Performance Improvement Techniques Ccpp and Fbc Boiler

Arvind Limited, Ahmedabad 1

ABSTRACT

The aim of the project is to improve the performance of Power Plant i.e.

combined cycle power plant for power generation and also improve the FBC boiler

performance.

Now a days CCPP (combined cycle power plant) is the way for power

generation efficiently. In Arvind Ltd., both Ahmedabad & Santej plant have the

same power generation of 24.5 MW is a CCPP cogeneration plant. The Plant is

upgraded to compressed natural gas (CNG) which is replacing Naphtha having its

cost & other benefits. Its performance and cost reduction can further be improved.

Economic and technical considerations for combined-cycle performance

enhancement options further described in this report.

FBC (Fluidized Bed Combustion) Boiler is not used for power generation in

Arvind Limited but is used for steam generation which is used in further chemical

process. Fluidized bed boiler is the newest and cleanest way of generating steam.

The traditional grate fuel firing systems have got limitations and are techno-

economically unviable to meet the challenges of future. Fluidized bed combustion

has emerged as a viable alternative and has significant advantages over conventional

firing system and offers multiple benefits – compact boiler design, fuel flexibility,

higher combustion efficiency and reduced emission of noxious pollutants such as

SOx and NOx It having great efficiency (upto 85%)and is also uses both coal &

biomass. It’s performance and cost reduction can further be improved. Economic

and technical considerations FBC boiler performance enhancement options further

described in this report.


We visited in Arvind Ltd., Naroda Road, Ahmadabad. We have learned many

things about Power Plant generation and how it works. We have also learned the

basics of applications of thermodynamics in Power plant. We shall collect more

information about this Project in future.

Keywords : CCPP,FBC Boiler, CNG, Cost reduction and improve efficiency of

CCPP & FBC.


List of Figures

Fig. No. Figure Title Page

No.

1.4.1.1 Cogeneration (Bottom) Compared with Conventional

Generation (Top)

21

1.4.2.1 Simplified CCPP diagram 24

1.4.2.2

Schematic of Combined Cycle Power Plant (CCGT) 25

2.1.1.1 Simplified Flow Diagram of a Combined Cycle 30

2.1.2.1 Auxiliary Systems in a Gas Turbine Power Plant 33

2.1.4.1 The brayton-Rankine Combined Cycle 38

2.1.5.1 The performance map of a typical combined cycle

power plant

40

2.1.5.2 Comparison of net work output of various cycles’ 40

2.1.5.3 Comparison of thermal efficiency of various cycles’

temperature

41

2.1.6.1 Energy distribution in a combined cycle power plant 44

2.1.6.2 Load sharing between prime movers over the entire

operating range of a combine cycle power plant

45

2.1.6.3 A typical large combined cycle power plant HRSG 46

2.1.7.1 Cost Components of Different Plant Areas in a

Combined Cycle Power Plant

52


2.1.7.2 Plant Life Cycle Cost for a Combined Cycle Power

Plant

53

2.2.2.1 CFBC Power Generation Unit : Working Diagram 56

2.2.3.1 Principle Of Fluidization 59

2.2.3.2 Relation between Gas Velocity and Solid Velocity 60

2.2.4.1 Circulating Bed Boiler Design 62

3.1.2.1.1 Psychometric chart, simplified 70

3.1.2.1.2 Effect of evaporative cooler on available output—85

percent effective

71

3.2.2.1 When Dp Drop Is Less Bed Coarse Partices Settle At

Bottom Of Bed

80

3.2.2.2 Bed Area Reduction To Suit The Reduced Steam

Generation Requirement

81

3.2.2.3 Bed Height & Airbox Instrumentation idle dg bed air-

box dg

82

3.2.2. 4 Bed Material Spillage To Idle Compartment 83

3.2.2. 5 Caustic Gouging Attack In Idle Compartment Tube 84

3.2.2.6 Fuel Line Air Eroding Away Bed Coil In Idle

Compartment fuel

85

3.2.2.7 Fuel Line Air Eroding Away Bed Coil In Idle

Compartment fuel

87


3.2.2.8 Fuel Spillage And Leakage Air In Idle Compartment

Causing Clinkers clinker

88

3.2.2.9 Coarse Particles Settling Around Fuel Nozzle And Pa

Jet Hitting Bed Coil

89

3.2.2.10 Sealing strips from circular dampers 90

3.2.2.11 Improper Power Cylinder Erection Causes Leakage 91

3.2.2.12 Leakage Between Support Frame And Dp Plate 92

3.2.2.13 Failed Air Nozzles Disturb Fluidisation And Cause

Bed Coil Erosion

93

3.2.2.14 Coil Spacing In Hair Pin Type Bed Coils 95

3.2.4.2.1 Effects of Air Temperature on Excess Air Level 103


LIST OF TABELS

Table No. Table Name Page

No.

3.1.2.3.1 Effect on Performance of Power Enhancement

Option on Combined Cycles Compared with the

Base Case

77

3.2.3.1.1 Oxygen content and excess air 97

3.2.4.3.1.1 Burning Characteristics for Fluidized Bed 105

4.1.2.1 Efficiency of Each Components of CCPP 117

4.2.1.1 Principle Losses 119

4.2.2.1 Parameters for Boiler Efficiency Calculation 120

5.1.1.1 Peak Power Enhancement 124

5.1.2 Gas Turbine Upgrade option 126

5.2.1.1.1 Economics : Air-Fuel Ratio Optimization 127

5.2.1.1.2 Traps & Tricks : Air-Fuel Ratio Optimization 127


LIST OF ABBRIVATIONS

Symbol Name Abbreviations

Btu British thermal units

HHV higher heating value

LHV Lower heating value

NOx Nitrogen oxides, (NO2 and NO)

SOx Sulfur oxides, expressed as SO2

Pc Power Co-efficient

CCPP Combined Cycle Power Plant

IGV Inlet Guide Vane

STG Steam Turbine Generator

GTG Gas Turbine Generator

HRSG Heat recovery steam generator

STG Steam Turbine Generator

TDS Total Dissolved Solids

TPH Tons Per Hour

CHP Combined Heat and Power

VAHP Vapour Absorption Heat pump

FBC Fludised Bed Combustion

CFBC Circulating Fludised Bed

Combustion

mw mass flowrate of water in kg/s

mg mass flowrate of fluegases kg/s

Cpw Specific heat of water kj/kg.k

Cpg Specific heat of gases kj/kg.k

Cps Specific heat of steam Kj/Kg.K

ms mass flowrate of steam Kg/s

DCS Distributed Control System


TABLE OF CONTENTS

Acknowledgement 3

Abstract 4

List of Figures 6

List of Tables 9

List of Abbreviations 10

Table of Contents 11

Chapter : 1 Introduction 15

1.1 About Arvind Ltd. 16

1.2 Product Profile

1.3 Project Site Overview 18

1.3.1 Map 1 : Naroda, Ahmedabad

1.3.2 Map 2 : Santej ,Kalol

1.4 Introduction to the Power Plant 20

1.4.1 Meaning of Combined Cycle Cogeneration Power Plant

1.4.2 Combined Cycle Power Plant : Schematic

1.5 Introduction to the FBC boiler 25

1.5.1 Types of Fluidised Bed Combustion Boilers

1.5.2 AFBC

1.5.3 CFBC

1.5.4 PFBC

Chapter: 2 Brief History of the work 29

2.1 Combined Cycle Power Plants 29

2.1.1 The Basics : CCPP

2.1.2 Gas Turbine Power Plant Working : The Auxiliary Systems

2.1.3 Gas Turbine Power Plant Work – The Main Equipment

2.1.4 The Brayton-Rankine Cycle

2.1.5 Summation of Cycle Analysis

2.1.6 A General Overview of Combined Cycle Plants


2.1.7 Cost Components of a combined cycle plant

2.2 Circulating Fluidised Bed Combustion (CFBC) boiler 54

2.2.1 Basics

2.2.2 CFBC Power Generation Unit : Construction with Working Diagram

2.2.3 Mechanism of Fluidised Bed Combustion

2.2.4 Circulating Fluidised Bed Combustion – Working

2.2.5 Characteristics of FBC Boilers:

2.2.6Performance Evaluation of Boilers

2.2.6.1 Thermal efficiency

2.2.6.2 Evaporation ratio

2.2.7 Boiler Water Treatment

Chapter: 3 Expected Outcome 67

3.1 Combined Cycle Power Plant 67

3.1.1 Economic and Technical Considerations for Combined-Cycle

Performance-Enhancement Options :

3.1.2 Output Enhancement

3.1.2.1 Gas Turbine Inlet Air Cooling

3.1.2.2 Power Augmentation

3.1.2.3 Efficiency Enhancement

3.2 Improve Availability and Efficiency of FBC Boilers : 78

3.2.1 Fine Tuning The Fluidised Bed Combustion Boilers :

3.2.2 Tips for Improvement in Operations / Modifications for FBC

Boilers

3.2.3 Energy Efficiency Opportunities In Boilers 96

3.2.3.1 Reduce excess air

3.2.3.2 Minimize stack temperature

3.2.3.3 Feed water preheating from waste heat of stack gases

3.2.3.4 Combustion air preheating from waste heat of stack gases

3.2.3.5 Avoid incomplete combustion

3.2.3.6 Reduce scaling and soot losses


3.2.3.7 Minimize radiation and convection losses

3.2.3.8 Adopt automatic blowdown controls

3.2.3.9 Optimize boiler steam pressure

3.2.3.10 Variable speed control for fans, blowers, and pumps

3.2.3.11 Effect of boilder loading on efficiency

3.2.3.12 Boiler replacement

3.2.4 Approach to Optimum Combustion Control 102

3.2.4.1 Draft Control

3.2.4.3 Optimize The Air-Fuel Ratio

3.2.4.2 Air-Fuel Ratio

3.2.4.3.1 The Optimum Air-Fuel Ratio

3.2.4.3.2 Efficiency Loss from Incorrect Air-Fuel Ratio :

3.2.4.3.3 General Procedure for Adjusting Air-Fuel Ratio :

3.2.4.3.4 Adjust the Air-Fuel Ratio Mechanically :

Chapter 4 Energy Efficiency Calculations 108


4.1.1 Efficiencies of Different Elements of Combined CycIe Power Plant

4.1.2 Summary of Calculations :

4.2 FBC Boiler 118

4.2.1 Indirect method of determining boiler efficiency methodology

4.2.2 Direct method of determining boiler efficiency methodology

4.2.2.1 Calculation for Boiler Efficiency :

Chapter 5 Result Analysis 123


5.1.1 List of Performance Enhancements (Peak Power Enhancement)

5.1.2 Gas Turbine Upgrade

5.2 FBC Boiler 126

5.2.1 Air : Fuel Optimization :

5.2.1.1 Economics


5.2.1.2 Traps & Tricks

5.2.2 Improve Efficiency in Boiler

5.2.2.1 Reduce Excess Air

5.2.2.2 Install an Economizer

5.2.2.3 Install a Condensing Economizer

5.2.2.4 Upgrade Fan Controls

5.2.2.5 Consider Installing a Selective Catalytic Reduction

(SCR) System

5.2.2.6 Perform Proper Water Treatment

5.2.2.7 Reduce Boiler Pressure

5.2.2.8 Consider Boiler Blowdown Heat Recovery

5.2.2.9 Upgrade to a High Turndown Burner and Controls

5.2.2.10 Implement an Energy-Efficiency Program

5.2.3 Tips For Energy Efficiency In Boilers

5.2.4 Cost-Effective Components

5.2.5 General rules (“Rules of Thumb”)

Chapter 6 Conclusion 135


6.2 FBC Boiler 136

Chaper 7 : References 137


7.2 FBC Boiler 138


Chapter : 1 Introduction

1.1 About Arvind Ltd.

The Arvind Mills was set up with the pioneering effort of the Lalbhai rothers in

1931. With the best of technology and business acumen, Arvind has become a true

Indian multinational, having chosen to invest strategically, where demand has been

high and quality required has been superlative. Today, The Arvind Mills Limited is

the flagship company of Rs.20 billion (US$ 500 million) Lalbhai Group.

Arvind Mills has set the pace for changing global customer demands for textiles

and has focused its attention on select core products. Such a focus has enabled the

company to play a dominant role in the global textile arena. With its presence across

the textile value chain, the company endeavors to be a one-stop shop for leading

garment brands.

Fore vision and Technology has brought Arvind to be one of the top three

producers of Denim in the world, and on its way becoming the Global Textile

Conglomerate. Arvind is already making its presence felt in Shirting’s, Knits and

Khakhis fabrics apart from being all set to create ripples in the ready to wear

Garments world over.

Arvind Mills started with a share capital of Rs. 2,525,000 ($55,000) in the year

1931. With the aim of manufacturing the high-end superfine fabrics Arvind invested

in very sophisticated technology. With 52,560 ring spindles, 2552 doubling spindles

and 1122 looms it was one of the few companies in those days to start along with

spinning and weaving facilities in addition to full-fledged facilities for dyeing,

bleaching, finishing and mercerizing. The sales in the year 1934, three years after

establishment were Rs. 45.76 lakhs and profits were Rs. 2.82 lakhs. Steadily

producing high quality fabrics, year after year, Arvind took its place amongst the

foremost textile units in the country.


1.2 Product Profile

In 1997 Arvind set up a state-of-the-art shirting, gabardine and knits facility,

the largest of its kind in India, at Santej. With Arvind’s concern for environment a

most modern affluent treatment facility with zero affluent discharge capability was

also established.

Year 2005 is a watershed year for textiles. With the mulitifiber agreement

getting phased out and the disbanding of quotas, international textile trade is poised

for a quantum leap. In the domestic market too, the rationalizing of the cenvat chain

and the growth of the organized retail industry is likely to make textiles and apparel

see an explosive growth.

Arvind has carved out an aggressive strategy to verticalize its current

operations by setting up world-scale garmenting facilities and offering a one-stop

shop service, of offering garment packages, to its international and domestic

customers.

With the Indian economy poised for rapid growth, Arvind brands with its

international licenses of Lee, Wrangler, Arrow and Tommy Hilfiger and its own

domestic brands of Flying Machine, Newport, Excalibur and Ruf & Tuf, is setting

it’s vision on becoming the largest apparel brands company in India.

List of Products listed below:

Fabric

Denim

Shirtings

Khakis

Knitwear

Voiles

http://en.wikipedia.org/wiki/Textile

http://en.wikipedia.org/wiki/Shirting

http://en.wikipedia.org/wiki/Khaki

http://en.wikipedia.org/wiki/Knitwear

http://en.wikipedia.org/wiki/Voile


Garment Exports

Shirts

Jeans

Arvind Brands (owned)

Flying Machine

Newport

Ruf & Tuf

Excalibur

Arvind Brands (licensed)

Arrow

Lee

Levis

Wrangler

Gant U.S.A.

Sansabelt

Izod

Cherokee

http://en.wikipedia.org/wiki/Garment

http://en.wikipedia.org/wiki/Shirt

http://en.wikipedia.org/wiki/Jeans

http://en.wikipedia.org/w/index.php?title=Arvind_Brands&action=edit&redlink=1

http://en.wikipedia.org/w/index.php?title=Ruf_%26_Tuf&action=edit&redlink=1

http://en.wikipedia.org/w/index.php?title=Arvind_Brands&action=edit&redlink=1

http://en.wikipedia.org/wiki/Lee_(Jeans)

http://en.wikipedia.org/wiki/Wrangler_Jeans

http://en.wikipedia.org/wiki/Gant_U.S.A.

http://en.wikipedia.org/wiki/Sansabelt

http://en.wikipedia.org/wiki/Izod


1.3 Introduction Cogeneration CCPP Power Plant

1.3.1 Map 1: Overview of the Project Site : Naroda Road, Ahmedabad


1.3.2 Map 2: Overview of the Project Site : Santej Road , Kalol,

Gandhinagar


1.4 Introduction to the Power Plant :

1.4.1 Meaning of Combined Cycle Cogeneration Power Plant :

Cogeneration:

Cogeneration is on-site generation and utilization of energy in

different forms simultaneously by utilizing fuel energy at optimum

efficiency in a cost-effective and environmentally responsible way.

Cogeneration systems are of several types and almost all types primarily

generate electricity along with making the best practical use of the heat,

which is an inevitable by-product.

Cogeneration mainly divided into three categories:

(i) Industrial power stations supplying heat to an

industrial process

(ii) District-heating power plants

(iii) Power Plants coupled to seawater desalination

plants

The most prevalent example of cogeneration is the generation of

electric power and heat. The heat may be used for generating steam, hot

water, or for cooling through absorption chillers. In a broad sense, the

system, that produces useful energy in several forms by utilizing the

energy in the fuel such that overall efficiency of the system is very high,

can be classified as Cogeneration System or as a Total Energy System.

