Steam generator part 3

BOILER
Prepared by:
Mohammad Shoeb Siddiqui
Sr. Shift Supervisor
Saba Power Plant

BOILER
Prepared by:
Saba Power Plant
Part 3

Prepared by:
Saba Power Plant
Steam Generator (Boiler)
Hello,
I am trying to explain about Steam Generator
(Boiler) in this session, due to length of said
presentation, I am deciding to divide it in three
parts.
Part 1 cover the “Introduction & Types of
Steam Generator”
Part 2 cover about the “Parts of Steam
Generator and Its Accessories & Auxiliaries”
and This
Part 3 cover the “Design,
Efficiency, Performance &
Protection”

Classification Of Boiler,
Fundamental Of Boiler Design,
Efficiency, Safety &
Environment Control
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1. Mode of circulation of working fluid.
2. Type of fuel.
3. Mode of firing.
4. Nature of heat source.
5. Nature of working fluid.
6. Position of the furnace.
7. Type of furnace.
8. Boiler size.
9. Materials of construction.
10. Shapes of tubes and their spatial position.
11. Content of the tubes.
12. Steam pressure.
13. Specific purpose of utilization.
14. General shape.
15. Manufacturers trade name.
16. Special features. Prepared by:
Fundamental Of Boiler Design

Mode of classification Type
Circulation 1. Natural Circulation Boiler, 2. Forced Circulation
Tube shape and position
(Depending on the form
of tubular heating surface)
1. Straight tube boiler. 2. Bent tube boiler.
Tube shape and position
(Depending on the inclination
of tubular heating surface)
1. Horizontal Boilers, 2. Vertical Boilers,
3. Inclined Boilers
Furnace position 1. Externally fired furnace
2. Internally fired furnace
Tube Contents 1. Fire tube boilers, 2. Water tube boilers
Steam pressure 1. Lowe pressure Boilers, 2. Power Boilers,
3. Miniature Boilers
Mode of firing 1. Fired boilers, 2. Non-fired boilers
Heat source 1. Fuel fired boiler, 2. Waste heat boiler
3. Electrical powered boiler,
4. Nuclear powered boilers
Nature of fuel 1. Coal fired, 2. Gas fired, 3. Oil fired,
4. Wood fired, 5. Bio gas fired
Type of Furnace 1. Dutch oven boiler, 2. Open boiler,
3. Scutch boiler, 4. Screened boiler, 5. Twin boiler

In A Steam Generating Unit Two Distinct
Fundamental Processes Take Place:-
1. Conversion of the potential energy of the fuel
into thermal energy.
2. Transfer of this liberated thermal energy to the
working fluid to generate steam for useful
purpose
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1. Service requirements.
2. Load characteristics.
3. Fuel characteristics.
4. Mode of fuels burning.
5. Hydrodynamics of gas flow.
6. Feed water quality
7. Furnace size, shape and material of construction.
8. Type of furnace bottom.
9. Boiler proper.
10. Boiler operation.
11. Capital investment. Prepared by:

