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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.
Arvind Limited, Ahmedabad 2
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.
Arvind Limited, Ahmedabad 3
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
Arvind Limited, Ahmedabad 4
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
Arvind Limited, Ahmedabad 5
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
Arvind Limited, Ahmedabad 6
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
Arvind Limited, Ahmedabad 7
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
Arvind Limited, Ahmedabad 8
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
Arvind Limited, Ahmedabad 9
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
Arvind Limited, Ahmedabad 10
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 Combined Cycle Power Plant 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 Combined Cycle Power Plant 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
Arvind Limited, Ahmedabad 11
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
6.1 Combined Cycle Power Plant 135
6.2 FBC Boiler 136
Chaper 7 : References 137
7.1 Combined Cycle Power Plant 137
7.2 FBC Boiler 138
Arvind Limited, Ahmedabad 12
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.
Arvind Limited, Ahmedabad 13
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
Arvind Limited, Ahmedabad 14
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
Arvind Limited, Ahmedabad 15
1.3 Introduction Cogeneration CCPP Power Plant
1.3.1 Map 1: Overview of the Project Site : Naroda Road, Ahmedabad
Arvind Limited, Ahmedabad 16
1.3.2 Map 2: Overview of the Project Site : Santej Road , Kalol,
Gandhinagar
Arvind Limited, Ahmedabad 17
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.
Arvind Limited, Ahmedabad 18
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)
Arvind Limited, Ahmedabad 19
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.
Arvind Limited, Ahmedabad 20
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
.
Arvind Limited, Ahmedabad 21
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.
Arvind Limited, Ahmedabad 22
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
Arvind Limited, Ahmedabad 23
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)
Arvind Limited, Ahmedabad 24
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
Arvind Limited, Ahmedabad 25
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 :
Arvind Limited, Ahmedabad 26
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.
Arvind Limited, Ahmedabad 27
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.
Arvind Limited, Ahmedabad 28
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.
Arvind Limited, Ahmedabad 29
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.
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Fig 2.1.2.1 Auxiliary Systems in a Gas Turbine Power Plant
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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.
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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.
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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
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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
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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
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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
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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’
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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
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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
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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.
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Figure 2.1.6.1 Energy distribution in a combined cycle power plant
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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.
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Figure 2.1.6.3 A typical large combined cycle power plant HRSG
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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
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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
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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
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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
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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
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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
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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:
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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
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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.
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Figure 2.2.2.1 CFBC Power Generation Unit : Working Diagram
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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
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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
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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.
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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
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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
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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:
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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
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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.
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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
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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
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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
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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.
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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
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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
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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
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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 :
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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 :
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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
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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.
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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
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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:
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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 :
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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
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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.
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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
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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.
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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.
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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
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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
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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.
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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.
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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
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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
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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.
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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.
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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.
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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.
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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
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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
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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).
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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
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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.
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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%.
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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
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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.
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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.
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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
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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.
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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.
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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
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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
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Chapter 4 : Calculations
4.1 Combined Cycle Power Plant
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.
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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 %,
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= 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 %
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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,
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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%
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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%
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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
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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
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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 %
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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
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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:
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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
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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:
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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,
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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
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5.1 Combined Cycle Power Plant
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.
Case 11 GT Inlet Chilling to 45°F (Ambient RH-45%), Chiller with
Cooling Tower Sink
Case 12 GT Inlet Chilling to 45°F (Ambient RH-60%), Chiller with
External Heat Sink.
Case 13 GT Inlet Chilling to 45°F (Ambient RH-60%), Chiller with
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.
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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.
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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
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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.
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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
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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
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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.
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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
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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.
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(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.
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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.
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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.
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Chapter 6 : Conclusion
6.1 Combined Cycle Power Plant
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.
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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 .
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Chapter 7 : REFERENCES
7.1 Combined Cycle Power Plant
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
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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