Circulating Fluidized Bed Boiler (cfb) training module

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Circulating Fluidized Bed
Boiler Operation
My world changed when I started focusing on the skills and made the
commitment to practice, practice, practice, until I mastered them.
Coal as fuel for power plants
The average annual sale prices of coal at mines producing each of the four major
ranks of coal in 2015, in dollars per short ton (2,000 pounds)
• Bituminous—$51.57
• Subbituminous—$14.63
• Lignite—$22.36
• Anthracite—$97.91
In 2015, the average sales price of coal at the mine was $31.83 per ton, and the
average delivered coal price to the electric power sector was $42.58 per ton,
resulting in an average transportation cost of $10.75 per ton, or about 25% of the
total delivered price

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Operating the CFB Boiler – Is it easy?

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Conveying
system
Boiler Safe Operation

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Boiler Safe operation is a result of
comprehensive training programs for
operators, well designed furnace
safeguard systems, and an effective plant
maintenance program.
Basic Rules in boiler operation:
 The boiler systems and auxiliary devices must be checked before start-up.
 The boiler cannot be started if significant flaws
 The Shift Supervisor responsible for operation assigns the person responsible.
 Boiler operators must understand the operation of the boiler completely
 The person responsible for the boiler operation gives the permission for start-up
Power Plant Supervisors spend 5% of their time on the
problem and 95% of their time on the solution……

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Day 1
8 Am – 12 Pm
1. CFB System
2. Mode of Operation
1 Pm – 5 pm
1. Operator Interface and Interlock
system
2. Boiler Safety and Protection System
Day 2
8 Am – 12 Pm
Start-up System of CFB Boiler, Start-
up and Load Operation
1 Pm – 5 pm
Shutdown and Operation Controls
for CFB Boiler and Auxiliaries

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Operating the Power Block – the process
The energy conversion process
Modified Rankine Cycle

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Taking Charge at the Plant
Taking Charge at the Plant...is it worth our
time
More than 8 hours
(minimum) of your
time, you spend at
the plant

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Taking Charge at the Plant…it is up to me
You have to ensure that the plant is running in a safe and efficient manner
Coal Fired Power Plant… You have to love it…
Very interesting to learn every bits and pieces of the plant

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CFB System
• Coal
• Hydrodynamics
• Combustion
• Heat transfer
• Operation and Maintenance issues
Coal
• Coal is a mixture of organic mineral material produced by a natural
process of growth and decay
• It is classify according to the amount of heat it produces
• Forms of coal
a) Anthracite - Hard and very brittle
b) Bituminous - are soft coals and are by far the most abundant
group
c) Subbituminous - are very soft coals
d) Lignite - are generally found close to the surface
•

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Coal Combustion in two common boilers
A pulverized coal-fired boilerA circulating fluidized bed boiler
What Is a Circulating Fluidized Bed Boiler?
• The furnace or combustion chamber holds a large inventory of non-
combustible solids, lifted and entrained by high-velocity combustion
gas passing through the furnace.
• Major fraction of the solids leaving the furnace is captured by a gas–
solid separator and is recirculated back to the base of the furnace at a
rate sufficiently high to cause a minimum degree of refluxing of solids
adequate to ensure uniformity of temperature in the furnace
• Combination of gas velocity, solid recirculation rate, solids
characteristics, solid inventory, and geometry of the system gives rise to
this special hydrodynamic condition under which solid particles are
fluidized at a velocity greater than the terminal velocity of individual
particles.

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Economic Advantages of a CFB Boiler …
The primary objective of selecting a CFB boiler is to reduce capital and operating
costs. CFB boilers provide the economic viability for burning low grade fuels with
superior environmental performance.
The economic advantages of a CFB boiler are mainly due to the following:
• Accepts low quality, less costly fuels.
• Offers greater fuel flexibility (within the specified range) as compared to
pulverized coal (PC) fired boilers.
• Reduces the fuel crushing (coarser feed size) cost.
• Lower capital cost (no expensive pollution control equipment) and lower
operating cost.
CFBC Issues and challenges…
Disturbances are caused by…
• Low quality fuels with varying heating values
• Multiple fuel firing with varying mixture and moisture
• Load demand requirements from generation requires
fast response and greater turndown
The consequences…
• Higher emissions
• Lower efficiency
• Imbalance between demand and supply
All lead to higher operating costs!

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CFBC Issues and challenges…
Factors Affecting CFB Availability Possible Technical Solutions
1 Erosion Problem
• In refractory transition Area
• In radiant SH
• Use of gas dampers/Mechanical
Valves/Screws
• Convection Heat Exchanger
Optimized gas velocity
Positioning of SH & convective design
No moving parts in high temperature zone
2 Refractory Problems Heavily minimized by cooled cyclone design
Single layered, less thick and easy to apply refractory
3 Failure of expansion Joints Completely avoided with water cooled cyclone
designs
4 Improper Auxiliary selection
• Fuel Feeders
• Fans & Motors
• Bottom Ash Handling System
Selection of appropriate type, size and make
Selection based on service availability
Maintaining adequate redundancy
5 Gradual & undetected Wear & Tear of boiler
parts
Periodically planned O & M Services
6 Operators Error Enhanced training of O &M team
Maximized automation of boiler controls
7 Design Faults Bench marking with feedback of vast fluid bed
operating experience
Other CFBC Issues and challenges…
• General Tube Erosion Cases
• Erosion of boundary aspect between
refractory and wall tube
• Erosion of tube coating boundary
aspect
• Erosion of irregular tube surface due
to overlaying and poor extent of tube
straight
• Erosion of lower part of wall tube (in
the vicinity of kick out) due to up-
flowing particles

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Hydrodynamics
a branch of physics that deals with the motion of fluids
and the forces acting on solid bodies immersed in
fluids and in motion relative to them

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Circulating Fluidized Bed Boiler
Hydrodynamics
The furnace of a CFB boiler contains a large inventory of granular solids
called bed materials, which are typically in the size range of 0.1–0.3 mm.
Bed materials may be made of the following:
1. Sand or gravel (for boilers, burning low-ash fuels, such as woodchips)
2. Fresh or spent limestone (boilers burning high-sulfur coal and
requiring control of sulfur emission)
3. Ash from fuels (boilers ring high or medium - ash fuels requiring no
sulfur)
Undergoes hydrodynamics conditions
1. Hydrodynamics Application in CFB
Fluidized bed hydrodynamic behavior is very complex and must be understood to
improve fluidized bed operations.
Several parameters are used to understand the behavior of a material the moment
it is fluidized.
One of the most important parameters to characterize fluidized bed conditions is
the minimum fluidization velocity (Umf), which quantifies the drag force needed to
attain solid suspension in the gas phase. The minimum fluidization velocity also
constitutes a reference for evaluating fluidization intensity when the bed is
operated at higher gas velocities
Gas holdup is another very important parameter that characterizes the fluidization
quality, mixing, and process efficiency in a fluidization system, and is defined as the
volume fraction of gas present within the bed.

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Fluidized bed hydrodynamic behavior is very complex
and must be understood to improve fluidized bed
operations.
Several parameters are used to understand the
behavior of a material the moment it is fluidized.
to improve the understanding of fluidized bed
hydrodynamics by determining the effects of bed
height and material density
In a circulating fluidized bed (CFB) boiler, hot solids circulate around an
endless loop carrying heat from burning fuels to heat-absorbing surfaces
and to the flue gas leaving the furnace

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Hydrodynamics Conditions
Location Regime
• Furnace (below
secondary air level)
• Turbulent or
bubbling fluidized
bed
• Furnace (above
secondary air level)
• Fast fluidized bed
• Cyclone • Swirl flow
• Return leg
(standpipe)
• Moving packed
bed
• Loop
seal/external heat
exchanger
• Bubbling fluidized
bed
• Back pass • Pneumatic
transport
1. Hydrodynamics Conditions in CFB
The hydrodynamic condition dictates auxiliary power
consumption, heat absorption, temperature distribution,
combustion condition, bed inventory and erosion.

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Hydrodynamics Conditions in CFB
1. An object denser than the bulk of the bed will sink
2. The solids from the bed may be drained
3. The bed surface maintains a horizontal level
4. Particles are well mixed, and the bed maintains a nearly uniform temperature
A Fluidized Bed Demonstrates All the Characteristics of a Fluid
Regimes of Fluidization
Different commercial combustion systems operate under different gas–solid flow
regimes.
Increasing Superficial Velocity

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Comparison hydrodynamics inside the
Fluidized Boiler
Bubbling Fluid
Bed Regime
Circulating Fluid
Bed Regime
Transport Regime
Comparisons of principal gas - solid
contacting combustion processes
Plot of gas pressure drop through a fluidized bed versus gas velocity

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Relationships
Between Fixed Grate, Fluidized Bed, and Pulverized Firing
Why Playing Football…instead of board
games

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Combustion in CFB Boiler
Material Material Density
(kg/m3)
Particle Diameter
(ʊm)
Coal 1545 717, 1200
Sand 2638 717
Limestone 2785 500, 600, 800
Material Material Density
(kg/m3)
Particle Diameter
(ʊm)
Coal 1545 717, 1200
Sand 2638 717
Limestone 2785 500, 600, 800
Combustion - /kəmˈbʌs.tʃən/, is a chemical
reaction that occurs between a fuel and an oxidizing
agent that produces energy, usually in the form of heat
and light.

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Goes in and Goes Out of the Boiler
Temperature Distribution in CFB boiler

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1. Comparisons of principal gas - solid
contacting combustion processes
Property Packed bed Fluidized
bed
Fast bed Pneumatic
transport
Application in boilers Stoker fired Bubbling
fluidized
Circulating
fluidized
Circulating
fluidized
Mean particle diameter (mm) <300 0.03–3 0.05–0.5 0.02–0.08
Gas velocity through
combustor
zone
1–3 0.5–2.5 3.5–6 15–30
Solids motion Static Up and
down
Mostly up,
some down
Up
Typical bed-to-surface. Heat
transfer coefficient (W/m2 K)
50–150 200–550 100–200 50–100
Agglomeration Considerable Some Less No Problem
2. Comparison of Circulating Fluidized Bed
with other types of Boilers
Characteristics Stoker Bubbling Circulating Pulverized
Height of furnace or burning zone (m) 0.2 1–2 15–40 27–45
Superficial gas velocity (m/s) 1–2 1.5–2.5 4–6 4–7
Excess air (%) 20–30 20–25 15–20 15–30
Grate heat-release rate (MW/m2) 0.5–1.0 0.5–1.5 3–5 4–6
Coal size (mm) 6–32 0–6 0–6 <0.1
Turndown ratio 4:1 3:1 3.4:1 3:1
Combustion efficiency (%) 85–90 90–96 95–99.5 99–99.5
Nitrogen oxide (ppm) 400–600 300–400 50–200 400–600
Sulfur dioxide capture in furnace (0.2) None 80–90 80–90 None

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Particle size distribution
Coal Combustion in CFB Boiler
• The bed material in a CFB boiler can be classified into groups with respect to
their contribution to fluidization and heat transfer :
• The effective material
• The ineffective material
• The effective bed material is consists of the fine particles that are entrained
out the bottom bubbling bed and forms a fast bed in the upper furnace. The
mass fraction of effective bed material is often denoted as bed quality.
• The rest particles, with relatively large size, are the ineffective material. As
their terminal velocity is larger these particles can not be entrained into the
upper furnace, but remains only in the bubbling bed.
• Normally the membrane water-wall in the bottom furnace is covered with a
refractory layer, so the ineffective bed material has a minor effect on heat
transfer performance.

