiency is the difference between the losses and the

energy input.

3.5 The Direct Method Testing

3.5.1 Description

This is also known as ‘input-output method’ due to the fact that it needs only the useful

output (steam) and the heat input (i.e. fuel) for evaluating the efficiency. This efficiency can

18

be evaluated using the formula:

3.5.2 Merits and Demerits of Direct Method

Merits

Plant people can evaluate quickly the efficiency of boilers

Requires few parameters for computation

Needs few instruments for monitoring

Demerits

Does not give clues to the operator as to why efficiency of system is lower

Does not calculate various losses accountable for various efficiency levels

Evaporation ratio and efficiency may mislead, if the steam is highly wet due to water

carryover

3.6 The Indirect Method Testing3.6.1 Description

19

The efficiency can be measured easily by measuring all the losses occurring in the boilers using the principles to be described. The disadvantages of the direct method can be overcomeby this method, which calculates the various heat losses associated with boiler.The efficiency can be arrived at, by subtracting the heat loss fractions from 100.An important advantage of this method is that the errors in measurement do not make significant change in efficiency.Thus if boiler efficiency is 90%, an error of 1% in direct method will result in significant change in efficiency. i.e. 90 ± 0.9 = 89.1 to 90.9. In indirect method, 1% error in measurement of losses will result inEfficiency = 100 - (10 ± 0.1) = 90 ± 0.1 = 89.9 to 90.1Various Heat losses occurring in the boiler are:

Fig. 3.1 Losses occurring in the boiler

The following losses are applicable to liquid, gas and solid fired boiler:

L1- Loss due to dry flue gas (sensible heat)

L2- Loss due to hydrogen in fuel (H2)

L3- Loss due to moisture in fuel (H2O)

L4- Loss due to moisture in air (H2O)

L5- Loss due to carbon monoxide (CO)

L6- Loss due to surface radiation, convection and other unaccounted losses which are

insignificant and are difficult to measure.

The following losses are applicable to solid fuel fired boiler in addition to above:

L7- Un burnt losses in fly ash (Carbon)

L8- Un burnt losses in bottom ash (Carbon)

Boiler Efficiency by indirect method = 100 – (L1+L2+L3+L4+L5+L6+L7+L8)

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3.6.2 Measurements Required for Performance Assessment Testing

The following parameters need to be measured, as applicable for the computation of boiler

efficiency and performance:

a) Flue gas analysis

1. Percentage of CO2or O2 in flue gas

2. Percentage of CO in flue gas

3. Temperature of flue gas

b) Flow meter measurements for

1. Fuel

2. Steam

3. Feed water

4. Condensate water

5. Combustion air

c) Temperature measurements for

1. Flue gas

2. Steam

3. Makeup water

4. Condensate return

5. Combustion air

6. Fuel

7. Boiler feed water

d) Pressure measurements for

1. Steam

2. Fuel

3. Combustion air, both primary and secondary

4. Draft

e) Water condition

1. Total dissolved solids (TDS)

2. pH

3. Blow down rate and quantity

3.6.3 Test Conditions and Precautions for Indirect Method Testing

A) The efficiency test does not account for:

Standby losses. Efficiency test is to be carried out, when the boiler is operating under a

steady load. Therefore, the combustion efficiency test does not reveal standby losses, which

occur between firing intervals.

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Blow down loss. The amount of energy wasted by blow down varies over a wide range.

Soot blower steam. The amount of steam used by soot blowers is variable that depends on

the type of fuel.

Auxiliary equipment energy consumption. The combustion efficiency test does not account

for the energy usage by auxiliary equipments, such as burners, fans, and pumps.

B) Preparations and pre-conditions for testing

Burning the specified fuel(s) at the required rate.

Tests are done while the boiler is under steady load. Testing is avoided during warming up

of boilers from a cold condition

The charts/tables are obtained for the additional data.

Sampling and analysis of fuel and ash.

Ensuring the accuracy of fuel and ash analysis in the laboratory.

Checking the type of blow down and method of measurement.

Ensuring proper operation of all instruments.

Checking for any air infiltration in the combustion zone.

C) Flue gas sampling location

It is suggested that the exit duct of the boiler be probed and traversed to find the location of

the zone of maximum temperature. This is likely to coincide with the zone of maximum gas

flow and is therefore a good sampling point for both temperature and gas analysis.