The boiler designer should essentially
consider the following load characteristics:
1. Maximum load, normal load
and minimum load.
2. Load factor.
3. Nature of load – constant or fluctuating.
4. Duration time of each load rate.
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From these very characteristics, a boiler
designer gets the knowledge of the heat value
available from the fuel as well as its specific
properties such as:-
a). Ash content and the percent of volatile matter.
b). Nature of ash and its fusion point.
c). The presence of corrosive agents as sulfur and
vanadium that will dictate the flue gas exit
temp as well as the material of construction of
the heating surfaces of the boiler to avoid the
problem of corrosion and slugging.
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It is the capacity of the fuel burning
device that controls the rate of fuel
input which in turn determines the
furnace volume and its design
specification
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The gas flow through the boiler is affected by
the differential pressure between the
combustion products in the furnace core and
the flue gases at the boiler exit. This pressure
difference, called draught (draft) may be
affected by natural means or by mechanical
means to supply the necessary primary and
secondary air to sustain and control fuel
combustion
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The presence of dissolved solids and
gases, suspended matter and organic
contaminants in feed water
cause corrosion, scaling, priming and
foaming that effectively impair the
performance of a boiler.
Feed water quality, together with other
factors, influences the design of drum
internals, steam separator and steam
washer etc.
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The furnace volume must be
sufficient to maintain the necessary
heat release rate and further
temperature while the combustion
space should be sufficient to contain
the flame so that it does not directly
hit the water walls.
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The factors control the design of boiler proper
are:-
 The operating pressure and temperature.
 The quality of steam – whether the steam
required should be wet, dry or superheated. If
wet steam is required, the designer may do
away with the separators and super-heaters.
 Layout of heating surface – The prime aim of
boiler designer is to obtain the best disposal of
heating absorbing surface within the
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 Heating surface requirements – These depend
upon the duty of the element heat exchangers
such as primary evaporators, secondary
evaporators, super-heaters radiant and
connective re-heater, economizer and air pre-
heater.
 Circulation of steam and water – Natural or
forced.
 Provision of continuous blow drum.
 The capacity of Boiler drum.
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Accessibility for operation, maintenance and
repairing must be easy and quick to ensure higher
operating efficiency and offset the long outage
time.
Adequate provision must be made for:
 Soot blowing
 Tube cleaning – chemically / mechanically
 Washing economizer and air pre-heater surfaces.
Automation should be injected wherever it leads
to higher reliability and greater ease in boiler
operation.
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The following factors are involved in determining the overall
capital investment in designing a boiler:
 Cost of equipment.
 Cost of fuel.
 Cost of labour and materials for operation, maintenance and
repairing.
 Cost of the auxiliaries, e.g., cost of running pumps, fans, ash
disposal systems, etc.
 Expected life of the equipment
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Combustion:
Combustion refers to the rapid oxidation of fuel
accompanied by the production of heat, or heat &
light. Complete combustion of a fuel is possible only
in the presence of adequate supply of oxygen.
Oxygen (O2) is one of the most common elements on
earth making up 20.9% of air. Rapid fuel oxidation
results in large amounts of heat. Solid or liquid fuels
must be changed to a gas before they burn. Usually
heat is required to change solid or liquid fuels into
gases. Fuel gases burn in their normal state if enough
air is present.
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Nitrogen is considered to be a temperature reducing
dilutant that must be present to obtain the oxygen
required for combustion.
Most of 79% of air is nitrogen, with traces of other
elements.
Nitrogen reduces combustion efficiency by absorbing
heat from the combustion of fuels and diluting the fuel
gases. This reduces the heat available for transfer
through the heat exchanger surfaces. It also increases
the volume of combustion by products, which then
have to travel through the heat exchanger and up the
stack faster to allow the introduction of additional fuel
air mixture. This nitrogen also can combine with
oxygen(particularly at high flame temperatures) to
produce oxides of nitrogen (Nox) , which are toxic
pollutants.
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Carbon, Hydrogen and sulphur in the fuel
combine with oxygen in the air to form CO2
,water vapour , and SO2 releasing 8084 Kcals ,
28922 Kcals and 2224 K.cals of heat
respectively. Under certain conditions, carbon
may also combine with oxygen to form CO,
which results in the release of a smaller
quantity of heat 2430 K.cals / kg of carbon.
Carbon burnt to CO2 will produce more heat
per kg of fuel than when CO or smoke is
produced.
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C + O2 CO2 + 8084 Kcals/kg of carbon
2C + O2 2CO + 2430 Kcals/kg of carbon
2H2 + O2 2H2O + 28922 Kcals / kg of
Hydrogen
S + O2 SO2 + 2234 Kcals/kg of sulpher
Each kg of CO formed means loss of (8084-2460 )
Kcals of heat
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3 T’s of Combustion:
The objective of good combustion is to release
all of the heat in the fuel. This is accomplished
by controlling the “three Ts” of combustion,
which are:
Temperature high enough to ignite and maintain
ignition of fuel
Turbulence or intimate mixing of the fuel and
oxygen and Sufficient
Time for complete combustion.
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STOICHIOMETRIC COMBUSTION
The efficiency of a boiler depends on efficiency of
the combustion system. The amount of air
required for complete combustion of the fuel
depends or the elemental constituents of fuel
i.e. , Carbon , Hydrogen and sulphur etc. This
amount is called stoichiometric air.
In general a certain amount of air more than that
of Stoichiometric air is required for
complete combustion and ensure that release of
the entire heat contained in fuel oil.
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FUEL ANALYSIS:
There are two methods: the ultimate analysis
splits up the fuel into all its component
elements, solid or gaseous, and the proximate
analysis determines only the fixed carbon,
volatile matter, moisture, and ash percentages.
The ultimate analysis must be carried out in a
properly equipped laboratory by a skilled
chemist, but proximate analysis can be made
with fairly simple apparatus
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PROXIMATE ANALYSIS:
Proximate analysis indicates the percentage by
weight of fixed carbon, volatiles, ash and
moisture content in coal. The amounts of fixed
carbon and volatile combustible matter directly
contribute to the heating value of coal. Fixed
carbon acts as a main heat generator during
burning. High volatile matter content indicates
easy ignition of fuel. The ash content is
important in the design of the furnace grate,
combustion volume, pollution control
equipment and ash handling systems of a
furnace.
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ULTIMATE ANALYSIS:
The ultimate analysis indicates that various
elemental chemical constituents such as
carbon, hydrogen, oxygen sulphur etc. It
is useful in determining the quantity of
air required for combustion and the
volume and composition of the
combustion gases. This information is
required for the calculation of flame
temperature and the free duct design.
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CALORIFIC VALUE:
The calorific value is the measurement of heat or
energy produced, and is measured either as
gross calorific value (GCV) or net calorific
value (NCV). The difference being the latent
heat of condensation of the water vapour
produced during the combustion process.
GCV assumes all water vapour produced during
combustion process is fully condensed.
NCV assumes water leaves with the combustion
products without fully being condensed.
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BOILER EFFICIENCY
Thermal efficiency of boiler is defined as the
percentage of heat input i.e. effectively utilized
to generate steam. There are two methods of
assessing boiler efficiency:
Direct Method:
Where the energy gain of the working fluid
(water and steam) is compared with the energy
content of the boiler fuel.
Indirect Method:
Where efficiency is the difference between the
losses and energy input.
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Direct Method:
This is also known as “input - output method”
due to the fact that it need only the useful
output (steam) and the heat input (i.e. fuel) for
evaluating the efficiency.
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Boiler efficiency
Boiler efficiency =Heat output /
Heat input
Parameters to be monitored for the
calculation of boiler efficiency by
direct method are:
Quantity of steam generated per
hour (Q) kg/hr.
Quantity of fuel used per hour (q)
in kg/hr.
The working in pressure [in
kg/cm²(g)] and superheat
temperature (°C), if any.
The temperature of feed water (°C)
Type of fuel and gross calorific
value of the fuel (GCV) in Kcal/kg
of fuel.
Heat
Input
Radiation
Loss
Steam Output
ESP
Second Pass
Furnace
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Boiler efficiency (η) = (Q x (hg-hf) /q x GCV) x 100 %
where
hg - Enthalpy of saturated steam in Kcal / kg of steam
hf - Enthalpy of feed water in Kcal/kg of water
q - quantity of fuel.
Disadvantages of direct method
Does not give clues to the operator as why the
efficiency of the system is lower. Does not calculate
various losses accountable for various efficiency
levels.
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Indirect method:
Indirect method is also called as heat loss method.
Subtracting the heat loss fractions from 1000 can arrive
at the efficiency. The standard do not include blow
down loss in the efficiency determination process.
The principle losses that occur in a Boiler are:
 Loss of heat due to dry flue gas.
 Loss of heat due to moisture in fuel and combustion.
 Air loss of heat due to combustion of hydrogen.
 Loss of heat due to radiation
 Loss of heat due to un burnt carbon.
In the above, loss of heat due to moisture in fuel and the
loss due to combustion of hydrogen are dependent on
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Indirect method:
The data required for calculation of boiler
efficiency using indirect method are:
 Ultimate analysis of fuel (H2, O2, S, C, moisture
content, ash content).
 Percentage of oxygen or CO2 in flue gas
 Flue gas outlet temperature in °C (Tf)
 Ambient temperature in °C (Ta) and humidity
of air in kg/kg of dry air.
 GCV of fuel in Kcal/kg.
 Percentage combustible in ash
 GCV of ash in Kcal/kg
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Indirect method:
1. Percentage of heat loss due to dry flue gas =
(m x Cp x (Tf-Ta) / GCV of fuel ) x 100
Where is:
m = mass of dry flue gas in kg/kg of fuel.
Total mass of flue gas (m) = mass of actual air
supplied + mass of fuel supplied
Cp = specific heat of super heated steam (0.45 K cal /
kg).
Tf = Flue gas outlet temperature in °C
Ta = Ambient temperature in °C
Loss due to dry flue gas = 4.928%
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Furnace
Second
Pass
ESPHeat
Input
1. Loss due to dry flue gas = 4.928%
Radiation
Loss
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Indirect method:
2. Percentage heat loss due to evaporation of water
formed due to H2 in fuel =
9 x H2[ 584 +Cp (Tp-Ta)] / GCV of fuel X 100
Where is:
H2 = Percentage of H2 in kg of fuel
584 = Latent heat corresponding to partial
pressure of water vapour ( 584 K cal / kg).
Loss due to Hydrogen in Fuel = 5.537%
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Indirect method:
3. Percentage of heat loss due to moisture present
in fuel
= M{ 584+CP(Tf – Ta) }X 100 / GCV of fuel
Where , M = % of moisture in 1 kg of fuel
Loss due to Moisture in Fuel = 1.263%
4. Percentage of heat loss due to moisture present in air
= AAS x humidity factor x CP X (Tf-Ta) X 100 / GCV of
fuel
Where, AAS = actual air supplied ( 0.45 K cals / kg)
Loss due to Moisture in Air = 0.074%
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Indirect method:
5. Percentage of heat
loss due to un-burnt
in fly ash
= [(Total ash collected /kg if
fuel burnt X GCV of fly ash) /
GCV of fuel ] X 100
6. Percentage of heat
loss due to un-
burnt in bottom ash
= [{Total ash collected /kg of
fuel burnt X GCV of
bottom ash} / GCV of fuel ]
X 100
Due to Sen. Heat of Fly Ash = 0.102%
Loss due to Unburnt Carbon = 0.331%
Due to Sen. Heat of Bottom
Ash = 0.071%
4) Due to Sen. Heat of Fly Ash
= 0.102%
Radiation
Loss
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Indirect method:
7. Percentage of heat loss due to radiation and other
unaccounted loss.
Unaccounted Losses = 1.327%
Total Losses = 13.83%
Thus, Boiler efficiency (η) = 100 – (1+2+3+4+5+6+7)
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Data required for Boiler Efficiency Calculations
Unit load MW
FW Flow at Econ inlet T/hr
Wet bulb Temp 0C
Dry bulb Temp 0C
Barometric Pressure mmHg
Total Coal Flow T/hr
Unburnt C in BA (Bottom Ash) %
Unburnt C in FA(Fly Ash) %
Radiation & Unaccounted Losses %
% Fly ash to Total Ash %
% Bottom ash to Total ash %
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Data required for Boiler Efficiency Calculations
Proximate Analysis of Coal Air Dry As fired
Moisture % %
Ash % %
Volatile Matter % %
Fixed Carbon % %
Gross Cal. Value Kcal/kg Kcal/kg
Ave FG O2 APH in Ave FG O2 APH Out
Ave FG CO2 APH in Ave FG CO2 APH Out
Ave FG CO APH in Ave FG CO APH Out
Ave. FG Temp APH in Ave. FG Temp APH Out
Air to APH in Air APH out
Total Primary Flow
Total Air Flow L
Total Air Flow R
Design Ambient / Ref air Temp
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Controllable losses
Following losses can be controlled
1. Loss due to dry flue gas
The designer gives this loss at the flue gas
APH outlet temp of 140
0
C
Any increase in the FGT more than 140
0
C will be
resulting in more losses. This temp has to be
controlled by proper cleaning of the furnace
2. Losses due to the unburnt coal in bottom and
fly ash.
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Controllable losses
2. Losses due to the unburnt coal in bottom and
fly ash.
3. Loss due to unburnt in bottom ash
The designer gives this %age as max 4.8 % any
increase in this percentage beyond this will
result in more losses.
If unburnt in bottom ash is more, the culprit is the
coal mill, check the fineness of pulverised coal.
Check the % retention on 50 mesh. It shall not
exceed 1%.
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Controllable losses
Check the Unburnt in fly ash sample taken from
the first hopper of ESP/BF. As per the designer
it shall not exceed 0.8%.
If Unburnt in fly ash exceeds 0.8% it indicates
incomplete combustion due to less amount of
air.
Check for O2 % at the APH Flue Gas inlet for
2.8%, increase if necessary to 3.2%. Again check
for Unburnts in fly ash. Simultaneously check
for air leakages/ingress in the second pass.
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Controllable losses
Assumptions:-
Fly Ash is 80% of Total Ash.
Bottom Ash is 20% of Total Ash
Sulphur is 0.4% in Coal
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The following are the factors influencing a boiler efficiency
1. Stack Temperature -
The stack temperature should be low as possible.
However, it should not be so low that water
vapour in the exhaust condenses on the stack
walls. This is important for fuels containing
significant sulphur , a low temperature can lead
to sulphur dew point corrosion. Stack
temperature greater than 140°C indicates
potential for recovery of waste heat. It also
indicate the scaling of heat transfer
/ recovery equipment and hence the urgency of
taking on early S/D for water / flue side
cleaning
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2. Incomplete Combustion
In complete combustion can arise from a shortage of
air or sulphur of fuel or poor distribution of fuel. It
is usually obvious from the colour or smoke and
must be corrected at the earliest. With coal firing,
unburned carbon can comprise a big loss. It occurs a
gift carry over or carbon in ash and may amount to
more than 2% of the heat supplied to the boiler.
Non-uniform fuel size could be one of the reasons
for incomplete combustion. Increase in the fines in
pulverized coal also increases carbon loss as because
finer coal particle may fall through grate bars or
carried away with furnace draught.
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3. Excess Air Control:
Excess air is required in all practical cases to
ensure complete combustion, to allow for the
normal variations in combustion and to ensure
satisfactory stack condition for some fuels. The
optimum excess air level for maximum boiler
efficiency occurs when the sum of the losses due to
incomplete combustion and loss due to heat in flue
gases is minimum. This level varies with furnace
design, type of burner , fuel and process variables .
It can be determined by conducting tests with
different air fuel ratio. Controlling excess air to an
optimum level always results in reduction in flue
gas losses; for every 1%reduction in losses 0.6% rise
in efficiency.
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4. Reduction of Scaling and Soot loses :
In oil and coal fired boilers , soot build up on
tubes acts as an insulator against heat transfer.
Any such deposits should be removed or regular
basis. Elevated stack temperatures may
indicate excessive soot build up. Also
same result will occur due to
scaling on water side for not maintaining proper
water Chemistry.
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Higher exit gas temperatures at normal excess
air indicate poor heat transfer performance. This
condition can result from a gradual build up of
gas side or waterside deposits. Waterside
deposits require a review of water treatment
procedures and tube cleaning to remove
deposits. An estimated 1% loss with every 22°C
increase in stack temperature stack temperature
should be cheeked and recorded regularly as an
indicator of shoot deposits. When flue gas
temperature rises about 20°C above the
temperature, it is time to remove shoot deposits.
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It has been estimated that about 3mm of shoot
can cause an increase in fuel consumption
by 2.5%. Thus soot /slag deposition on the
surface of the water wall tube, super heater, Re-
heater, Economizer tubes reduces the boiler
efficiency considerably and increases the flue gas
outlet temperature. Choking due to ash
deposition on the heating element of air pre-
heater also reduces the combustion air
temperature and there reduces efficiency and
increases flue gas temperature.
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5. Blow Down Control:
Boiler blow down is necessary for controlling the
dissolved solids contained in the boiler water,
and this is achieved by a certain amount of water
is blown off and replaced by feed water. Thus
maintaining optimum level of total dissolved
solids (TDS) in boiler water. Uncontrolled
continuous blow down is very wasteful. By
monitoring boiler water conductivity and PH
Blow down can be controlled and these reducing
the efficiency losses
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6. Quality of Fuel:
Quality of fuels influences the efficiency of Boiler to a
large extent. It depends upon fixed carbon
percentage, which gives a rough estimate of heating
value of coal. Volatile matter content in the coal is an
index of gaseous fuels present in coal. It
proportionately increases flame length, and helps in
easier ignition of coal. It also influences secondary air
requirement. Ash content is coal affects the
combustion efficiency and thus boiler efficiency also
causes clinkering and slugging. Moisture content
in fuel increases heat loss due to evaporation and
superheating of vapour, helps to a limit, in binding
fines, aids radiation heat transfer.
Sulphur affects clinkering and slagging tendencies.
Limits exit fuel gas temperature Prepared by:

TYPICAL INSTRUMENTS
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BOILER SAFETY EQUIPMENTS
Boiler Protections
Boiler safety equipments includes
• BMS (Burner Management System)
• Control System
• Inter lock System.
• Safety valve.
• Gauge Glass
• Pressure & Temperature Measurements
(Gauges, Transmitters, Switches &
Recorders)
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BMS (Burner Management System)
A burner management system is responsible for
the safe start-up, operation and shutdown of a
boiler. It monitors and controls igniters and main
burners; utilizes flame scanners to detect and
discriminate between the igniter and main flames;
employs safety shut-off valves, pressure,
temperature, flow and valve position limit
switches and uses blowers to cool the scanners
and/or provide combustion air for the igniters. Its
proper operation is crucial to the safety of a boiler.
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Background:
In the past, most boilers have operated on
temperature control from the outlet temperature to
a control valve in the main fuel line, with a single
shut-off valve upstream on the Control valve. This
shut-off valve was either automatic with the plant
DCS or operated manually with an Operator
action, with each company having various
additions to this basic concept.
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Operating philosophy:
The main function of the BMS is to allow and
ensure the safe start-up, operation, and shutdown
of the Fired Boiler. Once the logic is configured
and the system properly commissioned the BMS
will provide a safe and consistent operating
sequence. The human interface will guide the
operator so that the heater may be safely operated,
and if needed, be quickly and safely restarted.
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Boiler Protections