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Coal Combustion Facts
• The cost of fuel constitutes a major part (15–40 %) of the cost of electricity
generation for most fossil fuel power plants.
• Over the lifetime a boiler plant, a savings of 1.0 or 0.5 a percentage point in the
combustion efficiency can save a large amount of money in terms of operating
cost.
• Since the expenditure on fuel is much greater than that on sorbents, the impact
of combustion efficiency on the operating cost is greater than that of sorbent
utilization performance of the boiler.
1. Furnace
2. Air distribution device
3. Gas Solid Separator
4. Recycle Device
5. Combustion Process in CFB Boiler
• Heating and Drying
• Devolatization
• Volatile Combustion
• Char Combustion
• Communication Phenomena During Combustion

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Structure of CFB
Circulating Fluidized Bed Combustion
Bed is divided in to 3 zones
1. Lower Zone-Below PA entry.
• Fluidized by 40-80% of stoichiometric air for fuel feed Fuel, sorbent
and unburned char from cyclone are received in this zone.
• Oxygen deficiency controls NOx emission.
• Much denser and serves as an insulated storage of hot solids providing
CFB boiler with a thermal flywheel.
• PA/SA increased on increase of Boiler load, transferring greater
amount of hot solids into upper zone of the furnace and increasing
solid circulation rate.
2. Upper Zone-Above SA entry
• Combustion completes with added SA and unburned char to cyclone
for return. More residence time for completing the combustion.
3. Hot Gas/ Solids Separator
• Cyclone (External)/ U-Beams (internal)

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Coal Combustion
A fuel particle injected into a fluidized bed undergoes the following sequential
events;
• Heating and drying
• Devolatization and volatile combustion
• Swelling and primary fragmentation (for some types of coal)
• Combustion of char with secondary fragmentation and attrition.
Coal Burning in Fluidized Bed
Coal particles undergo fragmentation
in fluidized bed due to :
• Increase of porosity of char
particles (percolative
fragmentation)
• Collision of coal particles with bed
particles,
• Attrition of coal particles in bed.

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Coal Combustion in Free Board Zone
of Fluidized Bed
PULVERIZED COAL STRUCTURE
CFB COAL STRUCTURE
Stages of Combustion
Heating and Drying
• Burning fuel particles (or char) generally
constitutes around 1–3 % by weight of
the total solids in the fluidized bed.
• The remaining solids, known as bed
materials, are non-combustibles such as
ash and sorbents. Thus, when a fresh
fuel particle is fed into a CFB combustor,
a large body of non-combustible hot
solids immediately engulfs it.
• These hot particles preheat the cold
coal or fuel particle close to the bed
temperature. The rate of heating may
vary from 100 °C/s to more than 1000
°C/s, depending upon several factors,
including the fuel particle size

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Devolatilization
• Devolatilization (or pyrolysis) is the
process of release of a wide range
of condensable and non-
condensable gaseous products of
decomposition of fuel. The volatile
matter comprises a number of
hydrocarbons.
• The first steady release usually
occurs at around 500–600 °C, and
the second release occurs at around
800–1000 °C.
• Slowest species is CO, a 3 mm coal
take 14 sec to devolatilize at 850 0C
Sequence of volatile release showing how
different constituents of volatiles are released
during different stages of Devolatilization
Devolatilization and volatile combustion
• First steady release 500-600 0C
• Second release 800-1000 0C
• Slowest species is CO (Keairns et al., 1984)
• 3 mm coal take 14 sec to devolatilize at 850 0C (Basu and Fraser, 1991)

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Factors Affecting Combustion of CFBB
1. Fuel properties
2. Air distribution device and fluidization quality
3. Coal feeding mode
4. Bed temperature
5. Separator performance
6. Secondary air
Combustion Temperature
CFB furnaces are operated at a temperature of
around 850 °C. The combustion temperature is
maintained in the range of 800–900 °C for the
following reasons:
1. Most fuel ash does not fuse at this
temperature.
2. Sulfur capture reaction is optimum at around
850 °C.
3. Alkali metals from the coal are not vaporized
at such low temperatures. Thus, the risk of
fouling that is caused by condensation of
vaporized alkali metal salts on boiler tubes is
greatly reduced.
4. The nitrogen in combustion air is not readily
converted into NOx

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Combustion Temperature
CFB boiler furnaces at times operate at
temperatures well above the designed range
of 800–900 °C due to reduction in heat
absorption in the furnace or under surfacing
of furnace heat absorbing elements.
Prolonged operation at temperature
exceeding 900 °C could bring in the
following:
1. Much increase in limestone consumption
and sorbent production for designed
level of sulfur capture
2. Potential corrosion and fouling of
superheater or reheater tubes in the
backpass.
3. Reduction in creep life of tube elements
4. Increased NOx emission from the boiler
Bed Temperatures for Different Fuels
A temperature of 750°C (1380°F) during low loads acts as a limiting
temperature for the bed to decrease unburnt loss. The optimum
temperature for lime–sulfur reactions is 850°C (1560°F). A rough guide for
bed temperature selection can be as follows:
• 800°C (∼1470°F) for fuels with low-melting compounds in ash such
as lignite
• 850°C (∼1560°F) for fuels needing sulfur removal
• 900°C (∼1650°F) for difficult-to-burn low-volatile fuels such as
anthracite with more FC and ashy bituminous coals

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SO2 Capture
Optimum temperature :
850 °C
 SO2 Capture achieved by
limestone injection
CaCO3 --> CaO + CO2
CaO + SO2 + ½ O2 --> Ca SO4
Furnace temperature control is
very critical
Limestone consumption varies
enormously with furnace
temperature
NOX formation vs Temperature and Nitrogen
content of the fuel…

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In Summary
Circulating Fluidized Bed Combustion Process
The full-circulation CFBC process involves
1. Operating at higher velocities of ∼4 to 7 m/s
2. Using high ash recirculation for uniform temperature profile
3. Controlling the combustor temperature near optimum desulfurization
temperature
4. Employing staged combustion to limit NOx
5. Releasing high heat rates in plant areas closer to PF boilers
Combustion Air
Combustion air is supplied in CFBC boilers at two levels
1. ∼60% at the bottom of the combustor at a high pressure to fluidize the bed
2. ∼40% in freeboard to complete the combustion Fluidization velocities were
7–8 m/s (∼23 to 26 ft/s) and have been reduced to ∼6 m/s (∼20 ft/s).
In Summary
Circulating Fluidized Bed Combustion Process

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Heat Transfer in CFB
There are 5 different ways by which heat
transfer takes place in CFB Boilers
1. Gas to particle
2. Bed to water wall
3. Bed to surface immersed surfaces in
externa heat exchanger
4. Heat Transfer to cyclone or other primary
separator
Schematic of heat transfer process
Heat transfer in a CFBB
is achieved mainly
depending on the:
Heat Transfer
1. Convective heat transfer of
solid particles
2. Convective heat transfer of
flue gas
3. Radiative heat transfer of flue
gas and solid particles

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Heat Transfer Sections of a Circulating
Fluidized Bed Boiler
Heat Transfer is affected by:
• Gas to particle
• Suspension Density and
particle size
• Fluidization Velocity
• Vertical Length of
heating surface
• Bed Temperature
Convective heat transfer of solid particles
After entering into the fast bed fluidized state, a large quantity of particle clusters
move downwards along the water cooled wall in the surrounding of the furnace.
When the hot particle clusters contact with the water cooled wall, the new and old
particle clusters replace each other periodically, so that convective heat transfer
with the wall surface is achieved, as shown in figure below;
The higher the renewing frequency of
the particles is, the faster the heat
transfer speed will be. Therefore,
higher particle concentration and
smaller particle size lead to stronger
convective heat transfer. In addition, a
stronger convective heat transfer
process depends on higher
temperature, higher density and
smoother surface of the particles

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Convective heat transfer of gas
• Both the furnace and the Flue gas pass are full of
high-temperature flue gases.
• These flue gases carry out convective heat transfer
with the heating surface.
• The degree of heat transfer depends on the
temperature, flow rate, viscosity, density and
specific heat of the flue gases.
Radiative heat transfer
The high-temperature flue gases and solid particles in the furnace can also carry out
heat transfer with the heating surface by radiative heat transfer mode, the degree of
which is mainly affected by temperature.
The higher the temperature is, the stronger the degree of radiative heat transfer will be.
The heat transfer coefficients of these three heat transfer modes are listed in the
table below:
Heat Transfer Mode Heat Transfer
Coefficient, W/m2K
Radiation and
convection of gas
57 - 141
Solid radiation 141- 340
Solid Convection 340 - 545

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Heat Transfer in CFB Boiler
Mechanism of Heat Transfer (Water Wall)
Regions and phases in a CFB combustorThe furnace cross section
dimensions are selected based
on flue gas superficial velocity.

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• Wing walls are used to achieve the
desired furnace temperature.
• The evaporative or Superheat wing wall
located on upper zone of furnace is
covered by erosion resistant materials

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Mode of Operations

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Load Control and Part-Load Operations
A CFB boiler performs well
as a base load unit, it is at
times called for cycling
operation when the boiler
needs to respond to the
fluctuation of changes in
steam and load demand.
Load Control in CFB Boilers
When load increases, a boiler must deliver more steam, and when load decreases, the
steam delivery needs to reduce.
The steam temperature however should not change when the flow rate changes. CFB
boilers can adequately respond to variation in load demands.
• Typically, they can handle load changes of 2–4 % (of full load) per minute in the load
range of 100–50 %
• 1–2 %/min in the 50–30 % load range without any problem.
• In most cases, the boiler is not the limiting factor. The allowable rate of change of
turbine metal temperature restricts the pace of load change.
• The bed inventory, sensed by differential pressure drop across the bed, is one unique
control feature of a CFB boiler. Distributed control systems (DCS) and programmable
logic control (PLC) are used for control, display, alarm, and operator interface
functions.