D) Planning for the testing

The testing is to be conducted for duration of 4 to 8 hours in a normal production day.

Advanced planning is essential for the resource arrangement of manpower, fuel, water and

instrument check etc and the same to be communicated to the boiler Supervisor and

Production Department.

Sufficient quantity of fuel stock and water storage required for the test duration should be

arranged so that a test is not disrupted due to non-availability of fuel and water.

Necessary sampling point and instruments are to be made available with working condition.

Lab Analysis should be carried out for fuel, flue gas and water in coordination with lab

personnel.

The steam table, psychometric chart, calculator are to be arranged for computation.

3.6.4 Boiler Efficiency by Indirect Method: Calculation Procedure and Formula

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In order to calculate the boiler efficiency by indirect method, all the losses that occur in the

boiler must be established. These losses are conveniently related to the amount of fuel burnt.

Theoretical (stoichiometric) air fuel ratio and excess air supplied are to be determined first for

computing the boiler losses. The formula is given below for the same.

Table. 3.2 Formula Table

L1. Heat loss due to dry flue gas (%)

This is the greatest boiler loss and can be calculated with the following formula:

% Heat loss in dry flue gas (L1) = [m*Cp*(Tf -Ta)/GCV of fuel]*100

L2. Heat loss due to evaporation of water formed due to H2 in fuel (%)

The combustion of hydrogen causes a heat loss because the product of combustion is water. This water is converted to steam and this carries away heat in the form of its latent heat.

% Heat loss due to formationof water from H2 in fuel (L2) = [9*H2*{584+Cp(Tf -Ta)}/GCV of fuel]*100

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L3. Heat loss due to moisture present in fuel (%)

Moisture entering the boiler with the fuel leaves as a superheated vapor. This moisture loss is

made up of the sensible heat to bring the moisture to boiling point, the latent heat of

evaporation of the moisture, and the superheat required bringing this steam to the temperature

of the exhaust gas. This loss can be calculated with the following formula

% Heat loss due to moisturein fuel (L3) = [M*{584+Cp(Tf-Ta)}/GCV of fuel]*100

L4. Heat loss due to moisture present in air (%)

Vapour in the form of humidity in the incoming air, is superheated as it passes through the

boiler. Since this heat passes up the stack, it must be included as a boiler loss.

To relate this loss to the mass of coal burned, the moisture content of the combustion air and

the amount of air supplied per unit mass of coal burned must be known.

The mass of vapour that air contains can be obtained from psychometric charts.

% Heat loss due to moisturein air (L4) = [AAS*humidity*Cp*(Tf-Ta)/GCV of fuel]*100

L5. Heat loss due to incomplete combustion (%)

Products formed by incomplete combustion could be mixed with oxygen and burned again

with a further release of energy. Such products include CO, H2, and various hydrocarbons and

are generally found in the flue gas of the boilers. Carbon monoxide is the only gas whose

concentration can be determined conveniently in a boiler plant test.

% Heat loss due to partialconversion of C to CO (L5) =[(%CO*C)/(%CO+%C)]*[5744/GCV of

fuel]*100

L6. Heat loss due to radiation and convection (%)

The other heat losses from a boiler consist of the loss of heat by radiation and convection

from the boiler casting into the surrounding boiler house.

Normally surface loss and other unaccounted losses is assumed based on the type and size of

the boiler as given below:

For industrial fire tube / packaged boiler = 1.5 to 2.5%

For industrial water tube boiler = 2 to 3%

For power station boiler = 0.4 to 1%

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L7. Heat loss due to unburned carbon in fly ash and bottom ash (%)

Small amounts of carbon will be left in the ash and this constitutes a loss of potential heat in

the fuel. To assess these heat losses, samples of ash must be analysed for carbon content. The

quantity of ash produced per unit of fuel must also be known.

% of heat loss due to unburned carbon

in fly ash = (Total ash collected/kg of fuel burnt*GCV

of fly ash*100) / GCV of fuel

% of heat loss due to unburned carbon

in fly ash = (Total ash collected/kg of fuel burnt*GCV

of bottom ash*100) / GCV of fuel

Heat Balance:

Having established the magnitude of all the losses mentioned above, a simple heat balance

would give the efficiency of the boiler. The efficiency is the difference between the energy

input to the boiler and the heat losses calculated.