The concept is very simple to understand as can be seen from following

points.

Conventional utility power plants utilize the high potential energy

available in the fuels at the end of combustion process to generate

electric power. However, substantial portion of the low-end residual

energy goes to waste by rejection to cooling tower and in the form

of high temperature flue gases.


On the other hand, a cogeneration process utilizes first the high-

end potential energy to generate electric power and then capitalizes

on the low-end residual energy to work for heating process,

equipment or such similar use.

Consider the following scenario. A plant requires 24 units of

electrical energy and 34 units of steam for its processes. If the

electricity requirement is to be met from a centralized power plant

(grid power) and steam from a fuel fired steam boiler, the total fuel

input needed is 100 units. Refer figure-1.4.1 (top)

Fig. 1.4.1.1 Cogeneration (Bottom) Compared with Conventional

Generation (Top)


If the same end use of 24 units of electricity and 34 units of heat, by

opting for the cogeneration route , as in fig 1.4.1 ( bottom), fuel input

requirement would be only 68 units compared to 100 units with

conventional generation. For the industries in need of energy in different

forms such as electricity and steam, (most widely used form of heat

energy), the cogeneration is the right solution due to its viability from

technical, economical as well as environmental angle.

The following two questions describe whole meaning of combined-cycle

power plant:

(iv) What is combined cycle power plant?

(v) Why are combined-cycle plants among the leading

technologies for large power plants?

Combined cycle can be defined as a combination of two thermal

cycles in one Plant. When two cycles are combined, the efficiency that

can be achieved is higher than that of one cycle alone.

Thermal cycles with the same or with different working media

can be combined; however, a combination of cycles with different

working media is more interesting because their advantages can

complement one another. Normally, when two cycles are combined, the

cycle operating at the higher temperature level is called the topping

cycle.1he waste heat it produces is then used in a second process that

operates at a lower temperature level, and is therefore called the

bottoming cycle.

Careful selection of the working media means that an overall

process can be created, which makes optimum thermodynamic use of the

heat in the upper range of temperatures and returns waste heat to the

environment at the lowest temperature level possible. Normally the

topping and bottoming cycles are coupled in a heat exchanger. The

combination used today for commercial power generation is that of a gas

topping cycle with a water/steam bottoming cycle.


1.4.2. Combined Cycle Power Plant: Schematic

Combined cycle gas turbine power plant is essentially an electrical

power plant in which a gas turbine and a steam turbine are used in

combination to achieve greater efficiency than would be possible

independently. The gas turbine drives an electrical generator while the

gas turbine exhaust is used to produce steam in a heat exchanger (called

a Heat Recovery Steam Generator, HRSG) to supply a steam turbine

whose output provides the means to generate more electricity. If the steam

is used for heat (e.g. heating buildings) then the plant would be referred

to as a cogeneration plant

Figure 1.4.2.1 shows a simplified diagram of CCPP and figure

1.4.2.2 is simple representation of a CCGT system. It demonstrates the

fact that a CCGT system is two heat engines in series. The upper engine

is the gas turbine. The gas turbine exhaust is the input to the lower engine

(a steam turbine). The steam turbine exhausts heat via a steam condenser

to the atmosphere.

The combine cycle efficiency (ƞcc) can be derived by the equation

.


Fig. 1.4.2.1 Simplified CCPP diagram

Equation states that the sum of the individual efficiencies minus the

product of the individual efficiencies equals the combine cycle efficiency.

This simple equation gives significant insight to why combine cycle

systems are successful.


Fig.1.4.2.2 Schematic of Combined Cycle Power Plant (CCGT)

1.5 Introduction to The FBC Boiler:

Fluidized bed combustion (FBC) has emerged as a viable alternative

and has significant advantages over a conventional firing system and

offers multiple benefits – compact boiler design, fuel flexibility, higher

combustion efficiency and reduced emission of noxious pollutants such

as SOx and NOx. The fuels burnt in these boilers include coal, washery


rejects, rice husk, bagasse & other agricultural wastes. The fluidized bed

boilers have a wide capacity range- 0.5 T/hr to over 100 T/hr.

When an evenly distributed air or gas is passed upward through a

finely divided bed of solid particles such as sand supported on a fine

mesh, the particles are undisturbed at low velocity. As air velocity is

gradually increased, a stage is reached when the individual particles are

suspended in the air stream – the bed is called “fluidized”.

With further increase in air velocity, there is bubble formation,

vigorous turbulence, rapid mixing and formation of dense defined bed

surface. The bed of solid particles exhibits the properties of a boiling

liquid and assumes the appearance of a fluid – “bubbling fluidized bed”.

If sand particles in a fluidized state are heated to the ignition

temperatures of coal, and coal is injected continuously into the bed, the

coal will burn rapidly and the bed attains a uniform temperature. The

fluidized bed combustion (FBC) takes place at about 840OC to 950OC.

Since this temperature is much below the ash fusion temperature, melting

of ash and associated problems are avoided.

The lower combustion temperature is achieved because of high

coefficient of heat transfer due to rapid mixing in the fluidized bed and

effective extraction of heat from the bed through in-bed heat transfer

tubes and walls of the bed. The gas velocity is maintained between

minimum fluidization velocity and particle entrainment velocity. This

ensures stable operation of the bed and avoids particle entrainment in the

gas stream.

1.5.1 Types of Fluidised Bed Combustion Boilers

There are three basic types of fluidised bed combustion boilers:

(i) Atmospheric classic Fluidised Bed Combustion

System (AFBC)

(ii) Atmospheric circulating (fast) Fluidised Bed

Combustion system(CFBC)

(iii) Pressurised Fluidised Bed Combustion System

(PFBC)


1.5.2 Atmospheric Fluidized Bed Combustion (AFBC) Boiler

Most operational boiler of this type is of the Atmospheric Fluidized

Bed Combustion.(AFBC). This involves little more than adding a

fluidized bed combustor to a conventional shell boiler. Such systems have

similarly being installed in conjunction with conventional water tube

boiler.

Coal is crushed to a size of 1 – 10 mm depending on the rank of

coal, type of fuel fed to the combustion chamber. The atmospheric air,

which acts as both the fluidization and combustion air, is delivered at a

pressure, after being preheated by the exhaust fuel gases. The in-bed tubes

carrying water generally act as the evaporator. The gaseous products of

combustion pass over the super heater sections of the boiler flowing past

the economizer, the dust collectors and the air pre-heater before being

exhausted to atmosphere.

1.5.3 Pressurized Fluidized Bed Combustion (PFBC) Boiler

In Pressurized Fluidized Bed Combustion (PFBC) type, a

compressor supplies the Forced Draft (FD) air and the combustor is a

pressure vessel. The heat release rate in the bed is proportional to the bed

pressure and hence a deep bed is used to extract large amounts of

heat. This will improve the combustion efficiency and sulphur dioxide

absorption in the bed. The steam is generated in the two tube bundles, one

in the bed and one above it. Hot flue gases drive a power generating gas

turbine. The PFBC system can be used for cogeneration (steam and

electricity) or combined cycle power generation. The combined cycle

operation (gas turbine & steam turbine) improves the overall conversion

efficiency by 5 to 8 percent.

1.5.4 Atmospheric Circulating Fluidized Bed Combustion Boilers

(CFBC)

In a circulating system the bed parameters are maintained to

promote solids elutriation from the bed. They are lifted in a relatively


dilute phase in a solids riser, and a down-comer with a cyclone provides

a return path for the solids. There are no steam generation tubes immersed

in the bed. Generation and super heating of steam takes place in the

convection section, water walls, at the exit of the riser.

CFBC boilers are generally more economical than AFBC boilers

for industrial application requiring more than 75 – 100 T/hr of steam. For

large units, the taller furnace characteristics of CFBC boilers offers better

space utilization, greater fuel particle and sorbent residence time for

efficient combustion and SO2 capture, and easier application of staged

combustion techniques for NOx control than AFBC steam generators.

Chapter: 2 Brief History Of the Work :


2.1 Combined Cycle Power Plants

2.1.1 The Basics : CCPP

First step is the same as the simple cycle gas turbine plant. Burning

of gas, the thrust rotating a gas turbine and the coupled generator

produces Electricity. In the second step the hot gases leaving the gas

turbine passes into boiler to produce steam. This boiler is called the ‘Heat

Recovery Steam Generator (HRSG). The steam then rotates the steam

turbine and coupled generator to produce Electricity. The hot gases leave

the HRSG at around 140 degrees centigrade and are discharged into the

atmosphere. The steam condensing, and water recycling system is the

same as in the steam power plant.

Roughly the steam turbine cycle produces one third of the power

and gas turbine cycle produces two thirds of the power output of the

CCPP. Normally there will be two generators, one driven by the gas

turbine and one driven by the steam turbine. There are also systems with

one generator connected through a single shaft to both the gas turbine and

steam turbine.

Even though this system is having the best efficiency, it has

limitations. The gas turbine can only use Natural gas or high grade oils

like aviation or diesel fuel. Because of this the combined cycle can be

operated only in locations where these fuels are available and cost

effective.


Fig. 2.1.1.1 Simplified Flow Diagram of a Combined Cycle

Developments for gasification of coal and use in the gas turbine are

in advanced stages. Once this is proven, Coal as the main fuel can also be

used in the combined cycle power plant.

2.1.2 Gas Turbine Power Plant Working : The Auxiliary Systems

Gas Turbines are one of the most efficient equipment for converting

fuel energy to mechanical energy. How does a Gas Turbine work? What

are the auxiliary systems for the Gas Turbine? This article explains in

simple terms the working of the Auxiliary Systems in the Gas Turbine

Power Plant.


The three main sections of a Gas Turbine are the Compressor,

Combustor and Turbine. The gas turbine power plant has to work

continuously for long period of time without output and performance

decline. Apart from the main sections there are other important

Auxiliaries systems which are required for operating a Gas Turbine

Power Plant on a long term basis.

Air Intake System

Air Intake System provides clean air into the compressor. During

continuous operation the impurities and dust in the air deposits on the

compressor blades. This reduces the efficiency and output of the plant .

The Air Filter in the Air Intake system prevents this.

A blade cleaning system comprising of a high pressure pump

provides on line cleaning facility for the compressor blades.

The flow of the large amount of air into the compressor creates high

noise levels. A Silencer in the intake duct reduces the noise to acceptable

levels.

Exhaust System

Exhaust system discharges the hot gases to a level which is safe for

the people and the environment. The exhaust gas that leaves the turbine

is around 550 °C. This includes an outlet stack high enough for the safe

discharge of the gases.

Silencer in the outlet stack reduces the noise to acceptable levels.

In Combined Cycle power plants the exhaust system has a ‘diverter

damper’ to change the flow of gases to the Heat Recovery Boilers instead

of the outlet stack.


Starting System

Starting system provides the initial momentum for the Gas Turbine

to reach the operating speed. This is similar to the starter motor of your

car. The gas turbine in a power plant runs at 3000 RPM (for the 50 Hz

grid - 3600 RPM for the 60 Hz grid). During starting the speed has to

reach at least 60 % for the turbine to work on its on inertia. The simple

method is to have a starter motor with a torque converter to bring the

heavy mass of the turbine to the required speed. For large turbines this

means a big capacity motor. The latest trend is to use the generator itself

as the starter motor with suitable electrics. In situations where there is no

other start up power available, like a ship or an off-shore platform or a

remote location, a small diesel or gas engine is used.

Fuel System

The Fuel system prepares a clean fuel for burning in the combustor.

Gas Turbines normally burn Natural gas but can also fire diesel or

distillate fuels. Many Gas Turbines have dual firing capabilities.

A burner system and ignition system with the necessary safety

interlocks are the most important items. A control valve regulates the

amount of fuel burned . A filter prevents entry of any particles that may

clog the burners. Natural gas directly from the wells is scrubbed and

cleaned prior to admission into the turbine. External heaters heat the gas

for better combustion.

For liquid fuels high pressure pumps pump fuel to the pressure

required for fine atomisation of the fuel for burning.

These are the main Auxiliary systems in a Gas Turbine Power Plant.

Many other systems and subsystems also form part of the complex system

required for the operation of the Gas Turbine Power Plant.


Fig 2.1.2.1 Auxiliary Systems in a Gas Turbine Power Plant


2.1.3 Gas Turbine Power Plant Work – The Main Equipment

Gas Turbines are one of the most efficient equipment for converting

fuel energy to mechanical energy. How does a Gas Turbine work? What

are auxiliary systems ? This article explains in simple terms the working

of the main parts of the Gas Turbine.

Gas turbine functions in the same way as the Internal Combustion

engine. It sucks in air from the atmosphere, compresses it. The fuel is

injected and ignited. The gases expand doing work and finally exhausts

outside. The only difference is instead of the reciprocating motion, gas

turbine uses a rotary motion throughout.

The three main sections of the Gas Turbine with details :

Compressor

The compressor sucks in air form the atmosphere and compresses it

to pressures in the range of 15 to 20 bar. The compressor consists of a

number of rows of blades mounted on a shaft. This is something like a

series of fans placed one after the other. The pressurized air from the

first row is further pressurised in the second row and so on. Stationary

vanes between each of the blade rows guide the air flow from one

section to the next section. The shaft is connected and rotates along

with the main gas turbine.


Combustor

This is an annular chamber where the fuel burns and is similar to

the furnace in a boiler. The air from the compressor is the Combustion

air. Burners arranged circumferentially on the annular chamber control

the fuel entry to the chamber. The hot gases in the range of 1400 to

1500°C leave the chamber with high energy levels. The chamber and the

subsequent sections are made of special alloys and designs that can

withstand this high temperature.

Turbine

The turbine does the main work of energy conversion. The turbine

portion also consists of rows of blades fixed to the shaft. Stationary guide

vanes direct the gases to the next set of blades. The kinetic energy of the

hot gases impacting on the blades rotates the blades and the shaft. The

blades and vanes are made of special alloys and designs that can

withstand the very high temperature gas. The exhaust gases then exit to

exhaust system through the diffuser. The gas temperature leaving the

Turbine is in the range of 500 to 550 °C.


The gas turbine shaft connects to the generator to produce electric

power. This is similar to generators used in conventional thermal power

plants.

Performance

More than Fifty percent of the energy converted is used by the

compressor. Only around 35 % of the energy input is available for electric

power generation in the generator. The rest of the energy is lost as heat of

the exhaust gases to the atmosphere.

Three parameters that affect the performance of a of gas turbine are


The pressure of the air leaving the compressor.

The hot gas temperature leaving the Combustion chamber.

The gas temperature of the exhaust gases leaving the turbine.

The above is a simple description of the Gas Turbine. Actually it is

very sophisticated and complex equipment which over the years have

become one of the most reliable mechanical equipment. Used in

Combined Cycle mode gives us the most efficient power plant.

2.1.4 The Brayton-Rankine Cycle

The combination of gas turbine with steam turbine is an attractive

proposal, especially for electric utilities and process industries where

steam is being used. In this cycle as shown in fig 2.5.1, the hot gases from

the turbine exhaust are used in a supplementary fired boiler to produce

superheated steam at high temperatures for a steam turbine.

The computations of the gas turbine are the same as shown for the

simple cycle. The steam turbine calculations are :

Steam generator heat

The combined cycle work is equal to the sum of the net gas

turbine work and the steam turbine work. About one-third to


one-half of the design output is available as energy in the

exhaust gases. The exhaust gas from the turbine is used to

provide heat to the recovery boiler. Thus. this heat must be

credited to the overall cycle. The following equations show the

overall cycle work and thermal efficiency:

Overall cycle work ,

Fig. 2.1.4.1 The brayton-Rankine Combined Cycle


Overall cycle efficiency

This system. as can be seen from Figure 2-27. indicates that

the net work is about the same as one would expect in a steam

injection cycle. but the efficiencies are much higher. The

disadvantages of this system are its high initial cost. However,

just as in the steam injection cycle, the NOx content of its exhaust

remains the same and is dependent on the gas turbine used. This

system is being used widely because of its high efficiency.

2.1.5 Summation of Cycle Analysis

Figure 2.5.21and 2.5.2 gives a good comparison of the effect

of the various cycles on the output work and thermal efficiency.

The curves are drawn for a temperature.

Turbine inlet temperature of 2400°F (1316 °C).which is a

temperature presently being used by manufacturers. The output

work of the regenerative cycle is very similar to the output work

of the simple cycle, and the output work of the regenerative

reheat cycle is very similar to that of the reheat cycle. The most

work per pound of air can be expected from the intercooling,

regenerative reheat cycle


Figure 2.1.5.1 The performance map of a typical combined cycle

power plant

Figure 2.1.5.2 Comparison of net work output of various cycles’


The most effective cycle is the Brayton-Rankine cycle. This cycle has tremendous potential in power plants and in the process industries where steam turbines are in use in many areas. The initial cost of this system is high; however, in most cases where steam turbines are being used this initial cost can be greatly reduced.