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Part - Load Operation
• A CFB boiler can reduce its output to 30 % of its maximum continuous rating (MCR)
without firing any auxiliary fuel oil. A pulverized coal-fired boiler on the other hand
will require support from oil firing to maintain the coal flame at such low load.
• The above positive feature of CFB boiler greatly reduces the consumption of
expensive auxiliary fuel. However, at 30 % load, the furnace would operate in
bubbling bed mode instead of being in fast bed.
• To reduce the load on the boiler, the operator could reduce the primary airflow. This
will increase the density of lower bed and reduce the density of upper bed.
• The fuel feed rate would, of course, change correspondingly to keep the oxygen
concentration and bed temperature within limits. The bed temperature is another
parameter that can be adjusted within a certain range to control the load.
Distribution of Primary and Secondary Air
and Change in Flue Gas Velocity at
Different Loads
LOAD 100 % 75% 60% 50%
Bed Temperature (0C) 840–850 840–850 840–850 840–850
Flue gas velocity in furnace (m/s) 6.5 4.1 3.4 3.1
Primary air ratio (%) 33 44 49 52
Secondary air ratio (%) 55 48 43 40

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Bed
The bed consists of two layers:
1. The active, fluidized layer above the air jets
2. The static layer of ∼100 mm thickness all
around air nozzles, which acts as an
insulation protecting the bottom plate from
the heat of the bed.
Bed material is usually sand, ash, or crushed
refractory in a size range of 0.5 –1.2 mm.
Sand should be rounded river or lake
sand with no abrasive alpha quartz to
avert any chances of erosion. Sea sand
should not be used because it contains
alkalies and chlorides.
Bed
• Coal with ash >15% do not require bed ash
replenishment.
• For firing coal with lower ash, a bed
material silo and a feeding system are
required. Crushed refractory for bed
material is less aggressive but more
expensive than sand.
• High underbed pressure in FBC boilers
drives away most of the ash, and only the
heavier particles, which are fuel impurities
such as stones and shale separate out as
bed ash. Bed ash usually contains very little
carbon (<1%) in case of coals and forms
<10% of total ash.
Periodic draining is needed to remove
this burden to maintain bed height.
Usually, one ash nozzle of 150 NB is
considered for 10–20 m2 (∼100 to 200
ft2) of bed area suitable to drain an
area within 3.5–5 m (∼10 to 15 ft) of
radius.

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Bed Drain Solids Coolers
• Water-cooled screws or
fluidized-bed ash coolers can
be used for the bed drain
cooling.
• The type of ash cooler
depends on fuel properties,
plant economics, heat
utilization, and the need for
bed material classification for
reinjection of fines particles.
• The purpose of draining the bed material from the
furnace is to control the bed solids inventory and
remove oversized material accumulated during
operation.
• Big bed-drain pipes in distributor, designed to, drain
some bed-materials on regular to maintain proper
inventory in the bed;
• The inventory can be indicated by pressure-drop
across dense bed; it can affect the bed temperature
and thus the furnace temperature.
• The drained material is at bed temperature and carries
a considerable amount of sensible heat.
• The material is cooled to an acceptable temperature
before disposal into the ash system.
Freeboard
• Freeboard is the chamber between the
top of the expanded bed and the
convection surfaces.
• For easy-burning fuels, it should give a
residence time of 2.5 s, and for slow-
burning fuels, the time should be 3 s.
• Fines and volatiles burn here, and
despite good heat absorption by
radiation, the exit temperature is ∼30 to
50°C higher than the bed temperature.
• For overfeed firing, the difference is at
the higher end, as all fines burn in
suspension. SA nozzles are provided on
opposite walls.

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Ash Recirculation
There are two reasons for recirculating ash
from the back ends in FBC boilers.
1. Fine particles escaping combustion in
freeboard get caught in the hoppers and
mechanical dust collectors (MDCs) or
electrostatic precipitator.
• The fines are rich in carbon and can be burnt
if returned to high furnace temperature once
again.
• This improves the carbon burn-up efficiency.
• In less reactive and high calorific value fuels
such as bituminous coal or anthracite, the
dust particles contain a lot of carbon and it is
vital that this is returned for refiring to
improve efficiency.
2. Ash recirculation is also necessary for better
utilization of limestone and lowering of Ca/S
ratio.
Air distribution device
It is the device which supports materials at the bottom of the
furnace and distributes primary air.
The air distribution device mainly comprises air distributor,
primary air chamber and air button.
Performance required for air distribution device
The air distribution device is significant for evenly distributing the
primary air, ensuring good fluidization quality.
Requirements for air distribution device are:
1. To be capable of evenly distributing airflow, avoiding
stagnant zone and four corners on the air distributor;
2. To provide enough air speed for the airflow at the outlet of
small air button hole so as to fully mix materials and air;
3. To have a certain strength and stiffness, and not to be
deformed easily;
4. Not to be leaked for ash easily.
Air Button Set on Water-Cooled Air
Distributor

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Air Distribution Device
• Distributor with bubble-caps nozzles
• Designed to
- Distribute air uniformly;
- Prevent back-sifting of solids at low load
- Create good turbulence for fuel/sorbent
mixing in primary zone
Big bed-drain pipes in distributor, designed to,
• Drain some bed-materials on regular to
maintain proper inventory in the bed;
• The inventory can be indicated by pressure-
drop across dense bed; it can affect the bed
temperature and thus the furnace
temperature.
Air Buttons with Small Borehole Diameter
Bell-Shaped Air Button with Big Borehole Diameter
Solids Separator
Gas Solid
Separation
Hot loop
Mechanical
Cyclone
Separator
Cold End
Electrostatic
ESP
Cold End
Filters
Bag House

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Solids Separator
1. One of the most important key components in CFB
• The main distinguishing feature of a CFB boiler is the separator.
2. Located at the furnace gas outlet
3. For collecting bed material entrained in flue gas and
return them back to bed
• Bed material contains fuel ash, unburned fuel, utilized &
unutilized limestone;
• Collection & re-circulation results in excellent fuel burnout &
limestone utilization
4. Two mainstreams of separators: cyclone type vs.
impact-separator
A. Cyclone:
• The most commonly used separator
• High separation efficiency;
• Separating solids from gases ,
• The gases are accelerated to a velocity of ∼25 to 28 m/s
B. Impact-Separator: a two-stage solid separation system;
• 1st stage being an impact-type solids separator
• Majority of solids collected by it are Internally Recycled
Within furnace;
Separation characteristics of different
gas–solid separators

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Recycle Device
Pressure distribution in recycle device of
CFBB
• Because high pressure primary air is sent
into from the air distributor, the pressure
on the air distributor is higher, which is
in the state of positive pressure.
• The pressure at the furnace outlet is
about equal to atmospheric pressure.
• The pressure in the separator is in the
state of negative pressure due to the
pumping effect of induced draft fan.
• Therefore, if materials separated from
the separator is to be sent into the
furnace of higher pressure from that of
separator lower pressure, recycle device
must be equipped.
Supplying of HP
Blower in Loop
Seal
Fuel and Sorbent
Fuel and sorbent are always fed into the
combustor from the top.
Usual crushed fuel sizes are
• 10 mm or more for lignite
• 8 mm for bituminous coal
• 6 mm for anthracite or low-volatile coal
Fines in fuel up to 40% through 1 mm and
surface moisture up to 15% are acceptable. This
makes CFBC an extremely versatile technology.
Sizing for limestone is usually 1 mm, depending
on purity and reactivity. Fuel and sorbent sizing
is very important for good interaction between
the two.

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Combustor
1. The lower combustor, up to the level of tertiary air (TA), is always in a heavily
reducing zone on account of sub-stoichiometric air.
2. This helps in lowering the NOx produced by the reaction of C and CO with NO2.
3. The lower combustor is refractory-lined to prevent tube corrosion due to the
reducing environment.
The refractory has to be:
• Very hard to withstand bed material erosion
• Reasonably thin to reduce weight
• Optimally conductive to transmit heat to the walls
Combustor
Tube leakage
1. Greater care is necessary in the manufacture of
membrane panels of CFBC boilers as they
experience a lot of ash flow along the tubes and
consequently are prone to erosion.
2. Any tube failure results in a lot of downtime and
repair work, as the water reacts with CaO and
forms huge blocks of gypsum by the time the
boiler cools down.
3. Removal of these blocks by pneumatic drills
around the air nozzles is a difficult task during
which a few nozzles may be damaged.

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Operational Practices that Leads to Bed
Agglomeration
1. High combustion temperature >= 1000 0C
a) Unstable combustion
a.1) high coal moisture content
a.2) low bed material inventory
a.3) firing of oversized/undersized coal
b) Faulty instrumentation
b.1) plugged instrument
b.2) outdated calibration
b.3) inappropriate location of installed instruments
c) Insufficient fluidization air and fluidized velocity
c.1) plugged bed nozzles
c.2) operators error during fuel switching
c.3) high bed material inventory
d) Over firing
Agglomeration
2. Poor coal ( fuel ) quality
A. High alkaline content
• high in sodium and potassium content
• natural properties
• contaminated with seawater
B. Inappropriate coal size
• oversize
• too fine
C. High moisture content greater than 30%
D. Muddy
• accumulated in mine site

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Agglomeration
3. Bed material ( sand ) in furnace.
A. Low ash fusion temperature of inert material< 1250 0C
B. Exceeds the design particle size distribution
C. High moisture content
D. High acid-soluble alkali ( Na2 + K2 ) and Chlorides ( Cl )
• contaminated with seawater
E. High bed material inventory
• Faulty instruments, Differential Pressure Transmitter
• Dysfunctional bottom ash removal system
Agglomeration
4. Operational practices/conditions
A. Boiler tube leak
• Overheating due to deposition ( inside and outside of tube)
• Seam cut due to faulty soot blowing
• Sandblasting, corrosion
B. Excessive limestone injection
C. Long duration of low loads operation of boiler less than 40 % of MCR.
D. Misoperation

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Boiler Auxiliaries
The auxiliaries breathe life into the static boiler made of pressure parts (PPs) and
non-pressure parts (NPPs). The auxiliaries, generating and regulating the flows, are
present in the following two circuits:
1. Air and gas circuit that comprises
a. Fans
b. Dust-collecting equipment
c. Dampers
2. Steam and water circuit that comprises
a. Feed pumps and circulation pumps
b. Valves, mountings, and fittings
c. Soot blowers (SBs)
Soot blowers are aid not involved in the movement and control of fluids but in
removing the soot or dust deposited on the heating surfaces (HSs) of the boiler.
They are unique to the boilers.
Salient Aspects of Fans

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Fans in Boiler Plant
Fans are perhaps the most important of all
the auxiliaries because they affect the boiler
• Performance
• Auxiliary power consumption
• Dynamics
Salient Aspects of Fans
• A fan can be defined as a volumetric device, that
moves air or gas from one place to another,
overcoming the resistance to flow.
• Fans overcome static forces. Total pressure,
however, includes velocity head, which is due to
kinetic energy.
• As a volumetric device, a fan gives output in cubic
meters and generates head in millimeters water
gauge and not in kilograms and millibars. The
weight and pressure are the derived figures,
depending on the density or specific volume.