3.7 Practical Work:

Efficiency of boilers in steel plant is calculated by Indirect Method and a sample calculation

is shown below. The Heat balance sheet is also prepared. The calculations are shown along

with the heat balance sheet. The parameters are obtained from the shift operator log book

from Main Control Room, TPP. The values are the mean of the readings taken from

November 2011 to January 2012.

3.7.1 Parameters for boiler efficiency calculation:

Fuel firing rate = 2560 tons/hrSteam generation rate = 330 tons/hrSteam pressure = 101 ATASteam temperature = 533 oCFeed water temperature = 196 oC%CO2 in Flue gas = 12%CO in flue gas = 0.50Average flue gas temperature = 190 oCAmbient temperature = 36 oCHumidity in ambient air = 0.0204 kg/kg dry airSurface temperature of boiler = 165 oCWind velocity around the boiler = 3.5 m/s

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Total surface area of boiler = 7397 m2

GCV of Bottom ash = 600 kCal/kgGCV of fly ash = 452.5 kCal/kgRatio of bottom ash to fly ash = 80:20

Fuel Analysis (in %)Ash content in fuel = 40.19Moisture in coal = 12.5Carbon content = 44.93Hydrogen content = 2.64Nitrogen content = 1.56Oxygen content = 14GCV of Coal = 2850 kcal/kg

3.7.2Efficiency Calculation by Indirect Method

Step-1 Finding theoretical air requirementTheoretical air requirement for

Complete combustion = [(11.6*C) + {34.8*(H2-O2/8)} + (4.35*S)]/100 kg/kg of coal

= [(11.6*44.93) + {34.8*(2.64-14/8)} + (4.35*0)]/100

= 5.55 kg/kg of coal

Step-2 Find theoretical CO2 %% CO2 at theoretical condition (CO2) t = Moles of C/ (Moles of N2+Moles of C)

Moles of N2 = (Wt of N2 in theoretical air/Mol.wt of N2 + (Wt of N2 in fuel/Mol.wt of N2)

Moles of N2 = [4.41*(77/100)]/28+ [1.56/28]=0.1767

Moles of C = 0.4493/12=0.0374

(CO2)t = 0.0374/(0.1767+0.0374)

(CO2)t = 17.46%

Step-3 To find excess air suppliedActual CO2 measured in flue gas=12.0%%Excess air supplied(ED) = 7900*[(CO2%)t+( CO2%)a]/(CO2)a%*[100-(CO2%)t] = 7900*[17.46-12]/12*[100-17.46] = 43.54%

Step-4 To find actual mass of air suppliedActual mass of air supplied = {1+EA/100}*theoretical air

= {1+43.54/100}*5.5

= 7.96kg/kg of coal

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Step-5 To find actual mass of dry flue gasMass of dry flue gas = Mass of CO 2+Mass of N2 content in the fuel + Mass of N2 in the Combustion air supplied + Mass ofO2 in flue gas Mass of dry flue gas = [(0.4165*44)/12] +0.0156+ (7.13*77)/100+ [(7.13-5.55)*23]/100 = 7.0689kg/kg of coalStep-6 To find all losses

1.% Heat loss in dry flue gas (L1) = [m*Cp*(Tf –Ta)/GCV of fuel]*100

= [7.0689*0.23*(190-36)/2850]*100

L1 =8.78%

2.% Heat loss due to formationof water from H2 in fuel (L2) = [9*H2*{584+Cp(Tf –Ta)}/GCV of fuel]*100

= [9*0.0264*{584+0.45(190-36)}/2850]*100

L2 =5.44%

3.% Heat loss due to moisturein fuel (L3) = [M*{584+Cp(Tf-Ta)}/GCV of fuel]*100

= [0.350*{584+0.45(190-36)}/2850]*100 L3 = 7.606%

4.% Heat loss due to moisturein air (L4) = [AAS*humidity*Cp*(Tf-Ta)/GCV of fuel]*100 = [7.96*0.024*0.45*(190-36)/2850]*100 L4 =0.464%5.% Heat loss due to partialconversion of C to CO (L5) =[(%CO*C)/(%CO+%C)]*[5744/GCV of

fuel]*100

= (0.5*0.4493)/(0.5+12)*[5744/2850]*100

L5 =3.622%

6.% Heat loss due to radiationand convection (L6) = 1% (using standard data for power plant

boilers)