Figure 2.1.5.3 Comparison of thermal efficiency of various cycles’

temperature

Regenerative cycles are popular because of the high cost of

fuel. Care should be observed not to indiscriminately attach

regenerators to existing units. The regenerator is most efficient at

low-pressure ratios. Cleansing turbines with abrasive agents may

prove a problem in regenerative units, since the cleansers can get

lodged in the regenerator and cause hot spots.

Water injection, or steam injection systems, is being used extensively

to augment power. Corrosion problems in the compressor diffuser

and combustor have not been found to be major problems. The


increase in work and efficiency with a reduction in NOS makes the

process very attractive. Split shaft cycles are attractive for use in

variable-speed mechanical drives. The off-design characteristics of

such an engine are high efficiency and high torque at low speeds.

2.1.6 A General Overview of Combined Cycle Plants

There are many concepts of the combined cycle. These cycles range

from the simple single pressure cycle, in which the steam for the turbine

is generated at only one pressure, to the triple pressure cycles where the

steam generated for the steam turbine is at three different levels. The

energy flow diagram Figure 2-30 shows the distribution of the entering

energy into its useful component and the energy losses which are

associated with the condenser and the stack losses. This distribution will

vary some with different cycles as the stack losses are decreased with

more efficient multilevel pressure Heat Recovery Steam Generating units

(HRSGs). The distribution in the energy produced by the power

generation sections as a function of the total energy produced is shown in

Figure 2-31. This diagram shows that the load characteristics of each of

the major prime-movers changes drastically with off-design operation.

The gas turbine at design conditions supplies 60% of the total energy

delivered and the steam turbine delivers 40% of the energy while at off-

design conditions (below 50% of the design energy) the gas turbine

delivers 40% of the energy while the steam turbine delivers 40% of the

energy.

To fully understand the various cycles, it is important to define a

few major parameters of the combined cycle. In most combined cycle

applications the gas turbine is the topping cycle and the steam turbine is

the bottoming cycle. The major components that make up a combined


cycle are the gas turbine, the HRSG and the steam turbine as shown in

Figure 2-32 a typical combined cycle power plant with a single pressure

HRSG. Thermal efficiencies of the combined cycles can reach as high as

60%. In the typical combination the gas turbine produces about 60% of

the power and the steam turbine about 40%. Individual unit thermal

efficiencies of the gas turbine and the steam turbine are between 30-40

%. The steam turbine utilizes the energy in the exhaust gas of the gas

turbine as its input energy. The energy transferred to the Heat Recovery

Steam Generator (HRSG) by the gas turbine is usually equivalent to about

the rated output of the gas turbine at design conditions. At off-design

conditions the Inlet Guide Vanes (IGV) are used to regulate the air so as

to maintain a high temperature to the HRSG.


Figure 2.1.6.1 Energy distribution in a combined cycle power plant


Figure 2.1.6.2 Load sharing between prime movers over the entire

operating range of a combine cycle power plant

The HRSG is where the energy from the gas turbine is

transferred to the water to produce steam. There are many different configurations of the HRSG units. Most HRSG units are divided into the same amount of sections as the steam turbine, as seen in Figure 2-32. In most cases, each section of the HRSG has a pre-heater or economizer, an evaporator, and then one or two stages of superheaters. The steam entering the steam turbine is superheated.


Figure 2.1.6.3 A typical large combined cycle power plant HRSG


The condensate entering the HRSG goes through a Deaerator where

the gases from the water or steam are removed. This is important because

high oxygen content can cause corrosion of the piping and the

components which would come into contact with the water/ steam

medium. An oxygen content of about 7 -10 parts per billion (ppb) is

recommended. The condensate is sprayed into the top of the Deaerator,

which is normally placed on the top of the feedwater tank. Deaeration

takes place when the water is sprayed and then heated, thus releasing the

gases that are absorbed in the water/ steam medium. Deaeration must be

done on a continuous basis because air is introduced into the system at

the pump seals and piping flanges since they are under vacuum.

Dearation can be either vacuum or over pressure dearation. Most

systems use vacuum dearation because all the feedwater heating can be

done in the feedwater tank and there is no need for additional heat

exchangers. The healing steam in the vacuum dearation process is a lower

quality steam thus leas ing the steam in the steam cycle for expansion

work through the steam turbine. This increases the output of the steam

turbine and therefore the efficiency of the combined cycle. In the case of

the over pressure dearation, the gases can be exhausted directly to the

atmosphere independently of the condenser evacuation system.

Dearation also takes place in the condenser. The process is similar

to that in the Deaertor. The turbine exhaust steam condenses and collects

in the condenser hotwell while the incondensable hot gases are extracted

by means of evacuation equipment. A steam cushion separates the air and

water so re-absorption of the air cannot take place. Condenser dearation

can be as effector as Lite one in a Deaertor. This could lead to not utilizing

a separate Dearator feedwater tank, and the condensate being fed directly

into the IIRSG from the condenser. The amount of make-up water added


to Lite system is a factor since make-up water is fully saturated with

oxygen. If the amount of make-up water is less than 25 % of the steam

turbine exhaust flow, condenser dearation nay be employed. But in cases

where there is steam extraction for process use and therefore the make-up

water is large, a separate deaerator is needed.

The economizer in the system is used to heat the water Close to its

saturation point. If they are not carefully designed, economizers can

generate steam, thus blocking the flow. To present this from occurring the

feed-water at the outlet is slightly sub-cooled. The difference between the

saturation temperature and the water temperature at the economizer exit

is known as the approach temperature. The approach temperature is kept

as small as possible between 10-20 F (5.5-11 °C). To prevent steaming in

the evaporator it is also useful to install a feedwater control valve

downstream of the economizer, which keeps the pressure high, and

steaming is prevented. Proper routing of the tubes to the drum also

prevents blockage if it occurs in the economizer.

Another important parameter is the temperature difference between

the evaporator outlet temperature on the steams side and on the exhaust

gas side. This difference is known as the pinch point. Ideally, the lower

the pinch point, the more heat recovered, but this calls for more surface

area and. Consequently, increases the back pressure and cost. Also,

excessively low pinch points can mean inadequate steam production if

the exhaust gas is low in energy (low mass flow or low exhaust gas

temperature). General guidelines call for a pinch point of 15-40 F(8 to

22°C). The final choice is obviously based on economic considerations.

The steam turbines in most of the large power plants are at a

minimum divided into two major sections the High Pressure Section (HP)

and the Low Pressure Section (LP). In some plants, the HP section is

further divided into a High Pressure Section and an Intermediate Pressure


Section (IP). The HRSG is also divided into sections corresponding with

the steam turbine. The LP steam turbine's performance is further dictated

by the condenser back pressure, which is a function of the cooling and the

fouling.

The efficiency of the steam section in many of these plants varies

from 30-40%. To ensure that the steam turbine is operating in at efficient

mode, the gas turbine exhaust temperature is maintained user a wide

range of operating conditions. This enables the HRSG to maintain a high

degree of effectiveness over this wide range of operation.

In a combined cycle plant, high steam pressures do not necessarily

convert to a high thermal efficiency for a combined cycle power plant.

Expanding the steam at higher steam pressure causes an increase in the

moisture content at the exit of the steam turbine. The increase in moisture

content creates major erosion and corrosion problems in the later stages

of the turbine. A limit is set at about 10% (90% steam quality) moisture

content.

The advantages for a high steam pressure, is that the mass flow of

the steam is reduced and that the turbine output is also reduced. The lower

steam flow reduces the site of the exhaust steam section of the turbine

thus reducing the site of the exhaust stage blades. The smaller steam flow

also reduces the site of the condenser and the amount of water required

for cooling. It also reduces the site of the steam piping and the valve

dimensions. This all accounts for lower costs especially for power plants

which use the expensive and high-energy consuming air-cooled

condensers.

Increasing the steam temperature at a given steam pressure lowers

the steam output of the steam turbine slightly. This occurs because of two

contradictory effects: first the increase in enthalpy drop, which increases


the output: and second the decrease in now, which causes a loss in steam

turbine output. The second effect is more predominant, which accounts

for the lower steam turbine amount. Lowering the temperature of the

steam also increases the moisture content.

Understanding the design characteristics of the dual or triple

pressure HRSG and its corresponding steam turbine sections (HP, IP, and

LP turbines) is important. Increasing pressure of any section will increase

the work output of the section for the same mass flow. However, at higher

pressure, the mass flow of the steam generated is reduced. This effect is

most significant for the LP Turbine. The pressure in the LP evaporator

should not be below about 45 psia (3.1 Bar) because the enthalpy drop in

the LP steam turbine becomes very small, and the volume flow of the

steam becomes very large thus the size of the LP section becomes large,

with long expensive blading. Increase in the steam temperature brings

substantial improvement in the output. In the dual or triple pressure cycle,

more energy is made available to the LP section if the steam team to the

HP section is raised.

There is a very small increase in the overall cycle efficiency

between a dual pressure cycle and a triple pressure cycle. To maximize

their efficiency, these cycles are operated at high temperatures, and

extracting most heat from the system thus creating relatively low stack

temperatures. This means that in most cases they must he only operated

with natural gas as the fuel, as this fuel contains a very low to no sulfur

content. Users have found that in the presence of even low levels of

sulfur. such as when firing diesel fuel (No. 2 fuel oil) stack temperatures

must be kept above 300F (149 Celsius) to avoid acid gas corrosion. The

increase in efficiency between the dual and triple pressure cycle is due to

the steam being generated at the IP level than the LP level. The HP flow

is slightly less than in the dual pressure cycle because the IP superheater


is at a higher level than the LP superheater, thus removing energy from

the HP section of the HRSG. In a triple pressure cycle the HP and IP

section pressure must be increased together. Moisture at the steam turbine

LP section exhaust plays a governing role. At inlet pressure of about 1500

psia (103.4 Bar), the optimum pressure of the IP section is about 250 psia

(17 Bar). The maximum steam turbine output is clearly definable with the

LI' steam turbine pressure. The effect of the LP pressure also effects the

H RSG surface area, as the surface area increases with the decrease in LP

steam pressure, because less heat exchange increases at the low

temperature end of the HRSG.

2.1.7 Cost Components of a combined cycle plant

The Availability of a power plant is the percent of time the plant is

available to generate power in any given period at its acceptance load.

The Acceptance Load or the Net Established Capacity would be the net

electric power generating capacity of the Power Plant at design or

reference conditions established as result of the Performance Tests

conducted for acceptance of the plant. The actual power produced by the

plant would be corrected to the design or reference conditions and is the

actual net available capacity of the Power Plant. Thus it is necessary to

calculate the effective forced outage hours which are based on the

maximum load the plant can produce in a given time interval when the

plant is unable to produce the power required of it. The effective forced


outage hours is based on the following relationship:

Figure 2.1.7.1 Cost Components of Different Plant Areas in a Combined Cycle Power Plant


Figure 2.1.7.2 Plant Life Cycle Cost for a Combined Cycle Power Plant

The Availability of a plant can now be calculated by the following relationship, which takes into account the stoppage due to both forced and planed outages, as well as the forced effective outage hours:

where ,

PT = Time period (8760 hts/ycar) PM = Planned Maintenance hours FO = Forced Outage Hours EFH = Equivalent forced outage hours

The reliability of the plant is the percentage of time between planed overhauls and is defined as:


Availability and reliability have a very major impact on the plant economy. Reliability is essential in that when the power is needed, it must be there.

2.2 Circulating Fluidised Bed Combustion (CFBC) boiler

2.2.1 Basics

The "CETHAR FLUIDIX" is an Atmospheric Bubbling Fluidised

Bed Combustion (AFBC) Boiler with water cooled, fin welded membrane

wall combustion chamber with under bed fuel feeding system.

FBC in boilers at atmospheric pressure can be particularly useful

for high ash coals, and/or those with variable characteristics. Relatively

coarse particles at around 3 mm size are fed into the combustion chamber.

Two formats are used, bubbling beds (BFBC) and circulating beds

(CFBC).

The boiler is designed for a variety of fuels such as Indian Coal,

Imported Coal, Bio fuels such as Rice husk and Sawdust etc as main fuel

for the generation of steam of high pressure and temperature. FD fan

supplies the required combustion/fluidization air for the boiler. Air is

heated in the air heater and is distributed to the fluidized grid through a

compartmentalized air box. A part of combustion air is tapped from air

heater outlet and further pressurized by a PA fan for pneumatic under bed

fuel feeding.

The distributor plate is fitted with well proven and time tested air

nozzles to distribute the fluidizing air from air box uniformly over the

entire bed. Bed tubes are immersed in the bed to maintain the required

bed temperature.

The fuel from the bunker is fed pneumatically into the bed through

a set of pocket feeder and drag chain feeder and mixing nozzles located


below the bunker. The hot flue gas generated from the combustion

chamber passes through convection superheater, boiler bank tubes,

economizer, airheater and ESP. Furnace draft is maintained by FD and ID

fans. Steam drum, boiler bank, mud drum (if provided), in-bed evaporator

tubes, Down Comers, Riser etc forms part of evaporator system.

There was rapid growth in the coal-fired power generation capacity

using FBC between 1985 and 1995, but it still represents less than 2% of

the world total.

2.2.2 CFBC Power Generation Unit : Construction with Working

Diagram

1. Fuel Input

Fuel and limestone are fed into the combustion chamber of the

boiler while air (Prirnary and secondary) is blown in to “fluidize” the

mixture. The fludized mixture burns at a relatively low temperature and

produces heat. The limestone absorbs sulfur dioxide (SO2), and the low-

burning temperature limits the formation of nitrogen oxide (NOx) -two

gases associated with the combustion of solid fuels.

2. CFB Boiler

Heat from the combustion process boils the water in the water tubes

turning it into high-energy steam. Arnmonia is injected into the boiler

outlet to further reduce NOx emissions.


Figure 2.2.2.1 CFBC Power Generation Unit : Working Diagram


3. Cyclone Collector

The cyclone is used to return ash and unburned fuel to the

combustion chamber for re-burning, making the process more efficient.

4. State-of-the-Art Air Quality Control System

After combustion, lime is injected into the "polishing scrubber" to

capture more of the SO2. A "baghouse” (particulate control device

collects dust particles (particulate matter) that escapes during the

combustion process.

5. Stearn Turbine

The high-pressure steam spins the turbine connected to the

generator, which converts mechanical energy, into electricity.

6. Transmission Lines

The electricity produced from the steam turbine/generator is routed

through substations along transmission lines and delivered to distributed

systems for customer use.

2.2.3 Mechanism of Fluidised Bed Combustion

When an evenly distributed air or gas is passed upward through a

finely divided bed of solid particles such as sand supported on a fine

mesh, the particles are undisturbed at low velocity. As air velocity is

gradually increased, a stage is reached when the individual particles are

suspended in the air stream – the bed is called “fluidized”.

With further increase in air velocity, there is bubble formation,

vigorous turbulence, rapid mixing and formation of dense defined bed

surface. The bed of solid particles exhibits the properties of a boiling

liquid and assumes the appearance of a fluid – “bubbling fluidized bed”.

At higher velocities, bubbles disappear, and particles are blown out


of the bed. Therefore, some amounts of particles have to be recirculated

to maintain a stable system – “circulating fluidised bed”.

This principle of fluidisation is illustrated in Figure 2.2.3.1

Fluidization depends largely on the particle size and the air velocity.

The mean solids velocity increases at a slower rate than does the gas

velocity, as illustrated in Figure 2.2.3.2 The difference between the mean

solid velocity and mean gas velocity is called as slip velocity. Maximum

slip velocity between the solids and the gas is desirable for good heat

transfer and intimate contact.

If sand particles in a fluidized state is heated to the ignition

temperatures of coal, and coal is injected continuously into the bed, the

coal will burn rapidly and bed attains a uniform temperature. The

fluidized bed combustion (FBC) takes place at about 840OC to 950OC.

Since this temperature is much below the ash fusion temperature, melting

of ash and associated problems are avoided.

The lower combustion temperature is achieved because of high

coefficient of heat transfer due to rapid mixing in the fluidized bed and

effective extraction of heat from the bed through in-bed heat transfer

tubes and walls of the bed. The gas velocity is maintained between

minimum fluidisation velocity and particle entrainment velocity. This

ensures stable operation of the bed and avoids particle entrainment in the

gas stream.

Combustion process requires the three “T”s that is Time,

Temperature and Turbulence. In FBC, turbulence is promoted by

fluidisation. Improved mixing generates evenly distributed heat at lower

temperature. Residence time is many times greater than conventional

grate firing. Thus an FBC system releases heat more efficiently at lower

temperatures.