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Boiler Fans
• Forced draft fan is the main air fan whose
prime job is to deliver the combustion air to
the firing equipment in a balanced draft
boiler. In a pressurized boiler, the FD fan has
to further push the gases formed in the
combustion chamber up to the chimney
exit.
• Primary air fan in CFB boilers draw hot air
from the discharge of AH and push the hot
PA through the wind box that fluidized the
bed materials in the furnace.
Induced draft fan, employed
only in balanced draft boilers,
suck the combustion gases
from the furnace and discharge
them at the stack exit. They
maintain a nominal suction of
5–25 mm wg in the furnace to
avoid flames leaping out, and
ensure operator safety and
prevent the insulation and
casing from burning out.
Valves and Mountings
Valves, mountings, and fittings are the auxiliaries in the steam and water circuit.
The mountings and fittings are the mandatory safety devices specified by codes for
permitting a boiler to steam. These are:
• Main steam stop valve (MSSV)
• Non-return valve (NRV) on steam line
• Safety valves (SV)
• Blow-down valves
• High–low water-level alarms on steam drum
• Water-level indicators (WLI) on steam drum
• Pressure gauges on steam drum and SH

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Existing problems:
Erosion & Corrosion
Operation and Maintenance issues
Serious Abrasion and Poor Reliability of
Equipment
• In the operation process, a CFBB is in the state of
high particle concentration and high working air
flow rate.
• The abrasion problem is serious for the heating
surfaces of:
1. Water cooled wall
2. Superheater as arranged in the furnace
3. The air button on air distributor below the
furnace
4. The junction of water cooled wall and fire-
resistant material in dense-phase zone
5. The cyclone separator at furnace outlet
• The proportion of fly ash in flue gas of a CFBB is
lower than that of PC boiler, due to larger
particle size of fly ash, obvious abrasion
problems can be found at the heating surfaces,
such as the superheater, economizer and other,
arranged in the Flue gas pass of CFBB.

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Coking and Burning Loss of Air Distribution
Device
• The direct cause of coking is the local or whole temperature of
bed material exceeds the ash fusion point or the sintering
temperature.
• Low-temperature coking always occurs in the bed for starting and
idling. During idling period of the boiler, the bed materials are in
static state.
• If any air is leaked in, combustible matters contained in hot bed
materials may ignite due to the acquisition of oxygen. Since the
heat generated by combustion can not be taken away in time,
coking may take place due over temperature of bed materials in
local areas.
• If the carbon content in bed materials is excessively high and the
bed temperature is not controlled by regulating the air flow or
material recycle rate, the bed temperature will go up sharply, the
results is coking.
• If the bed temperature exceeds the ash fusion point, high-
temperature coking will take place.
• Coking may lead to burning loss and deformation of air button.
Large Ventilation Resistance and High
Power Consumption of Fan
• In order to keep the fluidized state of solid materials in the boiler in the
operation process of a CFBB, a large amount of high-pressure fluidized
air should be supplied to overcome;
o The resistance of air distributor and bed materials
• CFB Boiler has high ventilation resistance, complicated air system and
high power consumption of fan that leads to high plant service power
consumption rate.
• Generally, the plant service power consumption rate of a plant with a
CFBB is 4 ~ 5% higher than that with a coal powder boiler.

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Refractory Problem
Wind Box Problem

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Difficulty in Achieving Automatic
Combustion Control
• Combustion control is the difficult and key points of automatic control
for the whole CFB boiler.
• Particularly, the coupling relation is high among feed coal, primary air,
secondary air and material recycle rate, which means that a change in a
single parameter would cause synchronous change of other parameters.
• In addition, due to its strong nonlinearity, time-varying characteristics
(major change may be found in the quality of the same batch of coal)
and large lag characteristics, the objects to be controlled are very
complicated.
• The application of conventional PID control could not achieve the ideal
control effect, which makes the automatic combustion control of a CFB
boiler is much more difficult than that of a coal powder boiler.
Upsizing
Restricted by technology and auxiliary equipment,
the unit capacity of a CFBB is smaller than that of a
Pulverized Coal boiler. The maximum unit capacity of
CFBB that has been put into operation is 600 MW.

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Damage Modes
1. Corrosion damage leads to untimely production upsets, costly equipment
failures and lost opportunities
2. Failure analysis an effective tool in establishing true root cause of failure
3. Root cause determination provides a path to effective corrective actions
4. Common corrosion mechanisms and case histories presented
Boiler tubes degrade for one of four reasons:
• They have been chemically attacked or have developed thick
deposits/oxide scales on their fluid side
• They have experienced fireside wastage
• They have experienced short- or long-term overheating or
• They have been stressed above their ultimate strength or repeatedly
stressed above their fatigue limits.
Corrosion Mechanisms
Overheating
– Short Term
– Long Term
• Hydrogen Damage
• Caustic Gouging
• Oxygen Attack
• Thermal Fatigue
• Flow Assisted Corrosion

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Failure Mechanism
Thermal excesses and/or inadequate flow led to DNB/steam blanketing .
• Scab-like deposits formed.
• Anions concentrated beneath iron deposits and created a corrosive
environment.
• Tubes thinned as a result of corrosion.
• Internal pressure overcame the thinned tube wall.
Failure Mechanism- Operating Conditions
• Gas side temperature increases reduce mean time to failure
• Pressure fluctuations cause significant increase in steam volume
• Potential exists for overheating due to steam stalling
• Boiler operated at maximum (and beyond) capacity

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Failure Mechanism - Operating Conditions
• Thermal cycling disrupts iron oxide film
• Spalled iron oxide accumulates further down in tubes
• Boiler water penetrates chip scale
• Wick boiling concentrates boiler water solids to percent levels
• Tube wall thinning results from over concentration of solids
and acid attack due to hydrolysis by Cl or SO4 anions
• Maximum allowable stress is exceeded due to thinning
Corrective Actions & Recommendations
• Improve boiler circulation
• Control intrusion of corrosive anions
• Maintain a buffering chemistry in the boiler water
• Modify boiler operation to avoid DNB

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Boiler Tube Failures (22 Primary Mechanisms)
Stress Rupture Fatigue
Short term overheating Vibration
High Temperature Creep Thermal
Dissimilar Metal Welds Corrosion
Water-Side Corrosion Erosion
Caustic Corrosion Fly Ash
Hydrogen damage Falling Slag
Pitting Soot Blower
Stress Corrosion Cracking Coal Particle
Fire-Side Corrosion Lack of Quality Control
Low Temperature Maintenance Cleaning Damage
Water Wall Chemical Excursion Damage
Coal Ash Material Defects
Oil Ash Welding Defects
Boiler Tube Failures (22 Primary Mechanisms)

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Erosion Phenomenon in Boilers
There are many locations possible
1. Erosion in the end coils which come closer to the water wall / cage wall
2. Erosion in the coils inside the bank
3. Erosion at the penetrations in the roof / side wall / casing
4. Erosion in coils facing ash impingement
5. Random erosion inside the bank due to ash clogging
6. Preferential erosion near hanger supports
7. Erosion caused by soot blower
8. Preferential erosion due to layout related mechanism
9. Erosion due to ash fouling
Erosion Processes
• Erosion is associated with solid fuel fired
boilers.
• The cause can be;
• Defective design
• Defective erection
• Improper operation & improper
maintenance.

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Causes Attributed to Design
1. Design with high gas velocities
2. Design without considering normal dust flow pattern expected within the tube
bank
3. Design without considering the preferential gas flow upstream / downstream
of the tube bank
4. Design without provision for controlling the preferential flow
5. Design with narrow clearance between tubes
6. Design without proper lateral spacers to maintain the longitudinal / transverse
pitch of tubes
7. Design with possibilities for impingement erosion
8. Failure to provide the sacrificial tube shields near soot blowers
9. Improper design of flow dividers
10. Failure to provide proper sealbox at places where the tubes enter inside the
gas path
Causes Attributed to Erection
1. Improper erection
methods resulting in
irregular pitching of tube
banks
2. Improper / incomplete
erection of protective
shields / gas baffle
3. Incomplete erection of
seal box

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Causes Attributed to Operation
1. Operation of the boiler
beyond the design
parameters
2. Operation of the boiler
without understanding the
fuel characteristics /
Operation of the boiler with
fuels not designed for.
Causes Attributed to Maintenance
1. Failure to ensure the design
pitching is maintained during
tube replacement
2. Failure to observe the pattern of
erosion and to take remedial
advice from manufacturer.
3. Failure to fit the gas baffles &
tube shields / sealing
arrangement after the tube
replacement
4. Decision to retain the distorted /
plugged coils within the flue path

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Erosion Processes
• Most of our understanding of erosion mechanisms of brittle and ductile
materials relates to room temperature.
• For the erosion-corrosion of metals at high temperature, the primary
requirement is to understand the behavior, under erosion, of a scale on a
deformable substrate.
• The scale may be regarded as thin or thick, depending on whether or not the
deformation on impact extends to the metal.
Corrosion of Air Preheater Tubes of CFB
Boilers
• The damage to gas air heater (GAH) plates in the zones where air and gas
temperatures are low discovered in CFB boilers was indicative of low-
temperature corrosion (LTC).
• The measured dew-point temperature of sulphuric acid in a pulverized firing
(PF) boiler is 75-80 0C. The maximum chlorine content of the deposits collected
from a probe tip inserted in a PF boiler’s gas flue is ~6%.
• The measured dew point temperature in a CFB boiler’s gas flue is 55-60 0C. If the
probe tip was contaminated, dew-point temperature rose to 75-80 0C. Chlorine
content of the deposit samples collected from a CFB boiler was ~3%.