L6 = 1%

7.% Heat loss due to un burntin fly ash

%Ash in coal = 40.19

Ratio of bottom ash to fly ash = 80:20

GCV of fly ash = 452.5Kcal/kg

Amount of fly ash in1kg of coal = 0.2*0.4019 = 0.08038kg

Heat loss in fly ash = 0.08038*452.5

= 36.371kCal/kg of coal

% Heat loss in fly ash = (36.371*100)/2850

L7 = 1.33%

8.% Heat loss due to un burnt27

in bottom ash

GCV of bottom ash = 600kCal/kg

Amount of bottom ash in 1 kgof coal = 0.8*0.4019

= 0.0644304kg

Heat loss in bottom ash = 0.064*600

= 51.4432kCal/kg of coal

%Heat loss in bottom ash = (51.4432*100)/2850

L8 = 6.76%

Boiler efficiency by indirect method = 100-(L1+L2+L3+L4+L5+L6+L7+L8) = 100 – (8.78+5.44+7.606+0.464+3.600+1+1.33+6.76)

= 100 – 34.97

= 65.03%

3.7.3 Summary of

Heat Balance for

Power Plant Boiler

Input/output Parameterkcal/kg of coal

Heat input = 2850

Losses in boiler

1.Dry flue gas,L1 = 250.23

2.Loss due to hydrogen in fuel,L2 = 155.04

3.Loss due to moisture in fuel,L3 = 216.771

4.Loss due to moisture in air,L4 = 13.224

5.Partial combustion of C to CO,L5 = 103.227

6.Surface heat losses,L6 = 28.5

7.Loss due to un burnt in fly ash,L7 = 37.905

8.Loss due to un burnt in bottom ash,L8 = 192.66

Boiler efficiency = 100 - (L1+L2+L3+L4+L5+L6+L7+L8) = 65.03%

3.8 Factors Affecting Boiler Performance

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The various factors affecting the boiler performance are listed below:

Periodical cleaning of boilers

Periodical soot blowing

Proper water treatment programme and blow down control

Draft control

Excess air control

Percentage loading of boiler

Steam generation pressure and temperature

Boiler insulation

Quality of fuel

3.9 Summary

All these factors individually/combined, contribute to the performance of the boiler and

reflected either in boiler efficiency or evaporation ratio. Based on the results obtained from

the testing further improvements have to be carried out for maximizing the performance. The

test can be repeated after modification or rectification of the problems and compared with

standard norms. Energy auditor should carry out this test as a routine manner once in six

months and report to the management for necessary action.

4. Heat Recovery and Performance Enhancement4.1 Introduction

Based upon the efficiency calculations, we have found that lot of heat energy is wasted from

flue gas loss and loss due to moisture content in fuel. Moreover due to moisture in fuel, lot of

energy is wasted as unburned fuel or formation of bottom ash. So to enhance the performance

of boilers, we have to extract sensible heat from flue gas and use it for various purposes

keeping in mind that decreasing the flue gas temperature will increase the sulphuric acid

content and decrease the moisture in fuel or using quality fuel that has low ash content.

This in fact involves various factors such as large investment, economy, environmental

factors, plant layout, etc. So to increase the efficiency of the boilers, we should find the best

practices for decreasing the flue gas loss and reduce the moisture content in fuel.

4.2 Heat Recovery from Flue Gas

The temperature of the flue gas leaving the boiler is commonly reduced in an air preheater

(APH) when the sensible heat in the flue gas leaving the economizer is used to preheat

combustion air. Preheating of combustion air has a significant positive effect on boiler

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efficiency.

Fig. 4.1 Acid dew point temperature as a function of the SO3 and H2O concentration.