Since limestone is used as particle bed, control of sulfur dioxide and


nitrogen oxide emissions in the combustion chamber is achieved without

any additional control equipment. This is one of the major advantages

over conventional boilers.

Figure 2.2.3.1: Principle of Fluidization

Fixing, bubbling and fast fluidized beds :

As the velocity of a gas flowing through a bed of particles increases,

a value is reaches when the bed fluidises and bubbles form as in a boiling

liquid. At higher velocities the bubbles disappear; and the solids are

rapidly blown out of the bed and must be recycled to maintain a stable

system.


Figure 2.2.3.2 Relation between Gas Velocity and Solid Velocity

2.2.4 Circulating Fluidised Bed Combustion (CFBC) – Working :

Circulating Fluidised Bed Combustion (CFBC) technology has

evolved from conventional bubbling bed combustion as a means to

overcome some of the drawbacks associated with conventional bubbling

bed combustion (see Figure 2.2.4.1).

This CFBC technology utilizes the fluidized bed principle in which

crushed (6 –12 mm size) fuel and limestone are injected into the furnace

or combustor. The particles are suspended in a stream of upwardly

flowing air (60-70% of the total air), which enters the bottom of the

furnace through air distribution nozzles. The fluidising velocity in

circulating beds ranges from 3.7 to 9 m/sec. The balance of combustion

air is admitted above the bottom of the furnace as secondary air. The

combustion takes place at 840-900oC, and the fine particles (<450


microns) are elutriated out of the furnace with flue gas velocity of 4-6

m/s. The particles are then collected by the solids separators and

circulated back into the furnace. Solid recycle is about 50 to 100 kg per

kg of fuel burnt.

There are no steam generation tubes immersed in the bed. The

circulating bed is designed to move a lot more solids out of the furnace

area and to achieve most of the heat transfer outside the combustion zone

- convection section, water walls, and at the exit of the riser. Some

circulating bed units even have external heat exchanges.

The particles circulation provides efficient heat transfer to the

furnace walls and longer residence time for carbon and limestone

utilization. Similar to Pulverized Coal (PC) firing, the controlling

parameters in the CFB combustion process are temperature, residence

time and turbulence.

For large units, the taller furnace characteristics of CFBC boiler

offers better space utilization, greater fuel particle and sorbent residence

time for efficient combustion and SO2 capture, and easier application of

staged combustion techniques for NOx control than AFBC generators.

CFBC boilers are said to achieve better calcium to sulphur utilization –

1.5 to 1 vs. 3.2 to 1 for the AFBC boilers, although the furnace

temperatures are almost the same.

CFBC boilers are generally claimed to be more economical than

AFBC boilers for industrial application requiring more than 75 – 100 T/hr

of steam.

CFBC requires huge mechanical cyclones to capture and recycle the

large amount of bed material, which requires a tall boiler.

Circulating bed boiler

At high fluidizing gas velocities in which a fast recycling bed of

fine material is superimposed on a bubbling bed of larger particles. The


combustion temperature is controlled by rate of recycling of fine material.

Hot fine material is separated from the flue gas by a cyclone and is

partially cooled in a separate low velocity fluidized bed heat exchanger,

where the heat is given up to the steam. The cooler fine material is then

recycled to the dense bed.

Figure 2.2.4.1 Circulating Bed Boiler Design

A CFBC could be good choice if the following conditions are met.

Capacity of boiler is large to medium

Sulphur emission and NOx control is important

The boiler is required to fire low-grade fuel or fuel with highly

fluctuating fuel quality.

Major performance features of the circulating bed system are as

follows:


a) It has a high processing capacity because of the high gas velocity

through the system.

b) The temperature of about 870oC is reasonably constant

throughout the process because of the high turbulence and circulation of

solids. The low combustion temperature also results in minimal NOx

formation.

c) Sulfur present in the fuel is retained in the circulating solids in

the form of calcium sulphate and removed in solid form. The use of

limestone or dolomite sorbents allows a higher sulfur retention rate, and

limestone requirements have been demonstrated to be substantially less

than with bubbling bed combustor.

d) The combustion air is supplied at 1.5 to 2 psig rather than 3-5

psig as required by bubbling bed combustors.

e) It has high combustion efficiency.

f) It has a better turndown ratio than bubbling bed systems.

g) Erosion of the heat transfer surface in the combustion chamber is

reduced, since the surface is parallel to the flow. In a bubbling bed system,

the surface generally is perpendicular to the flow.

2.2.5 Characteristics of FBC Boilers:

Combustion takes place at temperatures from 800-900°C.

Bubbling beds use a low fluidizing velocity, so that the particles are

held mainly in a bed which will have a depth of about 1 m, and has a

definable surface. Sand is often used to improve bed stability, together

with limestone for SO2 absorption. As the coal particles are burned away

and become smaller, they are elutriated with the gases, and subsequently

removed as fly ash. In-bed tubes are used to control the bed temperature

and generate steam. The flue gases are normally cleaned using a cyclone,

and then pass through further heat exchangers, raising steam.

Unit size


Atmospheric BFBC is mainly used for boilers up to about 25 MWe,

although there are a few larger plants where it has been used to retrofit an

existing unit.

Thermal efficiency

Overall thermal efficiency is around 30%.

Flue gas cleaning/emissions

Combustion takes place at temperatures from 800-900°C resulting

in reduced NOx formation compared with PCC. Air staging can further

reduce NOx formation. N2O formation is, however, increased. SO2

emissions can be reduced by the injection of sorbent into the bed, and the

subsequent removal of ash together with reacted sorbent. Limestone or

dolomite are commonly used for this purpose. A disadvantage of BFBC

is that in order to remove SO2, a much higher Ca/S ratio is needed than

in atmospheric CFBC. This increases costs, and in particular the cost of

residues disposal.

Residues

The residues consist of the original mineral matter, most of which

does not melt at the combustion temperatures used. Where sorbent is

added for SO2 removal, there will be additional CaO/MgO, CaSO4 and

CaCO3 present. There may be a high free lime content and leachates will

be strongly alkaline. Carbon-in-ash levels are higher in FBC residues that

in those from PCC.


2.2.6 Performance Evaluation of Boilers

The performance of a boiler, which include thermal efficiency and

evaporation ratio (or steam to fuel ratio), deteriorates over time for

reasons that include poor combustion, fouling of heat transfer area, and

inadequacies in operation and maintenance. Even for a new boiler,

deteriorating fuel quality and water quality can result in poor boiler

performance. Boiler efficiency tests help us to calculate deviations of

boiler efficiency from the design value and identify areas for

improvement.

2.2.6.1 Thermal efficiency

Thermal efficiency of a boiler is defined as the percentage of heat

input that is effectively utilized to generate steam. There are two methods

of assessing boiler efficiency: direct and indirect. In the direct method,

the ratio of heat output (heat gain by water to become steam) to heat input

(energy content of fuel) is calculated. In the indirect method, all the heat

losses of a boiler are measured and its efficiency computed by subtracting

the losses from the maximum of 100.

2.2.6.2 Evaporation ratio

Evaporation ratio, or steam to fuel ratio, is another simple,

conventional parameter to track performance of boilers on-day-to-day

basis. For small capacity boilers, direct method can be attempted, but it is

preferable to conduct indirect efficiency evaluation, since an indirect

method permits assessment of all losses and can be a tool for loss

minimization. In the direct method, steam quality measurement poses

uncertainties. Standards can be referred to for computations and

methodology of evaluation. The audit worksheets given in APO’s Energy

Audit Manual can also be used for this purpose.

2.2.7 Boiler Water Treatment


Boiler water treatment is an important area for attention since water

quality has a major influence on the efficiency of a boiler as well as on its

safe operation. The higher the pressure rating, the more stringent the

water quality requirements become. Boiler water quality is continuously

monitored for buildup of total dissolved solids (TDS) and hardness, and

blowdown is carried out (involving heat loss) to limit the same. Boiler

water treatment methods are dependent upon quality limits specified for

TDS and hardness by the manufacturers, the operating pressure of the

boiler, the extent of make-up water used, and the quality of raw water at

the site. For small-capacity and low-pressure boilers, water treatment is

carried out by adding chemicals to the boiler to prevent the formation of

scale, and by converting the scale-forming compounds to free-flowing

sludge, which can be removed by blowdown.

Limitations :

Treatment is applicable to boilers where feed water is low in hardness

salts, where low pressure – high TDS content in boiler water is tolerated,

and where only small quantities of water need to be treated. If these

conditions are not met, then high rates of blowdown are required to

dispose of the sludge, and treatment become uneconomical based on heat

and water loss considerations.

Chemicals Used :

Sodium carbonate, sodium aluminate, sodium phosphate, sodium

sulphite, and

compounds of vegetable or inorganic origin are used for treatment.

Internal treatment alone is not recommended.

Chapter: 3 EXPECTED OUTCOME


3.1 Combined Cycle Power Plant

3.1.1 Economic and Technical Considerations for Combined-Cycle

Performance-Enhancement Options :

The output and efficiency of combined-cycle plants can be

increased during the design phase by selecting the following features:1

Higher steam pressure and temperature

Multiple steam pressure levels

Reheat cycles

Additional factors are considered if there is a need for peak power

production. They include gas turbine power augmentation by water or

steam injection or a supplementary fired heat recovery steam generator

(HRSG). If peak power demands occur on hot summer days, gas turbine

inlet evaporative cooling or chilling should be considered. Fuel heating is

another technique that has been used to increase the efficiency of

combined-cycle plants.

The ability of combined-cycle plants to generate additional power

beyond their base capacity during peak periods has become an important

design consideration. During the last decade, premiums were paid for

power generated during the summer peak periods. The cost of electricity

during the peak periods can be 70 times more expensive than off-peak

periods. Since the cost during the peak periods is much higher, most of

the plant’s profitability could be driven by the amount of power generated

during these peak periods. Thus, plants that can generate large quantities

of power during the peak periods can achieve the highest profits.

3.1.2 OUTPUT ENHANCEMENT


The two major categories of plant output enhancements are (1) gas turbine

inlet air cooling and (2) power augmentation.

3.1.2.1 Gas Turbine Inlet Air Cooling

Industrial gas turbines operating at constant speed have a constant

volumetric flow rate. Since the specific volume of air is directly

proportional to temperature, cooler air has a higher mass flow rate. It

generates more power in the turbine. Cooler air also requires less energy

to be compressed to the same pressure as warmer air. Thus, gas turbines

generate higher power output when the incoming air is cooler.

A gas turbine inlet air cooling system is a good option for

applications where electricity prices increase during the warm months. It

increases the power output by decreasing the temperature of the incoming

air. In combined-cycle applications, it also results in improvement in

thermal efficiency. A decrease in the inlet dry-bulb temperature by 10°F

(5.6°C) will normally result in around 2.7 percent power increase of a

combined cycle using heavy-duty gas turbines. The output of simple-

cycle gas turbines is also increased by the same amount.

The two methods used for reducing the gas turbine inlet temperature

are (1) evaporative cooling and (2) chilling. Evaporative coolers rely on

water evaporation to cool the inlet air to the turbine. Chilling of the inlet

air is normally done by having cold water flowing through a heat

exchanger located in the inlet duct. The wet-bulb temperature limits the

effectiveness of evaporative cooling. However, chilling can reduce the

inlet air temperature below the wet-bulb temperature. This provides

additional output power, albeit at significantly higher costs.

Evaporative Cooling. :

Evaporative cooling is a cost-effective method to increase the

power output of a gas turbine when the ambient temperature is high and

the relative humidity is reasonably low.

Evaporative Cooling Methods. :

There are two methods for providing evaporative cooling.


The first utilizes a wetted-honeycomb type of medium known as an

evaporative cooler. The second is the inlet fogger.

Evaporative Cooling Theory :

Evaporative cooling uses water evaporation to cool the

airstream. Energy is required to convert water from liquid to vapor. This

energy is taken from the airstream. This results in cooler air having higher

humidity. Figure 3.1.2.1.1 illustrates a psychometric chart. It is used to

explore the limitations of evaporative cooling.

In theory, the lowest temperature achieved by adding water to air is

the ambient wet-bulb temperature. In reality, it is difficult to achieve this

level of cooling. The actual temperature achieved depends on both the

equipment design and atmospheric conditions. The evaporative cooler

effectiveness depends on the surface area of the water exposed to the

airstream and the residence time.

The cooler effectiveness is defined as:

The typical effectiveness of a cooler is between 85 and 95 percent.

If the effectiveness is 85 percent, the temperature drop will be


Fig 3.1.2.1.1 Psychometric chart, simplified

For example, assume that the ambient temperature is 100°F

(37.8°C) and the relative humidity is 32 percent. The cooling process is

illustrated on the psychometric chart (Fig. 3.1.2.1.1). It follows a

constant-enthalpy line as sensible heat is exchanged for latent heat of

evaporation. The corresponding wet-bulb temperature is 75°F (23.9°C).

The drop in temperature through the cooler is then 0.85 (100 – 75), or

21°F (11.7°C). Thus, the compressor inlet temperature is 79°F (26°C).

The effectiveness of an evaporative cooler is normally around 85 percent

and of the foggers is between 90 and 95 percent. The actual increase in


power from the gas turbine as a result of air cooling depends on the design

of the machine, site altitude, as well as ambient temperature and humidity.

However, the information provided in Fig. 3.1.2.1.2 can be used to

make an estimate of the effect of evaporative coolers. The highest

improvement is achieved in hot, dry weather.

Fig 3.1.2.1.2 Effect of evaporative cooler on available output—85

percent effective

Wetted-Honeycomb Evaporative Coolers :

Conventional evaporative coolers use a wettedhoneycomb-

like medium to maximize the evaporative surface area and the cooling

effectiveness.

The medium used for gas turbines is typically _12 in thick .A

controller is provided to prevent operation of the evaporative cooler

system below60°F (15.6°C). Icing could form if the system is allowed to


operate below this temperature. The whole system must be deactivated

and drained to avoid damage to the water tank and piping if the ambient

temperature is expected to fall below freezing.

Water Requirements for Evaporative Coolers :

Evaporative coolers have the highest effectiveness in arid regions

where water has a higher concentration of dissolved solids. As water

evaporates and makeup water enters the tank, the amount of minerals

present in the tank will increase. These minerals would precipitate out on

the media, reducing the rate of evaporation. The hazard of having

minerals getting entrained with the air entering the gas turbine will also

increase. This hazard is minimized by continuously bleeding down the

tank to reduce the concentration of minerals. This is known as blowdown.

Water is added as makeup for evaporation and blowdown. The rate of

evaporation depends on the ambient temperature and humidity, altitude,

cooler effectiveness, and airflow through the gas turbine.

Foggers :

These systems atomize the supply of water into billions of tiny

droplets. The size of the droplets plays an important role in determining

the surface area of water exposed to the airstream and, therefore, to the

speed of evaporation. For example, water atomized into 10-_m droplets

produces 10 times more surface area than the same amount atomized to

100-_m droplets.

Demineralized water is used to reduce compressor fouling or nozzle

plugging. However, it necessitates the use of a high-grade stainless steel

for all wetted parts.

Two methods are used for water atomization. The first relies on

compressor air in the nozzles to atomize the water. The second uses a

high-pressure pump to force the water through a small orifice

Evaporative Intercooling :


Evaporative intercooling, also known as overspray or overcooling,

consists of additional injection of fog into the inlet airstream beyond what

can be evaporated by a given ambient climate condition. Non-evaporated

fog droplets are carried into the airstream entering the compressor. The

higher temperatures in the compressor evaporate the droplets. This cools

the air and makes it denser, resulting in a decrease in the relative work of

the compressor and an increase in the total mass flow of the air. The

output power of the machine will increase. The power increase obtained

from fog intercooling is higher than the amount obtained from a

conventional evaporative cooling system. The only

possible drawback of intercooling is that if the water droplets are too

large, erosion of the compressor blade will occur due to liquid impaction.

Intercooling is also done by fog-spraying atomized water between

compressor sections. The atomization is done using high-pressure air

taken from the eighth-stage bleed. The water injection reduces the outlet

temperature of the compressor significantly, resulting in higher output

and better efficiency.

Inlet Chilling :

The two types of inlet chilling systems are (1) direct chillers and

(2) thermal storage. Liquefied natural gas (LNG) systems use the cooling

generated by the vaporization of liquefied gas in the fuel supply. Thermal

storage systems use off-peak power to store thermal energy in the form

of ice. During peak power periods, the ice is used to perform inlet chilling.

Direct chilling systems use mechanical or absorption chillers. All these

options can be installed in new plants or retrofitted in older plants.

The chilling achieved by using cooling coils depends on the design

of the equipment and ambient conditions. Unlike evaporative coolers,

cooling coils are capable of lowering the temperature below the wet-bulb

temperature. The capacity of the inlet chilling device, the compressor’s

acceptable temperature and humidity limits, and the effectiveness of the

coils limit the actual reduction in temperature.