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Boiler Control Strategies
1. Coordinate boiler with turbine
• Match generation to demand – Automatic Generation Control (AGC)
capability to trade in energy market
• Advanced Model Predictive Control (MPC) – provides correct demand to
turbine and boiler under all conditions
• Match boiler inputs with turbine energy requirement – maximize efficiency
2. Compute and control true “heat release”
• Detect changes in fuel heating value – maintain constant steaming rate
• Totalize “heat release” from all sources – maintain constant overall fuel flow
• Maintain proper fuel air ratio over entire load range – maximize efficiency
3. Optimize bed/furnace temperature
• Maintain temperature within operating range - lower limestone usage
• Maximize sulfur calcium association – lower SOx emissions
• Lower overall combustion temperature – lower NOx emissions

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Let us not forget the Main Purpose of this
Plant… Generate Electricity
• Must control generation to demand
• Must provide AGC capability
• Must operate at maximum rate of change
• Must protect the unit when equipment is not
performing at optimal conditions
Bed material and temperature management:
Good bed management:
• Lower emissions
• Lower agglomeration
• Greater turndown
• Stable combustion
Poor bed management:
• Higher emissions
• Forced outages
• Less stable combustion
• Higher agglomeration due to hot spots

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Control Logics Brief
• ID Fans trip J seal fans trip
• J Seal trip SA trip PA trip
• Furnace pressure very low ID trip
• Furnace pressure very high SA trip
• Bed temp low PA trip
• Bed level low Ash cooler stop
• Bed temp high Burners trip
Coal feeders trip
• Drum level very low MFT
Control Logics Brief
• Furnace pressure By ID fan ( VSC / Dampers)
• Total air By PA + SA (VSC / Dampers)
• O2 By SA
• Steam pressure By coal feeders (VFD) + fans
• Bed level Ash coolers (VFD)
• Bed inventory Coal + bed materials + limestone
• Bed temperature Coal feeders (VFD)
• Steam temperature Attemperator / dampers cascade

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Boiler Tube Failures
• Availability and reliability of boiler decreased with increased tube failures.
• Tube failure results in forced outages and hence direct impact on availability
• Boiler Tube Failures - main cause of forced outages in electric utility steam
generating boilers.

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Boiler Safety
Boiler Safety
Boiler Control System
Control the operation of
valve and actuators
Monitor Critical control
Functions for the
Safe operation of
The boiler•Unaware
•Unable
•Unmotivated
•Behavioural
•Unidentified
•Uncorrected

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Process Safety Management
Why Safety?
• Save lives and properties
• Care about people
• Achievement of corporate goals
• Corporate Citizenship
• Employees’ motivation
• Industry Level for Productivity
• Quality Consciousness
• Business Profitability
• Competitive advantage
• Industrial Peace
• Company Reputation
• Leaders’ Reputation

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Facts
• Literally hundreds of thousands
of workers are injured on the
job each year, and so many of
these workers die from
accidents in the workplace.
• Occurrence like these should be
good reasons to take safety
seriously, and to have a positive
attitude toward safety on the
job.
Boiler Safety
Problems that workplace accidents can cause.
• Lost work time – keeping you away from the job and costs you
money
• Lost productivity time – time could be spent working productively
to meet goals and build a successful organization.
• Lower morale – since no one wants to come to work at a
hazardous workplace
• Higher costs – rising insurance and legal costs that can restrict
employees’ ability to earn more money, and even put a company
out of business
• Painful injuries – these could be permanent, affecting the quality
of a worker’s life until he or she dies.

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Boiler Safety
Causal Factors – Boiler
Accidents
• Maintenance
• Lockout
• Startup / Re-ignition
• Falls
• Carbon Monoxide /
other gases
One Mistake could be Fatal

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Wisdom
is the
ability to
learn
from
change
Unit Trip Interlock

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Boiler Safety Systems
1. Alarm Systems
2. Emergency Shutdown (ESD) Systems
3. Flame Detectors
4. Startup Interlocks
5. Safety Valves
6. Non-Return Valve
Protections are Classified Under Three Groups
1. Protection causing complete shut down of the unit.
2. Protection causing load reduction of the unit.
3. Protection causing annunciation only.

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Plant O & M Operating Consideration
1. The prime consideration for all operation is the safety of people and equipment.
2. Whenever there is any doubt about an unsafe condition, the operator must take
immediate action to return the unit to a known safe condition even if it means
tripping the unit.
3. As the loss of a unit even during peak-load requirements is not as important as a
human life or the downtime for a major repair
4. The two most dangerous conditions remain the same today as throughout the
history of steam generation:
• The loss of water
• The explosive mixture of fuel and air.
As an Operator you are a Preventor – Prevent bad things from happening
Protections Causing Annunciation
These interlocks & protection systems are divided into two portions based
on the area they cover as briefly described below.
1. Boiler auxiliaries interlock & protection
This system takes care of sequence of starting, protection and interlock
of boiler Auxiliaries like FD fans, ID fans, Air-heaters, Dampers, Valves,
etc.
2. Furnace safeguard supervisory system (FSSS)
This system takes care of interlocks required for starting, supervising
the operating and safe shut down of the equipment connected with
fuel firing system.

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Boiler Interlock
• An interlock is a feature that
makes the state of two
mechanisms or functions
mutually dependent.
• It prevents incorrect operation
to avoid possible damage of
equipment.
• Interlocks can be considered as
start permissives of any
equipment.
Boiler Protections
DESCRIPTION
VALUES TIMER
(SEC)
NORMAL ALARM TRIP
DRUM LEVEL VERY LOW (
MM)
0 -100 -285 5
DRUM LEVEL VERY HIGH
(MM)
0 +100 +295 10
FURNACE PRESSURE VERY
LOW (MMWC)
- 10 -100 -175 -
FURNACE PRESSURE VERY
HIGH (MMWC)
- 10 +75 +150 -
AIR FLOW < 40% (T/HR) 400 215 158 -
BOTH ID FANS OFF - - TRIP --
BOTH FD FANS OFF - - TRIP -
REHEATER PROTECTION TRIP - - TRIP 10
UNIT FLAME FAILURE - - TRIP -
LOSS OF FUEL - - TRIP -
LOSS OF 220V DC MFT
POWER
- - TRIP 2
CRITICAL I/O MODULE FAIL - - TRIP -
MFT ACTED - - TRIP -
EMERGENCY TRIP SWITCH
ACTIVATED
- - TRIP -
• The state of action to
prevent possible damages
of any equipment or
system.
• It is necessary to safeguard
the equipment against
abnormal deviation of
process parameters to
unacceptable values .

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Furnace Purge
• To remove out combustible gases
• To assure all fuel are isolated from
furnace
• Before starting first burner for
cold start
• If bed temperature < 600 0C or
OEM recommend and no burner
in service
• Total air flow > 50%
• 300 second for purging time.
Unit Trip Interlock
• The safe and economical operation is carried out at coal fired power plant while
carefully checking environmental problems, there are many points that operators
must judge to take appropriate measures.
• A large load is applied to operators in case of an emergency.
• Therefore, it is necessary to
1. Automate emergency manual operations to be taken against faults
2. Automate normal manual operations in order to minimize operators’
judgments.
3. To keep the final protection of the plant, it is absolutely required to take
appropriate measures for the plant facilities.
• A unit protection device is installed to protect each unit if a fault occurs and it
becomes difficult to continue safe operation of the unit.
• This unit protection device is called the “unit trip interlock.”
1. Boiler protection interlock (MFT)
2. Turbine protection interlock (MTS)
3. Generator protection interlock (86G)

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Unit Trip Interlock
Basic interlock circuit
Problem on generator side
Problem on turbine side
Problem on boiler side
Generator Trip
Turbine Trip
Fire Extinguishing of boiler
Unit Trip Interlock - Boiler Protection Interlock
(MFT)
• This boiler protection interlock is intended to shut down
the fuel supply to stop the boiler if it becomes difficult
to continue stable combustion of the boiler.
• The conditions for tripping of this interlock may vary
slightly depending on the type of boiler, that is, whether
it is drum boiler or a once-through unit boiler.
• Generally, these conditions are fuel pressure drop, high
furnace pressure, stopping of two ventilating fans,
protection of the reheating unit, supply water flow rate
drop, and drum level drop.
• In addition to these conditions, unit emergency stop and
turbine/generator trip conditions are interlocked.
According to the boiler model, further conditions are
interlocked.

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Unit Trip Interlock - Turbine Protection
Interlock (MTS)
• If it becomes difficult to continue stable operation of the
turbine, the solenoid is operated to stop the turbine.
• The conditions for tripping of this interlock are turbine
overspeed, thrust error, bearing hydraulic pressure drop,
and degree of vacuum drop.
• In addition to these conditions, the unit emergency stop,
turbine manual stop, and generator trip conditions are
interlocked.
Unit Trip Interlock - Generator Protection
Interlock (86G)
• A status where stable operation of the generator or
transformer is difficult, it is only detected by the
protective device or protective relay.
• After this, the generator is disconnected from the
system and the turbine is tripped to stop the
generator at the same time.
• The conditions for detection of the protection are
ratio differentiation of the generator, loss of
excitation, ratio differentiation of the ground fault
or transformer, impulse hydraulic pressure, over
excitation, etc.
• In addition to these conditions, the high/low
frequency of the system and the protection of the
bus-bar are interlocked.

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Boiler Auxiliaries Interlocks and Protection
• Failure of any equipment calls for expensive replacement and results in costlier
down time.
• This emphasizes careful planning on the correct procedure for;
1. Safe sequence of start-up of equipment's in the power plant.
2. Continuous trouble free & efficient operation.
3. Safe sequence of shutdown of the equipment when needed.
4. This also leads to provision of adequate & reliable protection to safeguard
the various plant equipment's under abnormal and dangerous conditions.
5. The operation of the protections shall be accompanied by visual and
audible annunciation, which provide definite indication of the primary
cause or causes of operation of the protection.
6. Restarting of the equipment, which has once been tripped by protection
either by remote, automatic or manual control shall be possible only after
the elimination of the cause of tripping.
Protection Device Tests
Protection device tests during operation
• The important point during plant operation is that the plant can be stopped
safely in case of an emergency.
• To maintain this safety, it is necessary to periodically check the operation
status of various safety prevention apparatus installed for protection of the
plant. Table below shows examples of the protection device tests.

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Protection Device Tests
Interlock & Protection
Description
Interlock & Protection of Boiler Interlock test checklist of fuel oil system
Interlock & Protection of ID fan system Interlock & Protection of Turbine
Interlock & Protection of FD fan system Condensate Extraction Pump (CEP)
Interlock & Protection of APH system Circulating water system
Interlock & Protection of PA fan system Boiler Feed Pump Interlock & Protection
Interlock & Protection of Coal Feeder Vacuum system
Interlock & Protection of Seal Air Fan Lube oil system & EH oil system
Interlock & Protection of Scanner Air Fan Deaerator, HPH & LPH system
Interlock of Boiler Main steam and drainage system
Interlock & Protection of FSSS Bypass system
Interlock test checklist of steam and
water system
Turbine

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Boiler Operation Control during Normal
Operation
• It must be strongly attempted to find the error status early
and to prevent problems during normal unit operation in
order to maintain stable operation status.
• The actions to be actually taken are basically classified into
the inspection at the work field, and the sampling and
evaluation of the operation records.
• It is important to take these actions daily in order to check
status change in the early phase, and this leads to
appropriate actions and measures being taken in a timely
manner.
Protections Causing Complete Shutdown
of the Unit
1. Failure of all feed pumps (i.e.) reserve feed pump if any, fails to start on
tripping of running pumps even after a preset time delay.
2. Boiler shutdown due to failure of both FD fans, both ID fans, Air heater and
other conditions.
3. Reheater protection, which is to ensure continuous steam flow through
reheater tubes at, specified conditions.