Sulphuric acid in the flue gas is formed in gas-phase reactions of SO3 and H2O upstream of

the APH. The SO3 is formed from SO2 by homogeneous and heterogeneous reactions in the

furnace and convection pass of the boiler. The presence of SO3 in the flue gas increases the

dew point of the flue gas. The acid dew point temperature is presented in Fig. 4.2.1 as a

function of the SO3 and H2O concentration in the flue gas. Sulphuric acid condenses as

temperature is decreased bellow the dew point temperature. The condensed sulphuric acid

(acid and water mixture sulphuric acid is hydroscopic) is corrosive to the inexpensive

materials used in construction of the APH heat transfer surfaces and downstream ductwork.

Besides acid deposition, the other impediment to recovering heat from the flue gas by

additional cooling in the APH is the ESP performance.

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Fig.4.2 Ash resistivity versus flue gas temperature for a high-resistivity ash.

The ash samples were taken from the electrostatic precipitator when operating in

descending temperature mode at 7.2% moisture content.

As presented in fig.4.2.2, resistivity of fly ash decreases as the flue gas temperature is

reduced below 300F. However, in case of the high-resistivity ash, the temperature reduction

would not be a problem, for the low-resistivity ash low flue gas temperatures will have a

significant negative effect on the ESP performance.

Un-reacted ammonia combines with SO3 in the flue gas stream and SO3 produced on the SCR

catalysts to form ammonium bisulphate (ABS). The ABS forms in a temperature range

between the APH flue gas inlet and outlet temperatures. The deposits are sticky and corrosive

to steels commonly employed in the APHs.

Upon exiting the ESP, it is common to cool the flue gas by evaporative cooling to a

temperature close to the adiabatic saturation temperature by spraying water into the flue gas

stream within a wet flue gas desulfurization (FGD) system.

According to an FGD manufacturer, the optimal flue gas temperature for a desulfurization

process is approximately 149F (65°C). Cooling of the flue gas to the saturation temperature

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occurs in a spray area, and the flue gas leaves the FGD reactor at a temperature close to the

saturation temperature.

Most of the moisture can be removed from the flue gas by cooling it to a very low

temperature. The chilled ammonia concept, developed by Alstom Power, employs cooling of

the flue gas to a very low temperature using chillers. At the current state of technology

development, such low-temperature cooling of the flue gas is expensive due to high power

requirements for the chillers.

Condensation of the flue gas moisture liberates latent heat. The amount of latent heat released

is a function of the flue gas temperature and coal type. The amount of released latent heat

increases as TM content of the coal increases and temperature of the flue gas decreases. The

latent heat can be recovered in condensing heat exchangers (CXEs), but due to the low

temperature of a cooling fluid, there are practical temperature limits (approximately 100F to

110F) that impose limits on the amount of latent heat than can be economically recovered

from the flue gas. Available

heat sinks limit the amount of low-temperature heat that can be beneficially used.

The total (sensible and latent) heat of the flue gas is presented in fig. 4.2. As the flue gas is

cooled below its saturation temperature, the amount of total heat greatly increases. However,

as discussed previously, there are practical limitations associated with cooling of the flue gas

to low temperatures and beneficial use of the recovered low temperature heat.

Fig. 4.3 Total heat in flue gas as a function of flue gas temperature and coal type.

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4.3 Flue Gas Desulphurisation

One of the most commonly used FGD technologies for scrubbing pollutants from power plant

gas emissions is a limestone forced oxidation (LSFO) scrubber system. In this process, many

pollutants end up in the circulating water in the scrubber. To maintain appropriate operating

conditions, a constant purge stream is discharged from the scrubber system, and the purge

stream contains contaminants from coal, limestone, and make-up water. The purge is acidic

and supersaturated with gypsum, with high concentrations of TDS, TSS, heavy metals,

chlorides and occasionally, dissolved organic compounds.

State and Federal laws regulate the concentration of pollutants in FGD wastewater prior to

discharge to waterways. In some cases (e.g., power plants discharging to large rivers), the

wastewater may be suitable for discharge after minor treatment for suspended solids and pH

adjustment. However, in many cases, the wastewater requires treatment for the reduction of

key contaminants, including suspended solids, COD/BOD, total nitrogen, and selected heavy

metals to very low concentrations. The scrubber purge stream is most often treated in a

dedicated wastewater facility rather than an existing treatment system.