Inlet Chilling Methods :


Direct cooling provides an almost instantaneous power increase

by cooling the air at the inlet to the gas turbine. Large mechanical chillers

driven by electricity are used with heat exchangers (chiller coils) in the

inlet to the gas turbine. The pressure drop across these heat exchangers is

around 1 in of water. Absorption chillers are also

used if waste heat is available. The air temperature at the inlet to the gas

turbine can be reduced to 45°F (7.2°C). The net gain of mechanical

chillers is lower than absorption systems due to their high electrical

consumption.

Direct cooling is accomplished by two methods: (1) direct-

expansion and (2) chilled-water systems. Direct-expansion systems use a

refrigerant in the cooling coil installed in the inlet air duct. Chilled-water

systems use water or a mixture of water and glycol as a secondary

heating fluid between the refrigerant and the air entering the gas turbine.

It should be noted that these systems provide the maximum benefit on the

hottest days. Their benefit decreases as ambient temperature is reduced.

Also, these systems reduce the power output when the temperature drops

below 45°F (7.2°C) due to an increase in pressure drop at the inlet to the

gas turbine.

Off-Peak Thermal Energy Storage :

Off-peak thermal energy storage is used where the cost of electricity

during daytime peak periods is very high. Ice or cold water is produced

during off-peak hours and weekends by mechanical chillers and stored in

large tanks. The power increase lasts for a few hours each day. The inlet

air to the gas turbine is chilled during periods of peak power demand by

the melted ice or cold water. The gas turbine inlet air temperature is

reduced to between 50 and 60°F by this system. However, large storage

space is required for ice or cold water.

Gas Vaporizers of Liquefied Petroleum Gases :

Liquefied petroleum gases (LPGs) should be vaporized before use

in gas turbines. They are normally delivered at 50°F (10°C) to the gas


turbine. The inlet air can provide the heat needed to vaporize the liquid

fuel. Glycol is used as an intermediate fluid. The inlet air to the gas

turbine heats the glycol. Its temperature drops during this process. The

glycol heats the fuel. The typical drop in inlet air temperature is 10°F

(5.6°C). Thus, the energy in the incoming air to the gas turbine is used in

a useful manner.

3.1.2.2 Power Augmentation

The three methods used for power augmentation are: (1) water or

steam injection, (2) HRSG supplementary firing, and (3) peak firing.

Gas Turbine Steam or Water Injection :

The steam or water injection into the combustors for nitric oxide

(NOX) control increases the mass flow of the air, resulting in increased

power output. The amount of steam or water injected is normally limited

by the amount required to control NOX. This is done to minimize the

operating and maintenance costs and impact on inspection intervals. The

steam injected is normally mixed with the fuel entering the combustors.

It can also be injected into the compressor discharge casing of the gas

turbine.

In combined-cycle applications, the heat rate increases with steam

or water injection. The reasons for this change are

For water injection. Significant amount of heat is required to

vaporize the water.

For steam injection. Steam is taken from the bottoming cycle

(HRSG/steam turbine) to be injected in the gas turbine. This reduces

the efficiency of the steam cycle.

Most machines allow up to 5 percent of the compressor airflow for

steam injection. The steam must have at least 50°F (28°C) superheat and

be at a similar pressure to the fuel gas. Most control systems allow only

the steam flow required until the unit is fully loaded. At this stage,

additional steam or water is admitted for further increase in power.


Supplementary-Fired HRSG :

Since only a small percentage of the air entering the gas turbine

participates in the combustion process, the oxygen concentration in the

discharge of the gas turbine allows supplementary firing in the HRSG.

The definition of a supplementary-fired unit is an HRSG fired to an

average temperature of, not exceeding, about 1800°F (982°C).

Supplementary-fired HRSGs are installed in new units. However, it is not

practical to retrofit them on existing installations due to the space

requirements of duct burners and significant material changes.

Peak Firing :

Some gas turbines can be operated at a higher firing temperature

than their base rating. This is called peak firing. The output of the simple

cycle and combined cycle will increase. This mode of operation results in

a shorter inspection interval and increased maintenance. Despite this

penalty, operating at higher firing temperatures for short periods is cost-

effective due to the increase in power output.

Output Enhancement Summary :

Several output enhancement methods have been discussed.

Table 3.1.2.2.1 shows the effect on performance for each method on a

day that is 90°F (32.2°C), with 30 percent RH. The capability of each

piece of equipment in the plant, including gas turbine, steam turbine, and

generator, must be reviewed to ensure that the design limits will not be

exceeded. For example, the capability of the generator may be limited on

hot days due to inadequate cooling capability.

3.1.2.3 Efficiency Enhancement

Fuel Heating


Low-grade heat can be used to increase the temperature of gaseous

fuels. These results in increasing the plant efficiency by reducing the

amount of fuel consumed to increase the fuel temperature to the

combustion temperature. This method has minimal impact on the output

of gas turbines. However, it results in a limited reduction in the output of

combined cycles due to using energy to heat the fuel rather than for steam

production. The temperature of the fuel can be increased up to 700°F

(370°C) if the fuel constituents are acceptable, before carbon deposits

start to form on heat transfer surfaces and the remainder of the fuel

delivery system. Fuel temperatures of between 300 and 450°F (150 and

230°C) are considered economically optimal for combined-cycle

application. A typical gain in efficiency for a large combined cycle plant

is around 0.3.

Table 3.1.2.3.1 Effect on Performance of Power Enhancement

Option on Combined Cycles Compared with the Base Case

It is important to prevent the fuel from entering the steam system

because the temperature of the steam is normally higher than the auto-

ignition temperature of gas fuels. This can be accomplished by

implementing the following modifications:


Maintaining the water pressure above the fuel pressure in direct

fuel-to-steam heat exchangers to ensure that any leakage will occur

into the fuel system.

Design and operational requirements to prevent the fuel from

entering the steam system when the steam pressure is low.

Using an intermediate heat transport fluid so that any leak in the

fuel heat exchanger will not affect the steam system.

3.2 Improve Availability and Efficiency of FBC Boilers :

Basic boiler design has the largest impact on the system’s efficiency

and maintenance costs. First cost is a relatively small portion of

investment in a boiler. Energy costs might represent 70-80 percent of the

annual operating cost of boiler systems and 30-50 percent of the life-cycle

cost.

Since a boiler’s capital cost is a major component of its life-cycle

cost, deferred maintenance that shortens equipment life hurts the bottom

line. A typical boiler uses many times the initial capital expenditure in

fuel annually, so to maximize the boiler investment, managers need to

specify the most efficient boiler for the application.

Among the replacement options are converting steam to hot-water

boiler systems, using non-condensing type boilers and water heaters, and

using condensing type boilers and water heaters.

An efficiency increase of 11-15 percent is possible when comparing

condensing equipment with non-condensing equipment. Managers can

easily address the creation of sulfuric acid in flue gases by using stainless

steel for flue piping and by collecting and draining condensate. Doing so

can result in efficiencies of greater than 95 percent.

3.2.1 Fine Tuning The Fluidised Bed Combustion Boilers :


The design of Fluidised bed combustion boiler has lot to do with the

fuel type and the fuel conditions. The fuel itself may change since the

purchase of the boiler. A design based on certain fuel / fuel combinations

is not at its optimum when it comes to other fuels. This is specifically true

when the boiler is changed from agro fuels to coal. Similarly change in

operating loads may also warrant fine tuning of the boiler operational

parameters. There are cases where the boiler is specifically oversized

considering the future expansion. In such a case the bed area and bed coil

area may have to be covered up until the steam requirement increases.

The air requirement and flue gas to be handled becomes less. Use of VFD

/ use of smaller capacity fans would benefit the user in terms of power

saving and operational efficiency. Like this there are lot of possibilities

for a review of the original design to present operating conditions.

3.2.2 Tips for Improvement in Operations / Modifications for FBC

Boilers :

In the following pages the tips are explained with illustrations as

necessary. The tips are based in the operational experience of several

make of FBC boilers in India. Some of the tips would certainly benefit

some boiler users. In the continual improvement of the design / Operation

of the FBC boilers there is always scope for additions to this list.

TIP 1 –Measure and maintain adequate Distributor plate drop

The quality of fluidisation should be good ensuring there are no

defluidised zones. This cannot be ensured by visual means. The

distributor plate pressure drop becomes a vital factor to ensure this. When

the DP drop is less than 75 mmWC, the coarse particles begin to settle

down at the bed bottom. In an ideal case, DP drop should be 1/3 rd of bed

height. Defluidization or settlement of coarse particles will not be visible


from top of the bed, as the fine bed material would continue to fluidise.

Settling of coarse particles can also damage bed coils. This leads to

localised erosion of bed tubes. This can happen even in overfed FBC

boilers. Providing studs does not help. Bed coil erosion continues. See

figure 3.2.2.1

Fig. 3.2.2.1 When Dp Drop Is Less Bed Coarse Partices Settle At

Bottom Of Bed

TIP 2 – Check bed coil pitch for studded bed coils

Studs can increase protection against gross erosion but not localised

erosion. Studs decrease the clearance between adjacent bed coils. Spacing

of coils is to be specially addressed if studding is opted for. The Increased

fluidisation velocity at narrow clearances decreases the life of the bed

coils.


TIP 3- Consider reduction of bed size

When the steam demand is less, the bed area becomes oversized.

Maintaining a minimum pressure drop for fluidisation would be difficult.

The boiler operators continue to maintain high excess air level to avoid

bed slumping. In many process boilers this is the case due to oversized

boiler (planned considering future steam requirement) See figure 3.2.2.2.

It is necessary to reduce the bed area by blocking nozzles and by

construction of refractory walls.

Fig. 3.2.2.2 Bed Area Reduction To Suit The Reduced Steam

Generation Requirement

TIP 4 - Inadequate instrumentation

Some manufacturers do not provide draft gauges / manometers for

indication of bed pressure. In such cases, the operators do not get an idea

on bed height. Knowing air box pressure alone does not tell what the bed

height is. It may be possible that fluidising air is more and the bed height


is less. More fluidising air leads to excess air operation. This affects the

bed coil life. See figure 3.2.2.3.

Fig. 3.2.2.3 Bed Height & Airbox Instrumentationidledgbedairboxdg

TIP 5 - Care of idle bed

At times it may be necessary to reduce the steam production rate.

This is done by slumping compartments. Continued operation of slumped

bed may result in shallow bed height in the operating compartment and

leads to defluidization. This happens particularly when bed size is

smaller. The bed height in operating bed becomes less when it spills to

adjacent slumped compartment. See figure 3.2.2.4. It becomes necessary

to alternately activate the slumped bed to bring the bed height back to

normal. There are other reasons as well. See the further tips.


Fig 3.2.2.4 Bed Material Spillage To Idle Compartment

TIP 6 Provide additional drain points

Heavy stones and heavy ash particles keep accumulating at the

bottom of bed. Larger beds need more ash drain points in order to ensure

coarse ash particles, which settle at the bottom can be effectively

removed. If drain points are inadequate or if all the available drain points

are not used, small clinkers would form and grow big. The ash draining

will be effective in open bottom fluidised beds. The ash draining must be

kept partially opened to allow gradual discharge of ash from the bed. This

way it is found to remove most of the coarse particles that settle at the

bottom.

In overbed feeding arrangement coarser particles would settle near

fuel feed points. Provide additional ash drain points at these locations to

remove the stones / heavy particles.


TIP 7- Care for idle bed

Slumping of the bed is done to meet the steam demand. It is not

correct to keep same compartment under slumped condition. In the

slumped bed heat transfer to bed coil becomes less. The circulation of

water ceases. This may result in high pH corrosion / caustic gouging/

settling of iron oxides / corrosion products in such bed coils, depending

on boiler water chemistry. See figure 3.2.2.5, for appearance of tube

inside on a caustic gouging failure.

Fig. 3.2.2.5 Caustic Gouging Attack In Idle Compartment Tube

TIP -8 Use Optimum primary air pressure

Primary air fans are required for underfeed system. The PA fans are

selected with 15% - 25 % flow margins. It is necessary to keep the PA

header pressure as low as possible so that the suction effect is just the

minimum at the throat. The air leakage from the feeder must be taken as


a guide. Higher PA header pressure leads to more air flow through the

fuel feed points. Higher air flow would erode the bed coils faster. It

addition venturi erosion would be faster.

TIP 9 – Care for shutting PA damper in idle bed

In underbed feeding arrangements there is no physical partition

above the distributor plate. When a compartment is slumped for load

control, particularly for longer duration, it is necessary to close the PA

damper in slumped compartments. Leaving the primary air full open in

idle compartment would lead to bed coil erosion. It is the tendency of

many operators to leave open the PA line dampers, for the fear of line

choking. The bed material is continuously thrown at bed coil.

Fig. 3.2.2.6 Fuel Line Air Eroding Away Bed Coil In Idle Compartment

fuel


TIP 10 – Replace the Worn-out venturi / mixing nozzles promptly

In underfeed arrangement the fuel is fed from bottom of the bed. As

the pressure at the feed point inside the bed is 400 -500 mmWC, high

pressure PA fan with mixing nozzles are used to transport the fuel inside.

The air jet velocity at the throat of the mixing nozzle is of the order of

100 – 130 m/s. The fuel particles are accelerated at the mixing chamber

and the diffuser ensures the gradual return to normal line velocity. The

diffuser erodes over a period (1-2 year). As the pressure drop of mixing

nozzle increases more and more air is required for generating suction at

the throat. Naturally the erosion rate of bed coil will be more inside the

bed.

TIP 11- Care to use the air vent valve in idle compartment

Slumping of a compartment is necessary to take care of load

reduction and while start up of the combustor. There can be clinker

formation if the fuel spillage is present in the idle compartment. In certain

boilers, the fuel feed point may be close to the border of the adjacent

compartment. For the clinker to take place there should be air flow in the

idle compartment. The compartment dampers may not be leak proof. For

this reason, automatic air vent valves are provided in compartment air

box, to enable venting the passing air from compartment damper. If the

valves are to be manually operated, the same must be done. Needless to

say, that the leaky damper will have to be attended.


Fig. 3.2.2.7 Fuel Line Air Eroding Away Bed Coil In Idle Compartment

fuel

TIP 10 – Replace the Worn-out venturi / mixing nozzles promptly

In underfeed arrangement the fuel is fed from bottom of the bed. As

the pressure at the feed point inside the bed is 400 -500 mmWC, high

pressure PA fan with mixing nozzles are used to transport the fuel inside.

The air jet velocity at the throat of the mixing nozzle is of the order of

100 – 130 m/s. The fuel particles are accelerated at the mixing chamber

and the diffuser ensures the gradual return to normal line velocity. The

diffuser erodes over a period (1-2 year). As the pressure drop of mixing

nozzle increases more and more air is required for generating suction at

the throat. Naturally the erosion rate of bed coil will be more inside the

bed.


TIP 11- Care to use the air vent valve in idle compartment

Slumping of a compartment is necessary to take care of load

reduction and while startup of the combustor. There can be clinker

formation if the fuel spillage is present in the idle compartment. In certain

boilers, the fuel feed point may be close to the border of the adjacent

compartment. For the clinker to take place there should be air flow in the

idle compartment. The compartment dampers may not be leak proof. For

this reason, automatic air vent valves are provided in compartment air

box, to enable venting the passing air from compartment damper. If the

valves are to be manually operated, the same must be done. Needless to

say, that the leaky damper will have to be attended.

Fig. 3.2.2.8 Fuel Spillage And Leakage Air In Idle Compartment

Causing Clinkersclinker

TIP 12-Avoid continued operation with troubled bed

A fluidised bed may get clinkered when there are disturbances in

boiler operation. For example when there is no coal in bunker, the

operator momentarily reduces the air flow in order to reduce the bed


quenching. At this time, it is likely the bed defludises at some zones. The

average particle size is always high compared to start up bed material and

hence defluidization chances are more when the air flow is reduced. Once

the bed is known to have clinkered, steps are to be taken for immediate

removal. This may be possible by increasing the drain rate from the

clinkered bed. A bed clinkering can be figured out from the differences

between the bottom and top bed temperature readings.

TIP 13- Ensure proper fuel particle size

Improper fuel sizing affects the bed particle size. Improper screen

cloth sizing, coarse particle separation in bunker, worn out crusher

hammers can lead to oversized fuel particles. Oversized fuel particles are

found to accumulate near the fuel feed points leading to defluidization.

The air jets upwards once this happens. Bed coils erode locally above the

fuel feed point at this time. See figure 3.2.2.9.