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Protection Causing Load Reduction
1. ID fans: Two ID fans are required for boiler MCR. If any one of the
two running ID fans trips, the boiler load shall be run down to 60%
MCR.
2. FD fans: If any one of the two running FD fans trip, the boiler load
shall be run down to 60% MCR.
3. Cooling Water Pumps, PA fans & Coal Feeders: This reduces the boiler
load correspondingly due to limitations in fuel firing capabilities.
Protections Causing Annunciation
These interlocks & protection systems are divided into two portions based on the
area they cover as briefly described below.
1. Boiler auxiliaries interlock & protection This system takes care of sequence of
starting, protection and interlock of boiler Auxiliaries like FD fans, ID fans, Air-
heaters, Dampers, Valves, etc.
2. Furnace safeguard supervisory system (FSSS) This system takes care of
interlocks required for starting, supervising the operating and safe shut down
of the equipment's connected with fuel firing system.

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Inspection at the Work Field
• As a rule, the inspection interval must be every work shift.
• Walk around inspection of the boiler main unit parts and boiler auxiliary devices
• The inspection results must be kept.
• Generally, walk around inspection is carried out according to the checklist.
• Further inspection points, such as unusual noise, unusual odor, or discoloration must
also be inspected.
• The combustion status inside the furnace must also be checked during walk around
inspection.
• If the type of coal to be used is changed, the inspection must be carried out with
special attention.
• One of the points to inspect the status of clinker and ash sticking to each heat transfer
surface inside the furnace is to check whether or not excessive development or
accumulation exists.
• The other point is that the contamination status of each heat transfer surface is
checked.
Sampling and Evaluation of Operation
Records
• To grasp the secular change in the boiler static characteristics and to
evaluate performance records of the boiler operated at its rated output
are sampled periodically.
• In daily operation, it is basically checked whether or not the balance
among the feed water flow rate, fuel flow rate, and air flow rate is correct.
• As deviation of the boiler input command to the output command and
deviation of the water/fuel ratio and air/fuel ratio are checked, it is
possible to judge whether or not the balance is correct.
• Additionally, it must be strongly attempted to check changes in the make-
up water quantity in order to find any boiler tube leak in the early phase..

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Boiler Control System
What is Alarm Management?
Process by which alarms are engineered, monitored,
and managed to ensure safe, reliable operations

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Layer of Protection
The intent of these alarms is to warn operators of an impending abnormal
situation, which can often have safety related consequences.
In determining the average Probability of Failure on Demand for a System
Integrity Level loop that contains an alarm as a Layer of protection, the
probability of the operator failing to adequately respond to the alarm must be
considered
1. Continuous Lifecycle
Alarm management is a lifecycle process based on a continuous improvement process.
If the alarms and associated plant and equipment are not regularly maintained then it
is most likely the system performance will degrade over time.
2. Plant Maintenance/Reliability
Good plant maintenance practices are absolutely critical in terms of plant production
rates, safety, and alarm system performance. Poor practices can result in chattering
alarms, ineffective instruments, false alarms and safety related incidents.
3. Good Process Control
Good process control assists in minimizing the probability of abnormal situations from
occurring due to interlock failure, incorrect logic configuration or uncontrolled PID
loops. Typically poor process control also results in operator actions, chattering alarms

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4. Outcome of a Risk Assessment
Every task that is required within a power plant should be subject to a risk assessment,
including determining the requirement to use an alarm to minimize the risk potential.
This should be considered simply good engineering practice.
5. Related to Equipment Failure
All manufactured equipment eventually fails with time! Unfortunately some companies
rely too heavily on the higher LOPs (safety systems, pressure relief valves) to protect
the integrity of their plants. All safety equipment has a probability to fail on demand
and should only be employed as a last means of defense..
6. Enhanced/Advanced Control
There have been significant developments in smart alarming techniques such as state-
based alarming, model-based alarming and predictive alarming. These techniques are
used to improve the performance of the alarm system as well as minimizing the chance
of abnormal situations from occurring.
7. Abnormal Situation Management
This is all about allowing the operator enough time and resources to prevent an
unusual event from occurring. The power design team has undertaken significant
research into graphics, control systems and alarm systems for abnormal situation
management.
8. It Has Been Widely Ignored for a Long Time
On many sites the operators ignore the alarms as the systems are unusable in their
current state. There are still chemical plants, coal preparation plants, refineries, power
stations, where this is the case!
9. Often Used In Fault Tree Analysis
Fault Tree Analysis is a common method of undertaking quantitative risk assessments.

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Major Boiler Operating Variables,
Monitoring and Control
1. Steam Drum Level/BFW Rate
2. Boiler Blowdown
3. Steam Drum Pressure/Steam Production Rate
4. Fuel Flow/Pressure
5. Air Flow
6. Fire Box Pressure
7. Excess Air/Oxygen
Steam Drum Level/BFW Rate
The objective of the steam drum level
control is to:
1. Control the drum level to the set point
2. Minimize the interaction with the
combustion control system
3. Make smooth changes in boiler water
inventory as boiler load changes
(shrink/swell)
4. Properly balance the BFW input with
boiler steam output
5. Compensate for BFW pressure variation
without process upset

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Boiler Blowdown
1. The boiler blowdown rate from the steam
drum is continuous to control the
circulating boiler water quality.
2. The continuous blowdown may be
controlled by an on-line conductivity
analyzer.
3. Conductivity is proportional to the total
dissolved solids in the boiler water but can
be calibrated for any impurity.
4. Large rapid changes in the steam drum
blowdown rate can adversely affect the
steam drum level control
Steam Drum Pressure/Steam Production
Rate
1. The steam production rate is proportional to the firing rate.
2. The steam pressure is the primary control of firing.
3. As user demand increases there is a slight decrease in pressure until firing
rate can be increased so that steam production will match steam demand.
4. The reverse holds true for a decrease in steam demand. In a single boiler
installation the steam pressure controls the firing directly.
5. The steam rate controls the firing rate on each boiler.
6. The master controller can allocate steam rate to based on the boiler size or
on a least cost basis.
7. Steam production can drop off if the heating value of the fuel decreases.
8. In a single boiler installation, the reduced steam flow will result in decreased
steam pressure which will correct the firing.
9. If there are frequent fluctuations in fuel quality, firing controls can be made
more responsive by adding a fuel heating value feed-forward control
component.

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Fuel Flow/Pressure
1. Fuel flow is controlled to meet a boiler demand by the firing control
signal through the combustion control system.
2. Fuel flow can change due to boiler load changes and from heating
value changes in the fuel.
3. Fuel flow should not be a function of fuel supply pressure.
4. Supply pressure to the control valve should have an independent
control
5. Fuel flow will be shut off in a boiler shutdown event by BMS
6. The fuel flow will also be shutoff on air failure in a forced draft
system.
7. On boilers with the ability to burn both coal and oil fuels the
combustion control system can control the rate of either fuel but not
both.
8. When both fuels are fired, the oil rate is usually controlled by the
number of oil burners in service and the coal flow rate is controlled
by the combustion control system.
Air Flow
1. In a forced draft boiler air flow is controlled in proportion to fuel flow
by a flow ratio controller.
2. The air flow is measured by a minimal pressure drop flow
measurement such as a venturi.
3. The air to fuel ratio is normally fairly constant in most systems
because ratio does not change rapidly with heating value and the
heating value of the fuel is usually fairly constant.
4.
5. The air to fuel ratio may need to be adjusted when there is a major
change in fuel heating value, because higher heating value fuels
require more air for complete combustion.
6. Air flow from fans is normally controlled by throttling the suction of
the forced draft fan to minimize power usage.

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Furnace Pressure
1. The stack creates a draft (negative pressure) but the amount of draft
available in the firebox is a function of the pressure drop through the fire
box, convection section, stack damper and stack.
2. The lowest draft (highest positive pressure) in the boiler occurs at the
burners.
3. The highest draft (lowest pressure) occurs at the exit of the boiler. Note, the
outlet pressure of the boiler could be positive with a preheater. In boilers
with a positive pressure firebox, the firebox must be well sealed because
leaks of hot gases can damage the boiler structure since the structural
members are designed to operate at low temperatures.
4. The observation ports must be sealed with fire resistant glass and openings
for removing burners must have a sealing system to prevent escape of hot
gases.
5. The firebox pressure should be controlled at a constant value because
changes in the firebox pressure will change the differential pressure across
the burner.
6. Differential pressure swings will result in swings in the air flow. Swings in air
flow can result in changes in flame pattern which can affect tube metal
temperatures.
Excess Air/Oxygen
1. Excess air and excess oxygen are numerically equivalent since air always has
21% oxygen. Percent excess air or oxygen is defined as the amount of air in
excess of that required for complete combustion divided by the amount of
air required for complete combustion times 100.
2. Excess oxygen is not the oxygen concentration in the stack. Excess air is
controlled by the air to fuel ratio controller.
3. An oxygen trim control system may provide automatic control of excess
oxygen (air) using the stack oxygen analyzer to adjust the ratio of air to fuel.
4. Carbon monoxide analyzers are recommended but are to be used only for
monitoring and alarming

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“Total System” Interaction of Variables
1. Tuning of the control system is very important to prevent unwanted system
interaction.
2. For example the level control can affect the firing rate by swings of the cold
BFW rate into the steam drum.
3.
4. If the system is not properly tuned swings in the BFW rate can result in firing
rate swings which will then affect the level control because of the changes in
shrink and swell and cause further swings in the BFW rate.
5. This swinging could be started by a change in steam demand. Interactions
can also occur in other systems such as the draft control and the firing
system, blowdown and steam drum level control, etc..
Consequences of Inadequate Control
• Inadequate control can result in overheating of
tubes with the results.
• Other consequences of inadequate control include
carryover of boiler water into the steam system,
boiler explosions, lifting safety valves, etc..

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Power Plant Start-up
• The Power Plant operation instruction can only supplement the
experience and judgments of personnel in charge of operation.
• It shall be interpreted and applied after giving careful
consideration of the requirements of other relative equipment
and for any particular set of circumstances.
• All of the operation instruction does not purport to cover all
details or variations of equipment, including every contingency to
meet during operation and / or maintenance.
• As the successful operation and performance depend greatly
upon auxiliary systems, coal feed system, air & gas system, bed
material extraction system, Limestone Feed System, etc. shall be
understood as fundamental requirements of the boiler.