4.3.1 Lime in Flue Gas Desulphurisation

Lime and limestone play a significant role in the removal of pollutants from flue gas streams

of coal-fired power plants, incinerators and industrial facilities. Flue gas desulfurization

(FGD) primarily refers to the removal of sulphur dioxide (SO2). However, lime and limestone

are also used in the removal of other pollutants such as hydrogen chloride (HCl), sulphur

trioxide (SO3), fine particulates and mercury. In the US, air pollution control applications

were the second largest use of lime in 2003, consuming over 3.4 million tons of lime. Lime

and limestone products are used in both wet and dry FGD processes to absorb the sulphur

content.

In the wet FGD processes these products are slurred with water and sprayed into a flue gas

scrubber vessel. The acidic gases, normally SO2 and HCl, are absorbed into the water where

they chemically react with the lime and limestone. The reaction products, primarily calcium

sulphite, can then be oxidized to produce calcium sulphate, saleable gypsum by product.

There are three basic types of dry FGD processes.

Dry injection processes inject dry hydrated lime directly into the flue gas stream.

Spray dryer processes inject finely atomized lime slurry into a separate vessel. Water from

the slurry is evaporated before the solids contact the vessel walls.

Circulating fluidized bed processes inject dry hydrated lime in a separate fluidizing vessel. 33

With all three processes, the acidic gases combine with lime to form a dry product which is

removed from the flue gas stream in particulate control devices such as bag houses or

electrostatic precipitators (ESP's).

Fig. 4.4 Flue gas desulphurisation process4.4 Best Practices for utilising the low-temperature heat from flue gas

4.4.1 Feed water heating and Combustion Air Preheat.

The technology to recover low-temperature heat from flue gas originated in Europe, where it

has been used to improve performance of coal-fired power plants and industrial plants for

more than 15 years. Utility companies such as RWE Power, Vattenfall, and others utilize the

low-temperature heat from flue gas for feed water (FW) heating and preheating of

combustion air.

4.4.2 Flue Gas Reheat by Preheated Air

Cooling of the flue gas upstream to a lower temperature results in lower evaporation within

the FGD and less water makeup. Lower evaporation and less water added to the flue gas

stream result in lower moisture content of the flue gas at the FGD outlet. The flue gas leaving

the FGC with lower temperature, then a larger portion of the FGC operates below the acid

dew point temperature, resulting in increased H2SO4 condensation and increased FGC cost.

4.4.3 Installation of FGC Model

Another approach to reheating, in this reheat arrangement, ambient air is heated in the FGC

and mixed with a saturated flue gas leaving the FGD in a mixing box.

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Advantage- Only one heat exchanger is needed. Flue gas is diluted and flue gas moisture

content is lower compared to a conventional flue gas reheat.

Disadvantage-The air added to the flue gas increases the total flow rate through the stack.

The size of the FGC will be larger compared to the flue gas-to-water design.

Fig. 4.5 FGC Model

4.4.4 Flue Gas Coolers And Condensing Heat Exchangers

Flue Gas Cooler

It is an important piece of equipment which enables recovery of heat from the flue gas. As

the section of the FGC operates below the acid dew point temperature, heat transfer surfaces

need to be constructed from corrosion-resistant materials.

The heat exchanger is built of smooth flouroplastic Teflon (G-Flon) tubes arranged in a U-

tube configuration. A G-Flon foil lining protects the FGC casing against condensing acid. G-

Flon features high resistance to corrosion.

Sulphuric acid condenses on surfaces of the tubes, forming a thin layer of diluted sulphuric

acid that attracts fly ash and forms deposits. Wash water and condensed acid are discharged

into the FGD.

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Fig.4.6 DESIGN OF BBS FLUE GAS COOLER

The gas-to-water WAGAVO exchanger is suitable for applications where HCl and HF

concentration is lower than 15 to 20 mg/m3. In cases where HCl and HF concentration is

higher, enamel glass-lined plus PFA-lined mild steel is recommended.

Advantages

Anti-adhesiveness and resistance against HF and strong mineral acid. Showing that the steel

tube is protected even if one of the layers is damaged.

This type of heat exchangers are practically being used in Logichem Process Engineering,

Krugersdorp, South Africa.