Fig. 3.2.2.9 Coarse Particles Settling Around Fuel Nozzle And Pa Jet

Hitting Bed Coil

TIP 14 - Attend to Loose air nozzles


Some manufacturers adopt push fit nozzles over the distributor

plate. Further a castable refractory is laid over the plate. The castable gets

broken during service due to thermal expansion. This leads to leakage at

the air nozzle base itself. Such leakages lead to not only bypassing of

more air from such locations, but also lead to defluidised zones. This can

happen near bed ash drain points.

TIP 15 -Leaky compartment dampers

Leaky compartment dampers lead to partial fluidisation. Spilled fuel

from adjacent operating compartment would lead to clinker formation and

further growth. Dampers will need replacement. Butterfly dampers with

proper seals would be the ideal choice to solve the clinker problem. In

ordinary flap type damper sealing strips would help bring down the

leakage. See the figure 3.2.2.10, for the detail of sealing strip which prove

useful.

Fig. 3.2.2.10 Sealing strips from circular dampers

TIP 16- Improper setting of Power cylinder of compartment dampers

Compartment dampers are to be set for closed conditions. At times

it is found that the dampers do not close inside where as the power

cylinder closes fully at the outside. See figure 3.2.2.11, which points out

the defect, which is faced in many cases.


Fig.3.2.2.11 Improper Power Cylinder Erection Causes Leakage

TIP -17 Leaky distributor plates

Some manufacturers adopt removable distributor plate design. This

is adopted for ease of approach during bed coil maintenance. The leakage

between distributor plate and supporting frame would lead to local

fluidisation and keeps making clinkers. When the air bypasses at some

place it is natural at some other location, the bed has settled. See figure

3.2.1.12. If the erection is improper this could be a serious matter

disturbing the fluidised bed operation.


Fig. 3.2.2.12 Leakage Between Support Frame And Dp Plate

TIP -18 Replace all failed air nozzles at one go

Air nozzles may be made from cast iron / stainless steel. The nozzles

begin to oxidise at the top where it receives radiation and convection heat.

Over a period the top opens up. Now the air jets from top hitting the coils

above. Some experience cracking of air nozzles along the top row of

nozzles. Failed air nozzles allow more air flow and hence the air flow

through the good ones would come down (Preferential flow through least

resistance path). This leads to defluidised zones.


Fig. 3.2.2.13 Failed Air Nozzles Disturb Fluidisation And Cause Bed

Coil Erosion

TIP – 19 Do not Operate the boiler with choked PA lines

Primary air lines choke up when oversized fuel is fed or when

compartment damper is opened before operating PA damper. Due to this

the fuel nozzles get distorted. In running boiler no one can guess what the

extent of distortion is. The fuel nozzle cap is distorted the fuel-air mixture

may target the bed coil and lead to premature failure. Distorted nozzles

are to be replaced immediately. SS fuel nozzles offer better protection

when it comes to bed coil life.

TIP 20 -Reduce the chances for start up clinkers

Fluidised beds may be started compartment by compartment. When

the first compartment is started one must ensure that there is a good mount

of bed material to prevent the fuel spillage to adjacent compartment. The

PA pressure should be bare minimum. Excess PA pressure spills more

fuel to adjacent compartment. The PA pressure requirement will be less,

since the bed height will be less during start up. When the fuel spill is

more a border clinker is likely to form. Excess mixing air flow also leads

to more spillage. It is necessary to keep the PA air line dampers of

adjacent compartments in close condition.


TIP 21- More PA and less fluidizing air

By virtue of design / operating load, bed material settles along the

wall side. This leads to throwing of bed material along the wall to the

coils. This happens where fuel feed points are close to wall. When the

frequent load turn downs are expected the bed plate pressure drop has to

be designed for ensuring a minimum bed plate pressure drop of 75

mmWC. Operating at lesser ΔP would lead to pockets of defluidised

zones.

TIP 22 -Bed coil to fuel nozzle clearance

The designer has to ensure a minimum clearance of 150 mm from

fuel nozzle cap top to bed coil to safeguard the bed coil against erosion.

At times due to faulty erection the clearance may be less leading to

premature bed coil failure.

TIP 23 –Check the adequacy of instrumentation of fluidised bed

In the absence of bed temperature indications and air box pressure,

bed pressure, operation of the fluidised bed is risky. When such

instruments are compromised, no one can vouch that the bed is perfectly

OK at all places. It may be possible to assess from the bed material

drained from ash drain pipe. But the same will not be proper for bigger

beds. Failed thermocouples, burnt compensating cables, defective

temperature indicators are to be replaced at the earliest opportunity to

prevent bed coil erosion.

TIP 24- Review Oversized fuel feeders

In some cases, it is likely that the feeders are oversized. A feeder

designed for agro fuel becomes oversized when it comes to changing over

to coal. The fuel feeders are to be replaced with a smaller one or

additional speed reduction mechanism needs to be added. For a small rpm


change the feeder may be dumping excess fuel. The clinker formation

possibility is increased due to this. In the recent years many boiler users

have started using high GCV imported coal. This may also lead to excess

fuel dumping for a small rpm change.

TIP 25- Change the bed coil configuration while replacement

The pitch of the bed coil is a factor for erosion potential. At least

one tube gap must be adopted while selecting the pitch. This is a reason

for bend erosion in closely pitched hairpin type bed coils. Staggered bed

coils would ensure sufficient gap between coils and thus fluidisation

becomes more uniform at entire bed. Cross bed tubes are found to be

better than the hairpin coils. While planning for replacement of bed coils,

consider improvement of bed coil configurations. There are many

possibilities for better configurations considering ease of replacement.

Fig. 3.2.2.14 Coil Spacing In Hair Pin Type Bed Coils


3.2.3 ENERGY EFFICIENCY OPPORTUNITIES IN BOILERS

The various energy efficiency opportunities in boiler systems can

be related to combustion, heat transfer, avoidable losses, high auxiliary

power consumption, water quality, and blowdown, and are discussed

below.

3.2.3.1 Reduce excess air

To minimize escape of heat through flue gases, reducing excess air

(the air quantity over and above the theoretical amount needed for

combustion) is one of the most important methods of improving boiler

efficiency.

Perfect combustion is achieved when all the fuel is burned using

only the theoretical amount of air, but perfect combustion can rarely be

achieved in practice.

Good/complete combustion is achieved when all the fuel is burned

using the minimal amount of excess air (over and above the

theoretical amount of air needed to burn the fuel). Complete

combustion with minimum excess air is always our goal since heat

losses due to high excess air in flue gases are unaffordable and

unacceptable from the point of view of efficiency.

Incomplete combustion occurs when all the fuel is not completely

burned and escapes as CO in flue gases or as unburnts in refuse,

both of which result in higher losses and low efficiency.

Flue gas analysis of combustion is important as it helps to achieve

efficient combustion conditions by excess air control and reduction

of CO in flue gases.

Using gas analyzers, the excess air quantity can be established from

measurement of oxygen or carbon dioxide. Based on oxygen value in flue

gas, excess air is given as:

% of excess air = 100 *% of O2 / (21-% of O2).


The relation between % O2 and flue gas and excess air is illustrated

in Table 2-1. The advantage of oxygen based analysis is that it is the same

for any fuel or fuel combination:

The effort, therefore, should be to operate the boiler with minimum

% O2 in flue gases (excess air), eliminating all avenues of excess air used

for combustion and in the flue gas path.

% O2 % excess air

1 5

2 10.52

3 16.67

4 23.53

5 31.25

6 40

7 50

8 61.7

9 77

10 90.9

11 110

Table 3.2.3.1.1 Oxygen content and excess air

3.2.3.2 Minimize stack temperature

The stack temperature should be as low as possible, since it carries

all the heat from the fuel. However, it should not be so low that water

vapor from exhaust condenses on the stack walls. This is important in

fuels containing significant sulphur, as low temperature can lead to

sulphur dew point corrosion and acid attack effects on metallic parts in

the flue gas path. A stack temperature greater than 200ºC indicates

potential for recovery of waste heat. It also sometimes indicates the

fouling and scaling of heat transfer/recovery equipment. Boiler users

must monitor stack temperature and compare it with design value. When


it has increased over time, maintenance of heat transfer surfaces is called

for. If the design value itself is high, the stack temperature can be reduced

by adopting one of the following waste heat recovery methods.

Waste heat recovery systems are typically shell and tube type heat

exchangers and heat transfer area, and other design features depend on

flow rates, temperature drop considered, etc.

3.2.3.3 Feed water preheating from waste heat of stack gases

Where feasible, adoption of feed water heating, using economizer

from flue gases with economizer application, gives the highest fuel

economy, as one can pre-heat feed water almost up to the saturation

temperature of steam. The economizer is a pressure vessel.

A lower order and cheaper alternative for achieving fuel economy

through flue gas waste heat recovery would be a non-pressurized feed

water heater, which allows feed water pre-heating up to a maximum of

100ºC only. Every rise of 6ºC in boiler feed water temperature through

waste heat recovery would offer about 1% fuel savings.

3.2.3.4 Combustion air preheating from waste heat of stack gases

Combustion air preheating is an alternative to feed water heating,

and can be adopted, if no further scope for feed water pre-heating exists

and where stack gases still have waste heat potential left to be tapped.

Shell and tube type and rotary regenerative type air pre-heaters and

regenerative burners are some of the options that can be adopted for waste

heat recovery.

For every reduction in flue gas temperature by 22ºC for heat

recovery, fuel savings of about 1% can be achieved.

The combustion air pre-heat temperature limiting value is decided

by permissible exit flue gas temperature for avoiding chimney corrosion

on the one hand, and recommended limits of pre-heat temperature by

burner manufacturers on the other.


3.2.3.5 Avoid incomplete combustion

Incomplete combustion can arise from a shortage of air or sulphur

of fuel or poor distribution of fuel. It is usually obvious from the color or

smoke, and must be corrected immediately. In the case of oil and gas-

fired systems, CO or smoke (for oil-fired system only) with normal and

high excess air indicates burner system problems like poor mixing of fuel

air at the burner. Incomplete combustion can result from high viscosity,

worn burner tips, carbonization on burner tips, and deterioration of

diffusers or spinner plates.

With coal firing, unburnt carbon can escape through fly ash or

bottom ash and can lead to 2% to 3% heat loss. Coal preparation, sizing,

and air supply should be looked into, in order to avoid this loss.

3.2.3.6 Reduce scaling and soot losses

In oil and coal-fired boilers, soot buildup on tubes acts as an

insulator against heat transfer. Any such deposits should be removed on

a regular basis. Elevated stack temperatures may indicate excessive soot

buildup. The same result will also occur due to scaling on the water side.

High exit gas temperatures at normal excess air indicate poor heat transfer

performance.

This condition can result from a gradual build-up of gas-side or

water-side deposits. Water-side deposits require a review of water

treatment procedures and tube cleaning, to remove the deposits. Incorrect

water treatment, poor combustion, and poor cleaning schedules can easily

reduce overall thermal efficiency. However, the additional cost of

maintenance and cleaning must be taken into consideration when

assessing savings.

Every millimeter thickness of soot coating increases the stack

temperature by about 55ºC. A deposit of 3mm of soot can cause an

increase in fuel consumption by 2.5%. A 1mm thick scale (deposit) on

the water side could increase fuel consumption by 5% to 8%.


Stack temperature should be checked and recorded regularly as an

indicator of soot deposits and soot removal frequencies decided by trends

of temperature rise of flue gas. Fire-side (fuel additives) and water-side

additives may be judiciously adopted where justified.

3.2.3.7 Minimize radiation and convection losses

The boiler’s exposed surfaces lose heat to the surroundings

depending on the surface area and the difference in temperature between

the surface and the surroundings. The heat loss from the boiler shell is

normally assumed as fixed

energy loss, irrespective of the boiler output. With modern boiler

designs, this may represent only 1.5% of the gross calorific value at full

rating, but it will increase to around 6% if the boiler operates at only 25%

output. Repairing or augmenting insulation can reduce heat loss through

boiler walls.

3.2.3.8 Adopt automatic blowdown controls

As a first choice, ensure maximum condensate recovery, since

condensate is the purest form of water, and this would help reduce

dependence on make-up water and also blowdown requirements.

Uncontrolled, continuous blowdown is very wasteful. For optimizing

blowdown, automatic controls can be installed, which can sense and

respond to boiler water conductivity and pH. Relate blowdown to TDS

limits/Conductivity of boiler and feed water TDS/Conductivity, by online

monitoring.

3.2.3.9 Optimize boiler steam pressure

Wherever permissible, operating a boiler at lower steam pressure (a

lower saturated steam temperature, higher latent heat of steam, and a

similar reduction in the temperature of the flue gas temperature) helps to

achieve fuel economy. In some cases, the process demands are not

continuous, and there are periods when the boiler pressure could be


reduced. Pressure could be reduced in stages, and no more than a 20%

reduction should be considered.

Care should be taken that adverse effects, such as an increase in

water carryover from the boiler owing to pressure reduction, do not

negate any potential savings.

3.2.3.10 Variable speed control for fans, blowers, and pumps

Generally, combustion air control in boilers is achieved by throttling

dampers fitted at forced and induced draft fans. Though dampers are a

simple means of control, they are an inefficient means of capacity control

as they lack accuracy, giving poor control characteristics at the top and

bottom of the operating range. If the steam demand characteristic of the

boiler is variable, the possibility of replacing an inefficient damper and

throttling controls by electronic Variable Speed Drives should be

considered for reducing auxiliary

power consumed in boiler fans and pumps.

3.2.3.11 Effect of boilder loading on efficiency

Optimum boiler efficiency occurs at 65%–85% of full load. As the

steam demand falls, so does the value of the mass flow rate of the flue

gases through the tubes. This reduction in flow rate for the available heat

transfer area helps to reduce the exit flue gas temperature by a small

extent, reducing the sensible heat loss. However, at below 50% load, most

combustion appliances need more excess air to burn the fuel completely,

and this would increase the sensible heat loss. Operation of a boiler at low

loading should be avoided.

3.2.3.12 Boiler replacement

If the existing boiler is old and inefficient, not capable of firing

cheaper substitute fuels, over or under-sized for present requirements, not

designed for ideal loading conditions, or not responsive to load changes,

replacement by a more efficient one needs to be explored.


3.2.4 Approach to Optimum Combustion Control

Usually the cause of excessive or deficient combustion is:

1) The Draft

2) Proper Air-Fuel Mix

3.2.4.1 Draft Control

The major cause of boiler losses, both avoidable and unavoidable,

is the boiler draft. Poor draft conditions alters the flame pattern thus

inhibiting the fuel from burning properly and changing the air-fuel ratio.

Insufficient draft prevents adequate air supply for the combustion

process and results in smoky, incomplete combustion.

Excessive draft allows increased volume of air into the boiler

furnace. The larger amount of flue gas moves quickly through the

boiler, allowing less time for heat transfer to the waterside. The

result is that the exit temperature rises and this along with larger

volume of flue gas leaving the stack contributes to the maximum

heat loss.

Ideally the draft conditions which allow the boiler to operate at 2%

to 4% oxygen maintain the maximum combustion efficiency. If the boiler

does not have a forced draft system, excess combustion air cannot be

easily or properly controlled. Strong consideration should be given to

installing a forced draft system under this situation.

Even with a forced draft system, it still may not be feasible to closely

regulate the amount of excess air because of burners that require proper

air-fuel mix.

If it fails to maintain the CO2 levels > 12%, it indicates a worn out

burner or problem with the furnace draft. In these situations, the

manufacturer's representative should be consulted to discuss upgrading

the controls and equipment.


3.2.4.2 Air-Fuel Ratio

The efficiency of the boiler depends on the ability of the burner to

provide the proper air to fuel mixture throughout the firing rate, day in

and day out.

The density of air and gaseous fuels changes with temperature and

pressure, a fact that must be taken into account in controlling the air-to-

fuel ratio. For example, if pressure is fixed, the mass of air flowing in a

duct will decrease when the temperature increases. The controls should

therefore compensate for seasonal temperature variations and, optimally,

for day and night variations too (especially during the spring and fall,

when daily temperature variations are substantial).

Usually the cause of improper Air-Fuel ratio is due to inadequate

tolerance of the burner controls, a faulty burner or improper fuel delivery

other than draft conditions. Often, the burner cannot provide repeatable

air control and sometimes because of controller inconsistency itself, the

burners are permanently set up at high excess air levels. The fact is you

pay substantial dollars every time you fire the unit.

The figure below shows, the effect of air temperature on excess air

in the flue gas can be dramatic.

Fig. 3.2.4.2.1 Effects of Air Temperature on Excess Air Level


If it fails to maintain the CO levels < 400 ppm, it indicates the poor

mixing of fuel and air at the burner. Poor oil fires can result from

improper viscosity, worn tips, carbonization of burner nozzle and

deterioration of diffusers or spinner plates.