Boiler Protections
The following sequence of operation is typical for most
Fired Boilers.
1) Initially, the PLC will check that all the permissives
and interlock are in place to allow start up.
2) Start Purge. The PLC will check that the permissives
are at their correct status. The system will typically wait for
the operator to request the boiler to start, although all
permissives are met and the boiler is ready to purge. Once
the boiler start/purge is requested a pre-set timer will
commence. Assuming the timing is not interrupted by an
Interlock activation, it will continue until complete. Once
finished, it will notify the operator that “Purge Complete”
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Boiler Protections
3) Ignite Pilots. Once the purge is completed, the
operator will be notified that the system is ready to start
the pilots. The pilot header double block and bleed valves
will energize. Instantaneously, the individual local pilot
firing valves will open and the ignition transformers will
be energized. The pilot valves and the ignition
transformers will only be energized for a maximum of 10
seconds. If the pilot flame is not detected within this time
the individual pilot isolation valve will close.
4) Prove Pilots. Each pilot has its’ own dedicated flame
detector, which in most cases is via a flame rod. Once
proven, the individual pilot valve will hold in and continue
to burn, in the event a pilot is not lit.

Boiler Protections
5) Light Main Burners.
Before the main burners are lit, the PLC will continue to
check the permissives to ensure it is safe to light the main
burners. The two main permissives are that there is
sufficient flow in the process coils and the pilot burners are
proven. The system then proceeds to energize the main
header vent and shut-off valves. The first burner will light
at the minimum fire rate. A five second trial for ignition is
provided from the time the individual isolation valve is
opened until the detection of the flame. If the flame is not
detected, the individual main burner isolation valve is de-
energized.
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Boiler Protections
6) Confirm Main Burner Status.
Once this is achieved the system is ready to be ramped up
to operating conditions. This is usually performed
manually until the process variable is close to the
operating set point, then the temperature and gas
flow/pressure controllers can then be switched to auto
mode.
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The following is a list of new requirements that are
common to various boiler and BMS codes.
1) Mandatory Purging.
2) Permissive Interlocks
3) Double Block and Bleed systems
4) Pilots and Ignition Systems
5) Dedicated Flame Monitoring Systems
6) High / Low Pressure, Temperatures and Flow.
7) Combustion Air and Draft Pressure Alarms and Controls
8) Dedicated Logic Solver
Each of these requirements have been developed due to incidents that
have occurred because of the lack of them.
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1) Mandatory Purging:
The most important function of the boiler control
system is to prevent the possibility of an accumulation
of combustible fuel followed by accidental or improper
ignition sequence resulting in an explosion. Correct
pre-ignition purging of the heater is crucial to the safe
operation of the heater.
A time to achieve the four volume changes may be calculated
from the required flow rate. In the event the purge does not
continue for the prescribed time or required purge, permissives
are no longer met and a re-purge is required. Only when a
successful purge is completed can any ignition source be
introduced.
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1) Mandatory Purging: (Safety Rule)
• CSA B194.3-05 Section 9.2 Pre-purge 9.2.1:
When either an intermittent or interrupted pilot or a direct
transformer spark igniter is used to light the main burner and the
combustion air supply is by mechanical means, the appliance
control system shall provide a proven purge period prior to the
ignition cycle. This purge period shall provide at least four air
changes of the combustion zone and flue passages at an airflow
not less than 60% of that required at maximum input.
• NFPA 86 Section 5-4.1 Pre-ignition (Pre-purge, Purging
Cycle) 5-4.1.2:
A timed pre-ignition purge shall be provided. At least 4 standard
cubic feet (scf) of fresh air or inert gas per cubic foot (4m3/m3) of
heating chamber volume shall be introduced during the purge
cycle.
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Permissives & Interlocks:
These can be numerous and may include all of the
items on the BMS. The interlocks are usually
designated on the P&ID with the symbol “I”. These
are used in the configuration of the operating
procedure and logic so as to ensure the safe
sequential operation of the boiler particularly in
start-up and during operation. The permissives are
an integral part of the start-up and light-off
procedure. The main importance of the interlocks is
to detect the need for partial or total shut down of the
boiler.
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Permissives & Interlocks:
Typical interlocks would include high/low fuel and
pilot gas pressure, high/low stack temperature, loss
of flame, high/low firebox pressure and loss of
combustion air. In addition to these general trips
each boiler must be examined individually to
determine if additional trips may be required due to
the boiler design or configuration. These non-
standard trips are designed to protect the boiler and
personnel from tube and structural damage that may
occur from improper operation for a long duration.
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Shut-off Valves.
The safety shut-off valves are the key component in the BMS
to prevent the accumulation of an explosive mixture in the
boiler. Standard practice is to provide automated safety
shutoff valves installed in a double block and bleed
configuration on the main and pilot headers. An additional
safety shut-off valve should be located on each individual
burner for multiple burner systems. These shut-off valves
must also be certified for use safety shut-off valves. In
accordance with CSA requirements these valves need to be
certified to CSA 6.5 certified and per NFPA requirements
these valves need to be FM-7400 listed
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Shut-off Valves.
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Pilots and Ignition Systems:
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Unfortunately the majority of boilers still in use within the
industry rely on a manual ignition system. This means the
heater is manually lit by the operator inserting an oily rag or
an ignition torch to the base of the burner. With today’s
technology and easy accessibility to the electronic ignition
system it is no longer necessary to manually light the
heaters and potentially place the operator in harms way.
The electric ignition system consists of an ignition rod
provided with the burner and a high voltage ignition
transformer. When all interlocks are cleared and permissives
are in place the ignitor lights the pilot burner which then in
turn lights the main burner.