4.4.5 GAGAVO Flue Gas

The gas-to-gas heat exchanger (GAGAVO) with in-line placed plastic tubes in cross flow

arrangement is specifically designed for flue gas reheat. Raw flue gas flows inside the tubes

from top to bottom. All parts are corrosion resistant and made of PTFE, PFA, or nickel-based

alloy.

These heat exchangers are practically being used in REPUBLIKA POWER PLANT,

PERNIK, BULGARIA.

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Fig. 4.6a GAVAVO Flue Gas Cooler by FLUCOREX

Fig. 4.6b Design of GAGAVO Heat Exchanger with PTFE Tubes

A water washing system may be installed at the top of the GAGAVO casing where the water

washing of the inner surface of the plastic tubes removes the deposits. The cleaning system

consists of a stationary or retractable water washing lance with several nozzle groups. The

washing cycle is programmable to meet plant-specific conditions. Use of corrosion-resistant

plastic or alloys increases the cost.

These type of heat exchangers are used practically in FUEL TECH Inc, Illinois, United

States.

4.4.6 Condensing Efficiency

A condensing heat exchanger operates at lower temperature in order to condense moisture

from the flue gas stream. The heat sink temperature imposes a limit on the amount of water

that can be recovered by condensation from a flue gas stream. Condensation efficiency, the

percentage of flue gas moisture condensed out the flue gas stream determined. The results

indicate excellent agreement between the theoretically and experimentally determined values.

Condensation efficiency increases as sink temperature is reduced.

37

Besides the flue gas temperature, condensation efficiency is a strong function of the coal

type, which affects the initial moisture content of the flue gas. The results clearly show that

high-moisture coals are prime candidates for water recovery from the flue gas.

Fig. 4.7 Condensing Efficiency as a Function of Flue Gas Temperature and Coal Type

4.4.7 LDD System

A process of using desiccants to remove moisture from the flue gas has been proposed. The

liquid desiccant dehumidification process involves intimate contact between a liquid

desiccant and flue gas. Dehumidification takes place in the absorber tower, where several

levels of sprays are used to inject liquid desiccant in a counter-current flow to contact the flue

gas. A mist eliminator at the top of the tower is employed to control any entrained desiccant.

Additional development is needed to improve system performance.

A combination of the flue gas condenser and desiccant systems might be a practical option

for recovering water from the flue gas.

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Fig. 4.8 Conceptual Layout of a Proposed Commercial LDD System

4.5 Discussion

The above mentioned heat recovery methods from flue gas are based on the present flue gastemperature obtained from control room during the period of experimentation. Applying anyof these methods will utilize the considerable amount of waste heat from the boiler. Besidethis, the quality of coal is to be monitored. The preferable quality is of higher calorific value,low ash and moisture content. The bi-products of the steel plant such as blast furnace gas andcoke oven gas also has considerable amount of calorific value which help to run the boilerefficiently and should be used to save natural resources even though the coal is the mainsource of heat energy. To decrease the temperature of the flue gas, spraying water is not theonly solution. However it is the most common practice in thermal power plants. Instead ofspraying water, the temperature can also be reduced by using heat exchangers, heating feedwater and using it for drying combustion air. Efficiency calculation should be performedregularly to find the causes for the change in performance of the boilers.The best method for utilizing the flue gas is using condensing water heaters and using it as airpre-heaters. If equipments are pre-installed and are already serving the required quantity thenabove other mentioned low heat recovery methods can be used to utilize the waste heat.

4.6 Conclusion:The key step to enhance the performance of boilers in thermal power plant is the detailedstudy of boiler in the plant and then the efficiency calculation. The efficiency calculation byindirect method is the best way to account all the boiler losses. The flue gas loss is alwayshigher than any other losses. The flue gas loss can be minimized by heat extraction andproper utilization. Moreover when the primary fuel is coal, it should be accounted that it is ofhigher calorific value, low moisture and low ash content. The heat recovery method is doneby observing the amount of flue gas loss, temperature of the flue gas and layout of the plant.When the flue gas loss is reduced and the moisture content in the fuel is low, efficiency of theboiler can be as high as 80 percentReferences:

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1. David Spain, P. E. Nationwide Boiler Inc. Ways to improve efficiency of boilers. 1,September 20102. J. Gladstone Evans & C. Damodaran, Modern Trends In Boilers and EfficiencyImprovement Programmes.

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