3.2.4.3 Optimize The Air-Fuel Ratio

Air-fuel ratio is by far the most important routine adjustment that is

made to boilers. Of all the adjustments that plant operators can make, it

has the greatest influence on efficiency. Furthermore, failure to set the

air-fuel ratio properly can create serious maintenance and environmental

problems.

If there is automatic combustion controls, adjusting the air-fuel ratio

is easy. Using the several methods , measure combustion efficiency while

setting the combustion controls to the optimum air-fuel ratio. The

combustion controls will then maintain this ratio under all load

conditions.

Adjusting the air-fuel ratio is not much more difficult if there have

burners that fire at one or more fixed firing rates. On the other hand,

adjusting modulating burners can be tedious.

The basic steps are described as follows :

3.2.4.3.1 The Optimum Air-Fuel Ratio :

A perfect boiler would use just enough air to burn all the fuel

completely, with no oxygen left over in the flue gas. (The ratio of air to

fuel that achieves this ideal result is called a “stoichiometric mixture” by

chemists and advanced boiler people.) With real boilers, achieving

reasonably complete combustion requires a certain amount of air in

excess of the stoichiometric ratio. The excess air is needed to ensure that

all the fuel comes in contact with sufficient oxygen for complete

combustion within the flame area.

The minimum amount of excess air that is necessary for clean

combustion depends on the type of fuel and on the type of burner.


Burner Characteristics for fluidized bed combustion boilers :

Capacity Range Evolving type , large

Excess Air 2-10

(percent)

Standby low

Loss

Turndown evolving

Ratio

Operating very high

Energy

Maintenance very high

Table 3.2.4.3.1.1 Burning Characteristics for Fluidized Bed :

More excess air is needed for fuels that are heavier and dirtier.

Also, burners in smaller equipment tend to have substantially higher

excess air requirements. Modern, high-efficiency burners minimize the

amount of excess air required. The best modern burners do a much better

job of preparing the fuel for combustion and of bringing the proper

amount of air into the combustion zone. The design of the boiler’s

combustion chamber may also affect the excess air requirement.

The design of the combustion chamber becomes an issue in existing

boilers if you plan to retrofit a new burner.

Determine the optimum air-fuel ratio for each of your boilers

individually, using the tests recommended below.


3.2.4.3.2 Efficiency Loss from Incorrect Air-Fuel Ratio :

Efficiency suffers from too much air, and from too little. Efficiency

declines rapidly as the amount of air is reduced below the point of best

efficiency. Efficiency declines much more slowly above the point of best

efficiency. This is because insufficient air and excess

air waste energy in two different ways. With insufficient air, efficiency

falls primarily because combustion is incomplete. The incompletely

burned portion of the fuel is being thrown away through the flue, taking

along its unused energy. With excess air, the fuel is being burned almost

completely, but a portion of the combustion energy is wasted in heating

the excess air. The heated excess air is carried through the boiler as

useless baggage. Also, mixing the combustion gases with excess air

lowers the temperature of the gases, which reduces heat transfer.

See the effect in the graph of Figure 1 in Measure 1.2.1.

If the amount of excess air is extreme, the large volume of cool air

can quench the combustion process, causing fuel to be burned

incompletely. However, this effect does not become significant until

efficiency has already been lowered drastically by the previous effect.

3.2.4.3.3 General Procedure for Adjusting Air-Fuel Ratio :

Adjusting the air-fuel ratio consists of testing the combustion

efficiency of the boiler and adjusting the air-fuel ratio until you find the

optimum air-fuel ratio. In summary, the test sequence

is:

• Set the air-fuel ratio by using the oxygen test.

• Refine the adjustment by setting carbon monoxide.

3.2.4.3.4 Adjust the Air-Fuel Ratio Mechanically :

If there are no automatic combustion controls available, there is a

need to set the air-fuel ratio by making mechanical adjustments to the

burners or the control linkages. There may be critical adjustments that do

not seem important from their appearance. There is a need of combustion


efficiency tester for this job that provides a continuous, instantaneous

readout.

It helps to have two persons doing this work, especially if the burner

adjustments are not close to the point where the flue gas sample is taken

for the combustion efficiency tests. One person stays at the boiler

breeching with the test equipment and calls out the readings, while the

other person adjusts the burner.

Try to hold the boiler load as steady as possible during the

adjustments. If the burner operates at different firing rates, you may have

to set the air-fuel ratio for each firing rate at different times, as the load

changes. If the load on the boiler plant is light, it is practically impossible

to set the fuel-air ratio for high firing rates. Do not create a load by

warming up a cold boiler, because this would produce erroneous

efficiency readings and air-fuel settings.

Generally two types of burners are used :

Atmospheric Gas Burners

Modulating Burners


Chapter 4 : Calculations


4.1.1 Efficiencies of Different Elements of Combined CycIe Power Plant

:

GTG Parts:-The following are the parts of the GTG :

1. Starting (Cranking) Motor 2. Torque converter 3. Accessories like gears & gear box 4. Bearing 1 5. Inlet Guide Vane 6. Compressor 7. Bearing 2 8. Combustion Chamber 9. High Pressure turbine 10. Nozzle Control Vane (Element) 11. Bearings 3 12. Low Pressure turbine 13. Load Gear 14. Permanent Magnet type Generator

Gas Turbine Related Specification : Axial Compressor:- No. of Stages of Stator = 19 No. of Stages of Rotor = 17 Rotating Speed = 10,800 rpm Output Pressure of air = 14 ata Turbine of PGT-10:- No. of stages in LP and HP = 2 each Rotating Speed of HP = 10,800 rpm Rotating Speed of LP = 07,900 rpm

Below said calculation are based on current generation pattern of power

plant. Reading is taken from sites as well as DCS.


Compressor Efficiency :

P1 = inlet pressure =1.01325 bar

P2 = outlet pressure = 11.6 bar

T1 = inlet temperature = 22 c = 295 k

T2 = Outlet temperature = 392 c = 665 k , n =1.4

T2’/T1 = (

)

T2’/295 = (

)

T2’ = 592k

Comp. Efficiency =

=

= 0.8027

=80.27%,

Thermal efficiency of GT-1

T3 = Temp. Outlet of combustion chamber = 1080c =1080+273=1353k

T4 =Temp. outlet of Turbine outlet = 490c =499+273 = 772k

P3= Pressure of compressor outlet = 11.6 bar

P3 = Pressure inlet to GT

P4 = Pressure outlet of GT

Pressure loss = 3 %,


= 0.03 * 11.6

=0.348

P3 = 11.6- 0.348

=11.2 52 bar

P4 = 1.01325 + (

)

= 1.0260 bar

n = 1.333=constant of the process

= (

)

=

T4”= 743.5 K

Efficiency of Turbine

Efficiency of turbine =

= ( )

= 0.9532

= 95.32 %


Open cycle efficiency of GT-1

=

=

( )

Mass flow rate of gas = 2250 /hr

C.V. of gas = 8900 Kcal/

Input = (

)

= 26395.54 Kw

Generator output = 7500 Kw

GT Efficiency = (

)

= 0.2842

= 28.42%

Heat Recovery Steam Generator(HRSG):

Pre heater(CPH) Efficiency:

Heat gained by water

Heat rejected by flue gases,


Where,

mw = mass flowrate of water in kg/s mg = mass flowrate of fluegases kg/s

Cpw = Specific heat of water kj/kg.k

Cpg = Specific heat of gases kj/kg.k

= mw * Cpw * (91-35) mg * Cpg * (232-180)

3.61 * 4.2 * (91-35)

42.5 * 1.26 * (232-180)

= 0.32

= 32%

Economiser 1,2 Efficiency :

= Heat gained by water

Heat rejected by flue uses

= mw * Cpw * (206-106)

mg * Cpg * (268-232)

= 3.61 * 4.2 * 100

42.5 * 1.26 * 36

= 0.825

= 82.5%


Evaporator Efficiency :

= Heat gained by water

Heat rejected by flue gases

= mw * Enthalpy drop

mg * Cpg * (232-180)

= 3.61 * (2799-1115.2)

42.5 * 1.26 * (400-268)

= 0.86

= 86%

Superheater Efficiency: Here,

Cps = specific heat of steam Kj/Kg.K ms = mass flowrate of steam Kg/s

= Heat pained by Steam

Heat rejected by flue gases = ms * Cps * (432-253) mg * Cpg * (494-400) = 3.61 * 2.14 * (432-253)

42.5 * 1.2 * (494-400) = 30%


HRSG Efficiency:

= Heat gained by water in HRSG_____ Heat rejected by flue gases in HRSG

= ms * Enthalpy gain of water mg * Cpg * (493-180)

= 3.61 * (3183.06-146.945) 42.5 * 1.26 * (493-180)

= 0.6538

= 65.38%

Steam Turbine Generator(STG) Efficiency:

_ = Total Enthalpy drop in S T G

Workdone by STG

Generator output = 1.4 Mw

Assume Generator Efficiency = 97 % Generator Input = 1.4 / 0.97

=1.44 Mw

Net Mechanical power supplied S T G = 1440 Kw Assume Mechanical Losses = 2 %

Workdone by Turbine = (w)net * 1.02

= 1440 * 1.02

=1468.8Kw


Total Enthalpy drop in STG

= Drop in H.P. stage + Drop in L. P. stage

= 7.30 * (3208.23-3055.15)+ 0.083*(3208.23-2592)

=1118.334 + 51.3525

=1169.6865 Kw

STG Efficiency = 1169.6865 / 1468.8

=0.80

= 80%

GT-1 & HRSG-1 combined Efficiency

Gas flow rate = 2500 /hr

Calorific value of CNG = 8900 kcal/

Heat input = 2500 x 8900 x 4.187 / (3600)

= 25.875 Mw

GT Output =7500 Kw

Here,

h1 = Enthalpy of Steam at 432 C ,43 bar

h2 = Enthalpy of water at 35C, atm

HRSG Output = mw * Enthalpy gain of water

= 3.61 * (h1-h2)

= 3.61*(3183.06-146.945)

= 10960 Kw


Total output = 18460 Kw

Efficiency = 18460 / 25875

= 0.7135

= 71.35%

Overall Plant Efficiency:

= Heat & power output

Heat supplied

Heat supplied = mg * c.v.

= 5000 /hr x 8900 kcal/

= (5000 x 8900 x 4.187) /(3600)

= 51.75 Mw

GT Output = 7.5 x 2 = 15 MW

STG Output = 1.6 Mw

Steam extraction for process work = 20 TPH

Enthalpy of steam supplied to STG at 8 bar & 320 c

Hs = 3089 Kj/Kg

Assume Heat losses = 15%

Heat utilized for process = 20 * 1000 * 3089 * 0.85 / (3600)

= 14.59 Mw

Total Heat Output = 15 + 1.6 + 14.59

= 31.2 Mw

Overall plant Efficiency = 31.2 / 51.75

= 0.603

= 60.3 %


4.1.2 Summary of Calculations :

Elements Name

Input Output Efficiency (%)

Compressor Gas Turbine

Air at 1 ata288k Gas at 11.252bar 1353 k

Air at 11.6 bar 665K Gas at 1.026 bar 772 K

80.27 95.32 Thermal

Gas Turbine 26395.54 Kw Gas 7500 Kw Power 28.42 Open Cycle

Preheater 2784.6 Kw Flue Gases

849.072 Kw Water 82.58

Economiser 1836 Kw Flue Gases

1516.2 Kw Water 82.58

Evaporator 7068.6 Kw Flue Gases

6078.518 Kw Steam

86

Superheater 4794 Kw Flue Gases

1382.85 Kw Steam

30

HRSG 16761.15 Kw Flue Gases

10960.375 Kw Steam

65.38

STG 1468.8 Kw Steam 1169.6865 Kw Power

80

GT + HRSG 25872 Kw CNG 18460 Kw Power + Steam

71.35

Overall Plant 51750 Kw CNG 31200 Kw Power + Steam

60.3

Table 4.1.2.1 Efficiency of Each Components of CCPP


4.2 FBC Boiler

The performance parameters of boiler, like efficiency and

evaporation ratio reduces with time due to poor combustion, heat transfer

surface fouling and poor operation and maintenance. Even for a new

boiler, reasons such as deteriorating fuel quality, water quality etc. can

result in poor boiler performance. Boiler efficiency tests help us to find

out the deviation of boiler efficiency from the best efficiency and target

problem area for corrective action.

Thermal efficiency of boiler is defined as the percentage of heat

input that is effectively utilised to generate steam. There are two methods

of assessing boiler efficiency.

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.

4.2.1 Indirect method of determining boiler efficiency methodology

The reference standards for Boiler Testing at Site using the indirect

method are the British Standard, BS 845:1987 and the USA Standard

ASME PTC-4-1 Power Test Code Steam Generating Units.

The indirect method is also called the heat loss method. The efficiency

can be calculated by subtracting the heat loss fractions from 100 as

follows:


Efficiency of boiler (η) = 100 - (i + ii + iii + iv + v + vi + vii)

Whereby the principle losses that occur in a boiler are loss of heat due to:

i Dry flue gas

ii Evaporation of water formed due to H2 in fuel

iii Evaporation of moisture in fuel

iv Moisture present in combustion air

v Unburnt fuel in fly ash

vi Unburnt fuel in bottom ash

vii Radiation and other unaccounted losses

Table 4.2.1.1 Principle Losses

Losses due to moisture in fuel and due to combustion of hydrogen

are dependent on the fuel, and cannot be controlled by design.

The data required for calculation of boiler efficiency using the

indirect method are:

Ultimate analysis of fuel (H2, O2, S, C, moisture content, ash

content)

Percentage of oxygen or CO2 in the flue gas

Flue gas temperature in (Tf)

Ambient temperature in (Ta) and humidity of air in kg/kg of dry

air

GCV of fuel in kcal/kg

Percentage combustible in ash (in case of solid fuels)

GCV of ash in kcal/kg (in case of solid fuels)

Since, Indirect Methodology for boiler efficiency has not been

calculated here.

4.2.2 Direct method of determining boiler efficiency methodology


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 be evaluated using the

formula:

Boiler Efficiency (η),

Parameters to be monitored for the calculation of boiler efficiency by

direct method are:

Quantity of steam generated per hour (Q) in kg/hr.

Quantity of fuel used per hour (q) in kg/hr.

The working pressure (in kg/cm2(g)) and superheat temperature

( ), if any

The temperature of feed water ( )

Type of fuel and gross calorific value of the fuel (GCV) in kcal/kg

of fuel

And where,

hg – Enthalpy of saturated steam in kcal/kg of steam

hf – Enthalpy of feed water in kcal/kg of water

4.2.2.1 Calculation for Boiler Efficiency :

Find out the efficiency of the boiler by direct method with the data

given below:


Type of boiler Coal fired

Type of Coal Indian Coal / Imported Coal

Quantity of steam (dry) generated 23 TPH

Steam pressure (gauge) 11.5 Kg/ (g) = 11.3 bar

Steam Temperature 200

Quantity of coal consumed 95 Ton / day = 3.95 TPH

Feed water temperature 105 (Hot ) and 57 (Cold)

GCV of Indian coal 4000 Kcal/kg

Enthalpy of steam at 11.3 bar 674.0972 Kcal/Kg

Enthalpy of feed water 105.39 Kcal/Kg (at 105 )

57.30 Kcal/Kg (57 )

Table 4.2.2.1 Parameters for Boiler Efficiency Calculation

Boiler Efficiency (η) at 105 Feed Water,

Boiler Efficiency (η) = 23 * (674.0972-105.39) * 1000 * 100

3.95 * 4000 * 1000

= 82.7864 % ……. (i)

Boiler Efficiency (η) at 57 Feed Water,


Boiler Efficiency (η) = 23 * (674.0972-57.30) * 1000 * 100

3.95 * 4000 * 1000

= 89.7857 % ……….. (ii)

Equation ..(i) and ..(ii) shows , efficiency increases with decrease

in Feed-Water Temperature i.e. cooled feed-water which is processed by

deaerator having higher efficiency than the hot feed-water.

Chapter 5 : Result Analysis



5.1.1 List of Performance Enhancements (Peak Power Enhancement)

Case No. Description: Peak Power Enhancement Method

Case 1 GT Peak Firing (35°F)

Case 2 GT Steam Injection (3.5% of Compressor Inlet Air flow,

CIA)

Case 3 GT Steam Injection (5.0% of Compressor Inlet Air flow,

CIA)

Case 4 GT Peak Firing (35°F) + Steam Injection to 3.5% CIA

Case 5 GT Peak Firing (35°F) + Steam Injection to 5.0% CIA

Case 6 GT Evaporative Cooling (Ambient Relative Humidity-

45%)

Case 7 GT Evaporative Cooling (Ambient Relative Humidity-

60%)-Sensitivity

Case 8 GT Inlet Fogging (Ambient Relative Humidity-45%)

Case 9 GT Inlet Fogging (Ambient Relative Humidity-

60%)Sensitivity

Case 10 GT Inlet Chilling to 45°F (Ambient RH-45%), Chiller with

External Heat Sink.