Pilots and Ignition Systems:
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An electronic ignition system,
controlled by the BMS,
eliminates the need for the
operator to provide an ignition
source for the burners; which is
considered to be the most
dangerous part of the startup
procedure. As the BMS controls
the ignition of the burners the
heater purge cannot be so easily
bypassed.
Typically each burner is
provided with its own pilot and
ignition system.

Dedicated Flame Monitoring Systems:
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Each burner is equipped with its own flame monitoring
devices, independent detectors are required to supervise
the pilot and the main flame. Exceptions may be made
depending on the type of pilot and burner. In most
installations two different detection techniques are used,
a flame (ionisation) rod to monitor the pilot flame and an
UV (Ultraviolet) or IR (Infrared) Scanner to ‘see’ the main
flame. Flame rods are typically used on the pilot flame as
they are more cost effective, however the same detectors
should not be used on the main flames as these typically
run at a higher temperature and the flame rod would
burn out in a short amount of time.

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Dedicated Flame Monitoring Systems:

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Alarms and Shutdowns:
Alarms and shutdowns provided by the boiler’s instrumentation
provide added safety and permissives to allow the system to
transition from different stages of boiler operation in a proper and
safe manner. There is some instrumentation typical to all systems
and others that are dependent on the size, purpose, and
configuration of the boiler. The instrumentation is located on the
fuel gas trains and the heater itself. In the past, switches have been
widely used for these applications for various reasons, however it
is strongly recommended that transmitters be used in lieu of
switches. Switches may fail in an unsafe position without
providing any indication until the unit is required to operate.
Transmitters report back dynamic information and have built-in
diagnostics, so they are able to provide indication of failures.
Considering the losses involved if an incident was to occur, it is far
more cost efficient to use the more reliable transmitters.

Boiler Protections
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Combustion Draft / Pressure Alarms and Controls
Boiler draft is the motive force that will ensure proper air and flue
gas flow through the boiler. The most critical draft point is at the
arch as it is the controlling variable in the design of the burner and
boiler itself. This measurement is a critical indicator in the
operation of a fired boiler and alerts the operator to any tendency
to go positive.
Although this is normally not a shut-down device, it is closely
linked to opening the stack damper blade. The pressure control
loop consists of a pressure transmitter located at the boiler arch and
an actuator on the stack damper. A low draft pressure (high firebox
pressure) alarm should be added to this transmitter. The control
loop is to be configured such that the stack damper opens when
there is a low boiler draft. In the event that the boiler draft is still
too low but the stack damper is 100% open the burner firing rate
must be reduced.

Boiler Protections
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Dedicated Logic Solver:
Traditionally most BMS’s have been implemented using a
discrete series of relays and switches as the logic solver. When
designed correctly these hardwired panels may prove to be
very reliable. Unfortunately the permissives and interlocks on
such systems are easily bypassed. With the advent of the
microprocessor, unitized flame safeguard controllers have
been introduced. These units provide the required logic to
safely start and stop the heater. The draw back of these units
is that they are only designed to control single burner
systems.

Boiler Protections
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Dedicated Logic Solver:
The area of biggest change in BMS systems as of late is the
ability to use a Programmable Logic Controller (PLC) as the
primary safeguard and logic solver. Certain conditions must
be adhered to in order to validate their use, which vary
between different codes. Common requirements are that a
power or hardware failure will not prevent the system from
reverting to a safe condition and an external Watch Dog
Timer must be used to monitor a dedicated output channel.
Any failures will cause the system to revert to a safe
condition. As technology advances and the introduction of
true safety rated systems progresses, these requirements and
guidelines will inevitably change.

PLC Panel with Lights and Push Buttons

 LL Level Of Steam Drum
 LL Flow Of Water
 HH Pressure Of Furnace
 LL Fuel Pressure
 HH Fuel Pressure
 Instrument Air Loss
 Power Loss
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 Water Loss
 Fuel Loss
 Electrical Failure
 Instrument Air Failure
 Vacuum Loss Of Surface Condenser
 High Pressure Of Steam Drum
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Boiler Logs Are Important
The majority of boiler accidents can be
prevented. One of the most effective tools is the
proper use of operating and maintenance logs.
Boiler logs are the best method to assure a
boiler is receiving the required attention and
provide a continuous record of the boiler's
operation, maintenance and testing. Because a
boiler's operating conditions change slowly
over time, a log is the best way to detect
significant changes that may otherwise go
unnoticed.
Boiler Protections

 Level Measurement
 Temperature Measurement
 Flue Gas Analysis
 Furnace Pressure
 Fuel Control
 Air Flow Control
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Boiler Protections

 Level Measurement By Using Level
Glass
 Pressure Measurement By Using
Pressure Gauge
 Temperature Measurement By Using
Temperature Measuring Element
 Composition Analyzer
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Boiler Protections