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Start-up Preparation
• Start-up Power Availability
Plant shall be provided with two numbers of Station
Transformers, used to draw unit start-up and Station
auxiliary power from 138kV switchyard.
STG shall step down switch yard voltage of 138 kV to
4.16 kV level and feed station and unit loads.

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TYPES OF START-UP
COLD START (Shutdown > 56 hrs.)
WARM START (8 hrs. to 56 hrs.)
HOT START(< 8 hrs.)
Boiler & Turbine
Ramp rate and estimated start up time until 100 % load.
BOILER
COLD START
Furnace Temperature Ramp Rate 120 °C / hr
Expected time required for start up 6 ~ 8 hrs
HOT START (Auxiliaries equipment in service)
Furnace Temperature Ramp Rate 120 °C / hr
Expected time required for start up 1 ~ 2 hrs

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Boiler & Turbine
Ramp rate and estimated start up time until 100 % load.
TURBINE
COLD START 1.00% / min 1.5 MW/min 2.5 hrs
WARM START 1.32% / min 1.98 MW/min 1.7 hrs
HOT START 2.38% / min 3.57 MW/min 0.83 hr
Estimated Time of Start Up from (0 ~ 100% Load)
Cold Start 10.5 hrs
Hot Start 2.83 hrs
Sequence of Unit start-up
 Water quality conditioning
 Turbine Barring and Generator accessories
 Draught System
 Boiler Firing
 Steam Temp.-Pressure raising and conditioning
 Turbine run-up
 Generator Synchronization

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Boiler Start – up
Sequence
Prepare before hand:
1. Supply Power system is normal
2. Instrument air/Service air in service
3. Cooling water normal
4. Feedwater condition normal
5. Fuel gas duct condition normal
6. Instrument/control valves/DCS ready
7. Fuel oil circulation establish
8. Vents/drain of drum and SH are opened
9. Lube oil System of equipment establish
10. GAH/ESP are ready
Furnace Purge Start
IDF Running
Furnace pressure set-up ; - 15 mm H2O
SAF Running
FA Blower Running
GAH Running
Adjust an air flow >25%
Furnace purge complete MFT reset
Start-up burner Light off
1. Strat-up burner gate open
2. Start-up burner air damper at
purge position (25%)
The speed of rise which depend on
furnace temp. < 153 0C/hr
Drum Water Level NormalFlue Gas Line Condition ready
ID Fan Inlet Damper Closed
PA Fan Vane opened
SA fan inlet vane opened
FA blower vent shutoff valve open
FA Blower inlet flow control vane at 30%
FA blower outlet shut off valve closed
All oil burner valve closed
Burner Flame detector off
All coal feeder stop
All col feeder outlet valve closed
Limestone rotary valve not running
No drum level low low alarm
No boiler trip command
PAF Running
All ignitor power on
Fuel oil system supply pressure normal
Oil shutoff valve opened
Secondary air dampers in furnace closed to 10%
SAF inlet vane closed
PF inlet vane closed
Boiler Start – up
Sequence
1. Feeding the bed material until
∆ P> 900 ῀1100 mmH2O
1. Heat up furnace temp > 500 0C
Start limestone injection
Ash Screw Cooler System Start
1. Feeding coal flow continuously (Low
furnace temperature > 600 0C
2. Reduce Fuel oil flow
If furnace temperature >650 0C, t=three fuel
feeder running continuously if furnace
temperature > 700 0C
Start retracting start-up burner
1. Feeding the coal by batch
2. Check CO, O2, Sox and lower furnace
temp. rising reaction
At boiler load >60 %
Boiler Automatic control
Adjust the fuel flow & air flow by boiler load
At boiler load > 60%
Boiler automatic control (Boiler Master
function)
Furnace Temperature 850 0C- 890 0 C
is maintained
The desuperheater in service for
the protection of overheat
• Solid fuel ready
• Solid fuel feeder in remote auto
• Slid fuel feeder no discharge
temperature high
• Solid fuel silo level not low
• Solid fuel silo outlet vale open
• Solid fuel feeder outlet isolation valve
open
• Solid fuel feeder speed demand at
minimum
Main steam converting station in service
Deaerator heating steam
If boiler drum Feedwater control valve
opening over 10%, then set drum level )mm
change to automatic mode
Bottom Ash conveyor start
ESP in Service

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COLD STARTUP
0
100
200
300
400
500
600
700
800
900
1000
0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00
TIME, HOURS
SUPERHEATEROUTLETTEMPERATURE,°C
SUPERHAETEROUTLETPRESSURE,ata
FURNACETEMPERATURE,°C
0
20
40
60
80
100
120
BOILERLOAD,%
Furnace
Temperature
SH Outlet
Pressure
Boiler Load
SH Outlet
Temperature
5 Min. Purge
Fire Burners
Turbine
Roll
Turbine
Sync
Start
Fuel
Shut off
Startup
Burners
Full Load -
Boiler
WARM STARTUP
0
100
200
300
400
500
600
700
800
900
1000
-4.00 -3.00 -2.00 -1.00 0.00 1.00 2.00 3.00 4.00 5.00 6.00
TIME, HOURS
SUPERHEATEROUTLETPRESSURE,ata
0
20
40
60
80
100
120
LOAD,%MCR
8 - 56 HOUR
SHUTDOWN
Furnace
Temperature
Boiler Load
Superheater Outlet
Temperature
Superheater Outlet
PressureSH Out. Press.
SH Out. Temp.
Furn. Temp.
Boiler Load
Start
Reducing
Fuel
Shut off Fuel,
Trip Turbine
5 Min. Purge
Fire Burners
Roll
Turbine Sync
Turbine
Start
Fuel Shutoff
Burners
Full Load
Boiler

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HOT STARTUP
0
100
200
300
400
500
600
700
800
900
1000
-4.00 -3.00 -2.00 -1.00 0.00 1.00 2.00 3.00
TIME, HOURS
SUPERHEATEROUTLETPRESURE,ata
0
20
40
60
80
100
120
BOILERLOAD,%MCR
< 8 HOUR
SHUTDOWN
Begin
Reducing
Fuel
Shut off Fuel,
Trip Turbine
Start Fans,
Blowers
Start
Coal
Turbine Roll
Turbine Sync
Full Load
SH Out. Press.
SH Out. Temp.
Furn. Temp.
Boiler Load Boiler Load
Furnace Temp.
SH Out. Temp.
SH. Out. Press.
Balance of Plant System Availability
Before initiating plant start-up, following utility systems are considered to be in
service/lined up for start-up.
CW system in service and Circulating Water to condenser circuit is established.
DM Water system in service, DM transfer pumps running Service Water System
Condenser/Hotwell, are filled up to the normal water level. Fire Water System
ACW system
Fuel Oil Forwarding System in service and fuel oil pressure at
Boiler Terminal adequate
CCW system Chemical Dosing System
Compressed Air System
All Boiler and Turbine drain valves are properly positioned for
star up based on OEM philosophy.
Turbine Bypass system is on Auto and available All MOV’s are in Auto and Available
Boiler Drum is filled up to optimum level All maintenance valves are closed
Service Water System
All prior trips of Boiler and Turbine are reset and NO fault
conditions exist.
Fire Water System HVAC system in service.

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Boiler Pre - Operation Checks
1. Flue gas path-to be clean and free of foreign objects
2. Cyclones and ash recirculation system - empty hoppers and clean recirculation
system
3. ESP- Cleaned and empty hoppers
4. Bed Ash Coolers - No leakage of air, and filled with sand up to required level.
5. Gas Air Heater - System checked for leakage and protections
6. Furnace-Bed material filled up to proper level
7. Fuel-Proper level in coal bunkers and Fuel Oil tank
8. Safety-required control and protection logics healthy
9. Pre-start up checks of the burners are satisfied.
10. All the HV/LV Motors are on / Auto selected and in Remote position
Boiler Start-up in Cold condition-COLD
START-UP
1. Start ID Fans
2. Start SA fans and get a flow of 10 kg/s for 5 minutes for complete purging of
the furnace.
3. Start PA fans to get PA flow more than 34 kg/s
4. Ensure proper fluidization of the furnace bed.
5. Start Fuel pump and ensure adequate fuel oil header pressure.
6. Start Boiler Feed pump and condensate pump for maintaining drum and
deaerator level. Ensure appropriate make up water to the hot well.
7. Start both HCG one by one and set the oil flow such that refractory
temperature does not go beyond 850C. Ensure slow heating of the refractory
and the boiler bed.

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Boiler Start-up in Cold condition-COLD
START-UP
8. Raise the temperature of boiler furnace bed slowly to avoid unusual thermal
expansion. While water starts boiling, close the drum vent at a drum
pressure of 2.0-3.0 kg/cm2. Throttle the super heater drains to crack open.
9. After attaining bed temperature of 350oC, start one center coal feeder
10. Take another coal feeder into service adjust PA and SA flow as per
requirement.
11. Maintain Bed Temperature <800C and raise slowly drum pressure to 93
kg/cm2.
12. The Main steam drain valves are operated during system start-up to drain the
condensate from the main steam piping and also to warm the system piping
as steam is admitted. Main Steam line charging will be initiated by opening
Boiler main steam stop valve when steam pressure reaches 5 kg/cm2 (or at
high pressure in case of warm / hot start).
13. Maintain MS Temp. 515oC (±5C), MS pressure and various other parameters
as specified. All controls can be put to auto mode after stabilizing the
combustion.
14. Gradually raise the boiler loading as per requirements of turbine side.
Auxiliary Steam Line and Gland Seal
system Charging
Auxiliary steam during start-up will be supplied from the main steam line.
Auxiliary steam consumption during start-up includes the following consumers.
• Deaerator initial heating
• Deaerator Pegging steam
• Turbine Gland sealing
• Turbine Steam Jet Air Ejector
Auxiliary steam source to turbine gland seal system to be established (including
required pipe warming) upon achieving auxiliary steam inlet pressure of 5 kg/cm2.
Auxiliary steam isolation valve is opened to warm up the line first and upon
achieving appropriate temperature the gland steam system can be put into
service.