Cooling Tower Sink


External Heat Sink.


Cooling Tower Sink

Case 14 HRSG Duct Firing-Steam turbine sliding pressure mode of

operation. Fired to approximately 45% increase in HP

steam production.

Case 15 HRSG Duct Firing-Steam turbine fixed-pressure mode of

operation with HP throttle bypass to cold reheats. Fired to

output achieved in Case 14.


Case 16 HRSG Incremental Duct Firing-Firing from nominal

throttle pressure to max HP inlet throttle pressure limit.

Case 17 GT Steam Injection (5.0% CIA) + Incremental HRSG

Duct Firing

Case 18 GT Steam Injection (3.5% CIA) + Incremental HRSG

Duct Firing

Case 19 GT Peak Firing + Steam Injection (5.0% CIA) +

Incremental HRSG Duct Firing

Case 20 GT Steam Injection (3.5% CIA) + Evaporative Cooling

(Amb. RH-45%)

Case 21 GT Steam Injection (3.5% CIA) + Evaporative Cooling

(Amb. RH-45%) + Incremental HRSG Duct Firing.

Case 22 GT Inlet Chilling + GT Steam Injection (3.5% CIA)

Case 23 GT Inlet Chilling + GT Steam Injection (3.5% CIA) +

Incremental HRSG Firing

Case 24 GT Inlet Chilling + GT Steam Injection (5.0% CIA)

Case 25 GT Inlet Fogging + GT Steam Injection (3.5% CIA)

Case 26 GT Water Injection

Case 27 GT Water Injection + Incremental HRSG Duct Firing

Case 28 GT Inlet Fogging-to saturation

Case 29 GT Steam Injection (3.5% CIA) with steam supply taken

from the HP superheat discharge.

Table 5.1.1.1 Peak Power Enhancement

(Note: All other steam injection cases assume steam taken from IP

superheater with the balance made up from the HP superheater.)

GT inlet fogging to saturation is presented for theoretical evaluation

purposes only.


5.1.2 Gas Turbine Upgrade

Comprehensive Upgrades

Comprehensive upgrades of gas turbine involve the replacement of

“flange-to-flange” parts with more advanced designs.

An upgrade can be applied to individual components or to the entire

engine. Examples of components that can be upgraded include:

Inlet guide vanes, which allow more air flow

Improved seals, tighter clearances

Combustion liners and transition pieces, enabling higher firing

temperatures.

Turbine blades and vanes, also enabling higher firing

temperatures

Hot Section Coatings

Another option for upgrading gas turbine performance is to apply

ceramic coatings to internal components. Thermal barrier coatings

(TBCs) are applied to hot section parts in advanced gas turbines. These

same coatings can be applied to the hot sections of older gas turbines in

the field. The TBCs provide an insulating barrier between the hot

combustion gases and the metal parts. TBCs will provide longer parts life

at the same firing temperature, or will allow the user to increase firing

temperature while maintaining the original design life of the hot section.

Compressor Coatings

Coatings can also be applied to gas turbine compressor blades (the

“cold end” of the machine) to improve performance. Unlike hot section

coatings, the purpose of compressor blade coatings is not to insulate the

metal blades from the compressed air. Rather, the coatings are applied in

order to provide smoother, more aerodynamic surfaces, which increase

compressor efficiency. In addition, smoother surfaces tend to resist

fouling because there are fewer “nooks and crannies” where dirt particles

can attach. Some coatings are also designed to resist corrosion, which can


be a significant source of performance degradation, particularly if a

turbine is located near saltwater.

Table 5.1.2 Gas Turbine Upgrade option

5.2 FBC Boiler :

5.2.1 Air : Fuel Optimization :

5.2.1.1 Economics :

SAVINGS POTENTIAL 1 to 10 percent of fuel cost,

typically.

COST A good chemical combustion

efficiency test kit that measures

oxygen, carbon dioxide, and

smoke which is used to set

Air:Fuel ratio for less than Rs.

25,000. Electronic testers of

reasonable quality cost from about

Rs. 50,000 to several thousand

Rupees. Also, consider the cost of

the actions that have to take to

improve efficiency.


The amount of labor required to

set

air-fuel ratio can be less than one

man-hour for a boiler with a

single-stage burner, to several

man-days for a boiler with

throttling burners and difficulty in

maintaining a steady load.

PAYBACK PERIOD Immediate, to one year.

Table 5.2.1.1.1 Economics : Air-Fuel Ratio Optimization

5.2.1.2 Traps & Tricks

SKILLS Adjusting air-fuel ratio requires

two skills, efficiency testing and

setting the boiler’s air-fuel

controls. Make sure that the

person adjusting the boiler knows

how to do it correctly.

TEST EQUIPMENT The right test equipment makes

the work much easier.

BOILER CONDITION It can’t set the air-fuel ratio

properly if the boiler’s controls

are sloppy or defective.

SCHEDULING Repeat the procedure periodically.

Make sure that you have an

effective method of scheduling it.

Table 5.2.1.1.2 Traps & Tricks : Air-Fuel Ratio Optimization


5.2.2 Improve Efficiency in Boiler :

5.2.2.1 Reduce Excess Air

One of the first considerations when trying to improve boiler

efficiency is to look at how excess air levels are being controlled. An

often-stated rule of thumb is that boiler

efficiency can be increased by 1 percent for each 15 percent reduction in

excess air. With a properly designed 02 trim system, the boiler will

maximize combustion efficiency and

minimize heat loss up the stack. In order to maintain excess air at

optimum levels, ensure that boiler control systems are working properly

and periodically have a qualified boiler/burner technician re-tune the

boilers burner.

5.2.2.2 Install an Economizer

In many boilers, useful amounts of energy still exist in the flue gases

even after they have passed through the boiler. Economizers are designed

to capture and transfer the exhaust heat of the flue gases to preheat

incoming boiler feedwater. Extended-surface economizers are designed

for maximum heat recovery and can decrease flue gas outlet stack

temperature to as low as 250°F (121°C). In general, for each flue gas

temperature decrease of 40°F (22°C), boiler efficiency is increased by 1

percent.

5.2.2.3 Install a Condensing Economizer

Condensing economizers are designed to pick up both sensible and

latent heat by condensing flue gas water vapor. They have been

designed to decrease the flue gas outlet stack temperature to as low as

100°F (38°C). Before considering the installation of a condensing


economizer, be sure to determine how the condensed water from the

flue gas will be disposed. Unlike a standard feedwater economizer, the

low-grade heat produced cannot be used by the boiler system. A plant

must have a need for constant low-grade heat (as with a hydronic

heating or washdown application) for this to be a cost-effective option

5.2.2.4 Upgrade Fan Controls

Variable-frequency drives (VFDs) adjust and control fan speed in

response to the boiler load, so upgrading to VFD fan controls can help

improve boiler efficiency. Standard constant-speed fan airflow is matched

to the boiler load by the opening and closing of a damper so horsepower

stays relatively constant, regardless of the load (depending on damper

arrangements). With VFDs, the exerted horsepower vanes three times the

fan speed. For example, if a fan operates at 75 percent of maximum

operating speed, the required horsepower would only be 40 percent of full

load compared to a constant speed fan. In addition to their energysaving

benefits, VFDs also can increase the service life of the fan motor,

decrease maintenance costs and significantly reduce noise levels.

5.2.2.5 Consider Installing a Selective Catalytic Reduction (SCR)

System

For applications requiring ultra-low NOx operation, an SCR system

with a standard no flue gas recirculation (FGR) low-excess air burner can

use considerably less fan horsepower than a high FGR, high excess air

ultra-low NOx burner. An ultra-low NOx burner requires a significantly

larger fan and generally has limited turndown and response to load

swings.

An SCR system with a standard burner can provide emission

reductions to as low as 2.5 ppm NOx depending on the application. It also

can reduce energy demands and is able to handle most plant load swings

with reliable boiler performance.


5.2.2.6 Perform Proper Water Treatment

Another major problem that affects boiler efficiency is poor water

quality or water treatment. The main objective of any boiler treatment

program is to prevent deposits and corrosion on the water side of the

boiler. It is important to ensure that any water treatment equipment is

designed for the particular makeup water entering the system. It is always

worth considering reverse osmosis (RO) for makeup water treatment. RO

reduces blowdown, which increases boiler efficiency and reduces boiler

treatment chemicals. Having high condensate return also increases overall

plant efficiency and reduces makeup water requirements.

5.2.2.7 Reduce Boiler Pressure

Any boiler that is operating at a pressure higher than the process

requirements offers the potential to save energy by reducing boiler

pressure. The boiler pressure directly corresponds to the water/saturation

temperature in the boiler. A lower boiler operating pressure results in

several efficiency gains, including higher LMTD (log mean temperature

difference) between the flue gas and boiler saturation temperature, higher

heat transfer, lower heat loss, lower outlet stack temperature and overall

reduced fuel usage.

5.2.2.8 Consider Boiler Blowdown Heat Recovery

There are two types of boiler blowdown: continuous and bottom.

Continuous blowdown removes dissolved solids from the water surface

and is continuously operating. Bottom blowdown removes sediment that

has settled to the bottom of the boiler and generally is used several times

a day. The energy contained in the continuous blowdown can be used to

preheat feedwater and supply flash steam to a deaerator, reducing overall

steam required by the deaerator. Flash tank systems or a blowdown heat


recovery system with a flash tank and a heat exchanger are two methods

for recuperating energy in the blowdown.

5.2.2.9 Upgrade to a High Turndown Burner and Controls

Upgrading a boiler with a high turndown burner reduces boiler

cycling and heat loss, and 02 trim controls provide feedback to the burner

controls to optimize the air-to-fuel ratio. This controls excess air amounts

and maximizes boiler efficiency gains.

5.2.2.10 Implement an Energy-Efficiency Program

A boiler efficiency improvement program includes two aspects: the

actions needed to bring a boiler to peak efficiency and the actions needed

to maintain the efficiency at the maximum level. The general guidelines

above provide several opportunities for energy and performance

improvements; however, it is up to the plant operator to look past the

immediate demands of the equipment and take a broad view of how the

system parameters affect the plant systems as a whole.

Many resources are available today to help operators develop a

comprehensive strategy to increase efficiency, reduce emissions and

boost productivity. Free plant assessments, training sessions offering by

manufacturers, associations and industrial services, as well as software

tools are readily available to help make decisions about implementing

efficient practices in your facility a reality.

5.2.3 Tips For Energy Efficiency In Boilers

Establish a boiler efficiency-maintenance program. Start with an

energy audit and follow-up, then make a boiler efficiency-

maintenance program a part of your continuous energy management

program.

Preheat combustion air with waste heat. Add an economizer to

preheat boiler feed water using exhaust heat.


(Every 22°C reduction in flue gas temperature increases boiler

efficiency by 1%.)

Use variable speed drives on large boiler combustion air fans with

variable flows instead of damper controls.

Insulate exposed hot oil tanks.

Clean burners, nozzles, and strainers regularly.

Inspect oil heaters to ensure proper oil temperature.

Close burner air and/or stack dampers when the burner is off, to

minimize heat loss up the stack.

Introduce oxygen trim controls (limit excess air to less than 10% on

clean fuels).

(Every 5% reduction in excess air increases boiler efficiency by 1%;

every 1% reduction of residual oxygen in stack gas increases boiler

efficiency by 1%.)

Automate/optimize boiler blowdown. Recover boiler blowdown

heat.

Optimize de-aerator venting to minimize steam losses.

Inspect door gaskets for leakage avoidance.

Inspect for scale and sediment on the water side.

(Every 1mm-thick scale (deposit) on the water side could increase

fuel consumption by 5%–8 %.)

Inspect heating surfaces for soot, fly-ash, and slag deposits on the

fire side.

(A 3mm-thick soot deposition on the heat transfer surface can cause

an increase in fuel consumption of 2.5%.)

Optimize boiler water treatment.

Recycle steam condensate to the maximum extent.

Study part–load characteristics and cycling costs to determine the

most efficient combination for operating multiple boiler

installations.

Consider using multiple units instead of one or two large boilers, to

avoid partial load inefficiencies.


5.2.4 Cost-Effective Components

Modern boilers include the following burner features:

Re-circulated flue gases, which ensures optimal combustion with

minimal excess air.

Sophisticated electronic control systems that monitor flue-gas

components and adjust fuel and air as needed.

Greatly improved turndown ratios to improve efficiency at less than

peak load.

Powered or forced draft burners, instead of atmospheric burners.

The number of passes a boiler is designed for affects its efficiency.

Generally, the more passes, the higher the efficiency. Fire-tube boilers

designed with turbulators inside the tubes with fewer passes improve

efficiency.

5.2.5 General rules (“Rules of Thumb”)

5 percent reduction in excess air increases boiler efficiency by 1

percent (or 1 percent

reduction of residual oxygen in stack gas increases boiler efficiency

by 1 percent).

22°C reduction in flue gas temperature increases the boiler

efficiency by 1 percent.

6°C rise in feed water temperature brought about by

economizer/condensate recovery corresponds to a 1 percent savings

in boiler fuel consumption.

20 °C increase in combustion air temperature, pre-heated by waste

heat recovery, results in a 1 percent fuel saving.


A 3 mm diameter hole in a pipe carrying 7 kg/cm2 steam would

waste 32,650 liters of fuel oil per year.

100 m of bare steam pipe with a diameter of 150 mm carrying

saturated steam at 8 kg/cm2 would waste 25 000 litres furnace oil in

a year.

70 percent of heat losses can be reduced by floating a layer of 45

mm diameter polypropylene (plastic) balls on the surface of a 90 °C

hot liquid/condensate.

A 0.25 mm thick air film offers the same resistance to heat transfer

as a 330 mm thick copper wall.

A 3 mm thick soot deposit on a heat transfer surface can cause a 2.5

percent increase in fuel consumption.

A 1 mm thick scale deposit on the waterside could increase fuel

consumption by 5 to 8 percent.


Chapter 6 : Conclusion


Economic analyses of combined-cycle performance enhancement

options normally reveal that HRSG duct firing is the best option for the

plant. It is followed by inlet fogging, evaporative cooling, and inlet air

chilling. However, these analyses were focused on capacity-driven

economics resulting from premiums paid for short periods of peak power

generation. Efficiency enhancements can be achieved through fuel

heating and spray intercooling.

The final choice requires careful evaluation of many factors,

including water availability, maintenance factors, capital cost, operating

cost, operating duration and plant dispatch characteristics. These

economic drivers exist in today’s market environment. However, as the

market condition changes due to an increase in the installed capacity,

escalation of fuel prices, and deregulation in the power generation

industry, the emphasis will shift to plant efficiency.

Thus, plants designed with moderate increase in capacity and high

efficiency could provide the highest life cycle profitability.


6.2 FBC Boiler

We conclude that fluidized bed boiler is the new generation

method for production of steam. By this method we have seen that

the efficiency of pressurized bed boilers is almost 50% more than

that of a typical pulverized coal boiler. By this method we have seen

that the pollutants emitted during combustion of coal is significantly

reduced.

Fluidized bed boilers can also burn very dirty coal and

remove 90% or more of the sulphur and nitrogen pollutants .Since

these boilers operate comparatively at a low temperature corrosion

will be reduced and hence reduce boiler maintenance cost .


Chapter 7 : REFERENCES


1. Handbook for Cogeneration and Combined Cycle Power Plants

by Meherwan P. Boyce

2. Combined-Cycle Gas and Steam Turbine Power Plants

by Rolf Kehlhofer

3. Bureau of Energy Efficiency Guidebook

4. Combined Heating, Cooling & Power Handbook: Technologies &

Applications by Neil Petchers

5. Gas Turbine Engineering Handbook

by Meherwan P Boyce

6. Power Generation handbook 2nd edition

by Philip Kiameh


7.2 FBC Boiler

1. Energy Efficiency Manual

by Donald R. Wulfinghoff

2. Power Line Volume 8, No. 3, December 2003

3. Pressurized FBC Technology by W.F.Podolski, Noyes Data

Corporation, U.S, 1983.

4. Venus Energy Audit System, Venus-boiler audit-Guidebook

5. Bureau of Energy Efficiency Guidebook

6. Document : Thermal Energy Equipment: Boilers & Thermic Fluid

Heaters

7. Document : Improving Energy Efficiency of Boiler Systems by A.

Bhatia

8. Document : PDH Course Content : Improving Energy Efficiency

of Boiler Systems

9. Document : CIBO, Energy Efficiency & Industrial Boiler Efficiency An Industry Perspective

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