Water Level Control and Low Water Fuel Cutoffs
These devices perform two separate functions,
but are often combined into a single unit. This
method is economical, providing both a water
level control function and the safety feature of a
low water fuel cutoff device. We recommend,
however, that both steam and hot water boilers
always have two separate devices — a primary
and a secondary low water fuel cutoff. Many
jurisdictions require two such devices on steam
boilers.
 Steam Drum Low Low Level
 Low Low Flow Of Fuel
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The importance of proper cleaning and
maintenance of the water gage glass,
or sight glass, cannot be stressed
enough. The gage glass on a steam
boiler enables the operator to visually
observe and verify the actual water
level in the boiler. But water stains and
clogged connections can result in false
readings. The glass also may break or
leak. Take the time to replace the glass,
even if the boiler must be shut down.
That inconvenience is nothing
compared to the damage that may
result from operating a boiler without
a gage glass.
The Normal Operating Water Level
(NOWL) should be approximately in
the middle of the gauge glass.
Boiler Protections
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 Level Transmitter
 Pressure Transmitter
 Temperature Transmitter
 Level Switch
 Pressure Switch
 Flow Transmitter
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Boiler Protections

Major Variable
 Steam Pressure
 Steam Temperature
 Water Level
 Feed Water Pressure
 Furnace Draft
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Boiler Protections

 Steam Flow
 Feed Water Flow
 Combustion Air Flow
 System Drafts Or Pressure
 Feed Water Temperature
 Flue Gas Temperature
 Fuel Flow
 Fuel Pressure
 Fuel Temperature
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Boiler Protections

 Fixed Positioning
 Positioning With Operator Trim
 Pressure Ratio
 Fuel And Air Metering
 Cross Limited Metering
 Oxygen Trim Control
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Boiler Protections

Often considered the primary safety
feature on a boiler, the safety valve
should really be thought of as the last
line of defense. If something goes
wrong, the safety valve is designed to
relieve all the pressure that can be
generated within the boiler. Keep in
mind that the same conditions that
make other safety devices
malfunction can also affect the safety
valve. Don't let testing and
maintenance schedules slide.
The spring-loaded pop-off safety
valve pops open when steam
pressure exceeds the MAWP.
Safety valves are routinely tested to
ensure proper operation and must be
serviced by an authorized
manufacturer representative.
Boiler Protections
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Water must be treated for
safety. Minerals can cause a
build up of deposits and
cause overheating of boiler
parts.
Carryover occurs when a
high boiler water level
causes water particles to be
carried into steam lines.
Bottom blowdown, the
boiler should be under light
load and the water level
should be at the NOWL.
Boiler Protections
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The purpose of the drum level controller is to bring the
drum up to level at boiler start-up and maintain the level at
constant steam load. A dramatic decrease in this level may
uncover boiler tubes, allowing them to become overheated and
damaged. An increase in this level may interfere with the process
of separating moisture from steam within the drum, thus
reducing boiler efficiency and carrying moisture into the process
or turbine. The functions of this control module can be broken
down into the following:
● Operator adjustment of the setpoint for drum level
● Compensation for the shrink & swell effects
● Automatic control of drum level
● Manual control of the feedwater valve
● Bumpless transfer between auto and manual modes
● Indication of drum level and steam flow
● Indication of feedwater valve position and feedwater flow
● Absolute/deviation alarms for drum level The three main
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Mohammad Shoeb
Siddiqui

Single-element drum level control
The simplest but least effective form of drum level
control.
This consists of a proportional signal or process variable
(PV) coming from the drum level transmitter. This signal
is compared to a setpoint and the difference is a
deviation value. This signal is acted upon by the
controller which generates corrective action in the form
of a proportional output. The output is then passed to
the boiler feedwater valve, which then adjusts the level
of feedwater flow
Notes:
● Only one analogue input and one analogue output required
● Can only be applied to single boiler / single feedpump configurations
with relatively stable loads since there is no relationship between drum
level and steam- or feedwater flow
● Possible inadequate control option because of the swell effect into the
boiler drum.
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Single-element drum level control
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Two-element drum level control
The two-element drum level controller can best be applied to a single drum
boiler where the feedwater is at a constant pressure.
The two elements are made up of the following: Level Element: a
proportional signal or process variable (PV) coming from the drum level
transmitter. This signal is compared to a setpoint and the resultant is a
deviation value. This signal is acted upon by the controller which generates
corrective action in the form of a proportional value. Steam Flow Element: a
mass flow rate signal (corrected for density) is used to control the feedwater
flow, giving immediate corrections to feedwater demand in response to
load changes. Any imbalance between steam mass flow out and feedwater
mass flow into the drum is corrected by the level controller. This imbalance
can arise from:
● Blowdown variations due to changes in dissolved solids
● Variations in feedwater supply pressure
● Leaks in the steam circuits constant pressure.
Notes: ● Tighter control of drum level than with only one element
● Steam flow acts as feed forward signal to allow faster level adjustments
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Two-element drum level control
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Three-element drum level control
The three-element drum level control is ideally
suited where a boiler plant consists of multiple boilers and
multiple feedwater pumps or where the feedwater has
variations in pressure or flow.
The three-elements are made up of the following: Level
Element and Steam Flow Element: corrects for unmeasured
disturbances within the system such as: ● Boiler blowdown
● Boiler and superheater tube leaks Feedwater Flow
Element: responds rapidly to variations in feedwater
demand, either from the ● Steam flow rate feedforward
signal ● Feedwater pressure or flow fluctuations In order
to achieve optimum control, both steam and feedwater
flow values should be corrected for density.
Notes:
● The three-element system provides tighter control for drum level with fluctuating steam load. Ideal where
a system suffers from fluctuating feedwater pressure or flow
● More sophisticated level of control required
● Additional input for feedwater flow required
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Three-element drum level control
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Enhanced Three-element drum level control
The enhanced three-element drum level control module
incorporates the standard three element level components with
the following improvements: ● The three-element mode is used
during high steam demand. The two-element mode is used if the
steam flow measurement fails and the module falls back to
single element level control if the feedwater flow measurement
should fail or if there is a low steam demand.
● The drum level can be derived from up to three independent
transmitters and is density compensated for pressure within the
boiler drum.
Notes:
● Tighter control through a choice of control schemes. Drum
level maintained on failure of steam or feedwater flow
measurements
● This module introduces an additional level control loop Boiler
drum level control
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The Stack Temperature Gage
A stack temperature gage is normally installed on
a boiler to indicate the temperature of the flue
gas leaving the boiler. A high stack
temperature indicates that the tubes may be
getting a buildup of soot or scale. Also, the
baffling inside the boiler may have deteriorated
or burned through, allowing gases to bypass
heat transfer surfaces in the boiler.
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Environmental protection and the control of solid,
liquid and gaseous effluents or emissions are key
elements in the design of all steam generating systems.
The emissions from combustion systems are tightly
regulated by local and federal governments, and
specific rules and requirements are constantly
changing. At present, the most significant of these
emissions are sulfur dioxide (SO2), oxides of nitrogen
(NOx), and fine airborne particulate. All of these
require specialized equipment for control.
A key element in a successful emissions control
program is measurement and monitoring.
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Control approaches
One or more of the following measures have typically been
adopted to control emissions:
1. Emission standards These limit the mass of SO2, NOx, or other
pollutant emitted by volume, by heat input, by electric energy
output, or by unit of time (hourly, daily, annually).
2. Percent removal requirements These specify the portion of the
uncontrolled emissions that must be removed from the flue
gas.
3. Fuel requirements Primarily aimed at SO2 control, these either limit
the type of fuel that can be burned or the fuel sulfur content.
4. Technology requirements These typically indicate the type of control
technology specifically required or indicate the use of the best
available control technology or reasonably available control
technology at the time of installation. These requirements
depend in many cases on some level of economic feasibility.