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Main Steam Line Charging and Turbine
Bypass System into Service
• The Main steam drain valves are opened during system start-up to drain the
condensate from the Main steam piping and also to warm the system piping as
steam is admitted.
• Main steam line charging will be initiated by opening boiler main steam stop
valve when steam pressure reaches 5 kg/cm2 (or at higher pressure in case of
warm/hot start).
• 1x 60% (BMCR) Turbine bypass system is provided to control the main steam
pressure.
• During start-up before boiler is fired and all permissive for turbine bypass
system are satisfied turbine bypass will be put in to service under auto control.
• Once main steam pressure reaches 10 kg/cm2, turbine bypass valves are
opened. Steam pressure is then controlled by turbine by turbine bypass and
shall be increased gradually as per boiler pressurization curves.
• Turbine bypass will be operated as per boiler supplier recommendation from
boiler light off till the parameter (pressure and temperature) required for
turbine steam admission are achieved.
Vacuum Up
• For condenser vacuum building, gland sealing system to be established first.
• Once gland seals are established, condenser vacuum pulling can be initiated.
• During start-up both the ejectors inlet isolation valves are closed.
• Thereafter, both main and hogging ejectors are started and their inlet isolation
valves are opened for hogging operation.
• Once sufficient vacuum is established (to 0.3 kg/cm2) standby hogger shall be
stopped and respective inlet isolation valve to be closed.

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Bypass Control Mode
Turbine bypass valve controls builds up the main steam pressure by preset ramp rate
until the pressure reaches STG admission pressure of 30 kg/cm2 (for cold and warm
start up) and 40 kg/cm2 (hot start up).
And maintains at that pressure till main steam control valve takes over the control and
thereafter turbine bypass system changes over to tracking mode.
Once the main steam pressure reaches to steam admission pressure, turbine bypass
controller mode changes to pressure control mode.
Turbine bypass is operated so as to maintain the main steam pressure constant at
steam admission pressure.
As steam flow to turbine will gradually increases, turbine bypass will start closing
automatically.
Once HP bypass Valve opening is less than 2%, turbine bypass valve will be fully
closed. Then after turbine bypass will remain in auto mode (back up mode) to cater to
any emergency conditions.
Turbine Start-up
• Turbine start-up is performed by automatic turbine
run up system (ATRS) which is a part of turbine
control system, by providing acceleration, load
rates and hold times directly to the primary
controls.

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STG Rolling
Turbine start-up sequence is composed of three main phases:
1. Speed acceleration ramp from 0 rpm to 1st warm up speed (IDLE Speed)
2. Speed holding for the 1st warm Up for required time
3. Speed acceleration ramp from 1st warm up to rated speed
4. The turbine will be rolled by the ATRS sequence at suitable speed and
acceleration rate based on the casing temperature.
5. After all the STG pre requisites/ready to start conditions are ensured, and the
boiler steam parameters are matched to the STG admission needs (as per
STG start up mode), steam shall be admitted to the STG.
6. The STG will be rolled off and brought up to synchronization speed in
accordance with the STG accelerating program.
STG Synchronizing and initial Load
1. Generator synchronization will be done through auto synchronization
sequence (ASS) automatic synchronizing consist of automatically speed
matching and voltage matching, checking of phrase matching and
commanding the GSUT HV side breaker to close.
2. Once synchronization is completed, turbine will be loaded to 5% (to be
confirmed later) initial load.
3. Further STG load is increased - at a loading rate commensurate with the STG
start mode, by increasing steam flow into the turbine, accordingly the
turbine bypass valves will start closing gradually. When the turbine bypass
valve is opened less than 10%, the STG changes the mode from the load
control to the inlet pressure control. Thereafter, turbine bypass valve
changes from control mode to the tracking mode.

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Shutdown Procedure
1. The normal plant shutdown is considered from the unit operating at full load.
At this point plant is operating at 100% TMCR condition. Two/three coal
feeders are in operation depending upon the coal being used. Boiler
Feedwater requirement is being fulfilled by one BFP. One CEP in operation.
Turbine bypass system in auto and valves are in closed condition.
2. Target load to which load reduction is to be done automatically will be
selected by operator, also whether shutdown is to be done with condenser
vacuum up or not is to be selected by operator. However, if any of the
following condition occurs then vacuum break mode will be selected
automatically
• Condenser vacuum breaker valve open
• Condenser vacuum>later
3. Depending up on the selection, shutdown will be performed automatically by
executing various break points.
4. Steam turbine load will be reduced at a predefined rate of 1.5% / min up to
50% load (to be confirmed later). Once load is reduced to 50%, load hold of
around 30 min. (to be confirmed later). Will be initiated. Then load will be
reduced to minimum load condition at a predefined load rate of 1% /min(to
be confirmed later)..
Change over from Coal to Oil Firing
• Once all permissive for Fuel oil burner light off are satisfied, 3rd coal mill is cut
off below 35% load.
• Electrostatic precipitator shutdown sequence will be imitated. Oil firing will be
introduced to support further shutdown.
• Remaining two coal feeders will be gradually cut off as the load reduces towards
20%. Once all coal burners are cut off and at least one oil burner is in operation
then fuel changeover is deemed to be completed.
• Subsequent shutdown will be performed with the help of oil firing only.

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STG Trip and Bypass Operation
Turbine load will be reduced to minimum load condition. After the
minimum shutdown load is reached (<5%) STG shall trip on reserve power
protection due to the closing of the main steam stop valve and respective
STG GSUT circuit breaker shall open.
As soon as turbine is desynchronized, turbine speed decreases at a
predefined gradient and once speed reaches near to zero speed, turning
gear is started. Turbine bypass valve will open to maintain the upstream
pressure at floor pressure.
Boiler Shutdown
Once steam turbine is tripped, boiler shutdown is performed in following steps:
• Last fuel oil burner shutdown
• Primary air fans shutdown
• When oxygen reaches above 15% and bed temperature reaches below 700 degc stop PA
fans one by one.
• Ensure the CO vent valve is open after PA fan stop
• After stopping PA fans keep running SA fan for another 10 minutes. Then stop SA fans one
by one.
• Keep running ID fans with furnace draft-30 to -40 mmwc for another 30 minutes.
• Then stop one ID fan but keep running another fan and reduced furnace to -10 to -15
mmwc.
• Maintain drum level.
• Maintain drum level till below screen or bed temperature reaches below 150 degC
• BFP Shutdown
• Air & Flue gas draft group shutdown
• Chemical injection group shutdown

11/04/2018
110
Boiler Shutdown
Sequence
Reduce load flow by T/G load or boiler mater
Oil shut off valve closed
Decrease boiler load follow shutdown curve
Reduce coal flow until furnace temperature
< 750 0 C
1. Strat – up oil burner
2. Shutdown limestone injection system
3. Reduce coal flow at minimum
One by one Shutdown oil burner
1. Decrease boiler load follow shutdown
curve
2. Shutdown coal feeder one by one
At the boiler load < 44 % Boiler control from
Auto to Manual
Furnace Purge
Changing rate of coal flow and oil
flow.
Master Fuel Trip
Replace the extraction steam to
converting station
PA Inlet vane open
T/G Stop
Main Steam blow off valve open 10-20%
Main steam valve closed
1. Boiler master change to
manual from Auto
2. 2. Fuel Master change to
manual from auto
3. 3. Air demand change from
remote to auto
Sootblower operation before
unit reduces to 50% load
Boiler Shutdown
Sequence
SAF Stop
GAH Stop if flue gas inlet
temperature , 120 0 C
IDF Stop
Boiler Cooling Down
Bottom ash Conveyor stop
Ash Cooler system stopm
FA Blower Stop
Open all boiler vent
T/G Stop
Main Steam blow off valve open 10-20%
Natural cooling down and reduce boiler
pressure until drain pressure < 2kg/cm2
FA blower vent shutoff valve
open
FA blower inlet control valve at
30%
FA Blower outlet shutoff valve
closed

11/04/2018
111
A boiler trip would occur should any of the
following conditions happen
• PAF Stop
• SAF Stop
• IDF Stop
• Boiler Emergency Trip
• Total Air Flow < 25% (146 t/h)
• Furnace Pressure HH
• Drum Level LL
• Loss of Fuel
• Instrument Air Pressure LL
• Furnace Pressure LL
• All FA Blower Stopped
• Drum Level HH
• Boiler Temp. < 699 ⁰C (for Coal Firing)
• MFT Relay Trip
• Primary Air Flow LL (for Coal Firing)
• Turbine Trip
BOILER COLD SHUTDOWN
0
100
200
300
400
500
600
700
800
900
1000
-2.00 -1.00 0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00
TIME, HOURS
FURNACETEMPERATURE(°C)
SUPERHEATEROUTLETPRESSURE(ata)
SUPERHEATEROUTLETTEMPERATURE(°C)
0
20
40
60
80
100
120
BOILERLOAD,%MCR
Furnace Temp.
Boiler Load
SH Outlet Temp.
SH Outlet Press.
Begin Shutdown,
Start Reducing Fuel
Shut off
Solid Fuel
Start
Burners
Shut off
Burners
Shut off Oil Lances

11/04/2018
112
Role of Operation Engineer in Thermal
Power Station
The operation engineer is meant to ensure:
• Safety of equipment and personnel
• Reliability of supply
• Generation of energy at economic cost.
Operation Engineer’s Objectives is to ensure
• The plant will operate without recordable injuries.
• The plant will operate within environmental guidelines.
• The plant heat rate will be less than or equal to ___________ BTU/kW.
• Plant operational “runs” will be extended to ______ days, and the run
will not be terminated by an operational error.
• Assuming no delay due to silica and given a warm turbine and boiler, the
plant will be brought to full load in ____ hours.
• Mastery of terminal objectives in the following areas of plant operation
will be facilitated:
o Plant startup, shutdown, and power changes
o Transients caused by equipment malfunctions
o Plant operation without use of service equipment

11/04/2018
113
Operation Engineer’s Responsibility is to:
1. Start up of the equipment in a safe and systematic manner.
2. Connect the unit to the transmission network in a proper manner so that the
consumer can draw power.
3. Watch the equipment to ensure its run under safe working conditions.
4. Adjust the different control inputs, like fuel, air, water makeup to match the
electrical output of the unit.
5. Maintain proper cooling of the different bearing surfaces, by assuring
lubrication and heat dissipation by cooling.
6. Maintain salient levels in the different subsystems.
7. Maintain the specified pressure and temperature and levels at various points.
Normally, automatic devices are provided but the operation engineers should
be able to intervene and modulate the control to maintain the parameters
within the specified limits.
8. Maintain proper chemical conditions and concentrations.
9. Watch the mechanical behaviors of all moving equipment-noise, vibration,
bearing lubrication, cooling, control valves and dampers etc.
Plant Management big challenge :
Now, the Big Challenge….
In the rip tide of climate change, population
growth, and dwindling reserves of fossil fuels,
fulfilling the need for energy and electricity will
be one of the big challenges of the future..
Uncertainty about fuel availability and price,
threats of levies and caps on greenhouse gas
emissions, as well as escalating costs of new
power plants, completely changed the quiet
life of power companies

11/04/2018
114
O & M Team Dream:
As you do commence your
work life…..regardless of your chosen
endeavor, my advice..
Follow Excellence
and Success will
Chase you

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