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Kinds of Pollutants, Sources and Impacts
The focus of these slides are stationary emission
sources, particularly fired utility and industrial
boiler systems. Key pollutants from these sources are
SO2, SO3, NOx, CO and particulate matter. Another
class of emissions is called air toxics. These are
potentially hazardous pollutants that generally occur
in only trace quantities in the effluents from fired
processes.
However, they are undergoing more intense
examination because of their potential health effects.

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Kinds of Pollutants, Sources and Impacts
Air pollutants are contaminants in the atmosphere which,
because of their quantity or characteristics, have deleterious
effects on human health and/or the environment. The sources
of these pollutants are classified as stationary, mobile or
fugitive. Stationary sources generally include large individual
point sources of emissions such as electric utility power plants
and industrial furnaces where emissions are discharged
through a stack. Mobile sources are those associated with
transportation activities. Fugitive emissions generally include
discharges to the atmosphere from conveyors, pumps, valves,
seals and other process points not vented through a stack.
They also include emissions from area sources such as coal
piles, landfills, ponds and lagoons. They most often consist of
particulates and occur in industry-related activities in which
the emissions are not collected.

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Sulfur oxides
Sulfur oxides have been related to irritation of the human
respiratory system, reduced visibility, materials corrosion
and varying effects on vegetation. The reaction of sulfur
oxides with moisture in the atmosphere has been identified
as contributing to acid rain.
Wood and bark typically contain 0.0 to 0.1% elemental sulfur
on a dry basis. During the combustion process some of this
sulfur can be converted to flue gas SO2, but the conversion
ratio is typically low (10 to 30%).
Sulfur dioxide (SO2)
Most of the sulfur in fuel converts to SO2 with small
quantities of sulfur trioxide (SO3). The main source of sulfur
oxides is from the combustion of coal, with lesser amounts
from other fuels such as residual fuel oil.

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Sulfur trioxide (SO3 )
Some of the sulfur dioxide that forms converts to sulfur trioxide
(SO3). The typical conversion rate is 1% or less in the boiler.
However, the catalytic process that is frequently used to control
NOx levels has the undesirable side effect of converting
additional SO2 to SO3, which can range from 0.5 to 2% additional
conversion. The SO3 readily combines with water to form
sulfuric acid (H2SO4) at flue gas temperatures less than 500 oF
(260 oC). This acid can create extremely corrosive conditions. The
sulfuric acid condenses to form a fine mist when the flue gas
passes through a wet flue gas desulfurization system that is used
to remove sulfur dioxide (SO2). This sulfuric acid mist contributes
to the total stack particulate loading. Such mist is extremely fine,
less than 0.5 micron, and very small amounts of this mist (5 ppm
or less) can cause visible, bluish stack plumes, even in the
absence of solid particulate.

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Nitrogen oxides (NOx)
This category includes numerous species comprised of
nitrogen and oxygen, although nitric oxide (NO) and
nitrogen dioxide (NO2) are the most significant in terms
of quantity released to the atmosphere. NO is the primary
nitrogen compound formed in high temperature
combustion processes where nitrogen present in the fuel
and/or combustion air combines with oxygen. The
quantity of NOx formed during combustion depends on
the quantity of nitrogen and oxygen available, the
temperature, the intensity of mixing and the time for
reaction. Control of these parameters has formed the basis
for a number of control strategies involving combustion
process control and burner design.

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Nitrogen oxides (NOx)
Based on the most recent EPA emissions inventory,
utilities account for 22% of NOx emitted, with the
transportation sector emitting 56%. Of the total utility
NOx emissions, approximately 90% comes from coal-
fired boilers.
The most deleterious effects come from NO2 which
forms from the reaction of NO and oxygen. NO2 also
absorbs the full visible spectrum and can reduce
visibility. NOx has been associated with respiratory
disorders, corrosion and degradation of materials, and
damage to vegetation. NOx has also been identified as a
precursor to ozone and smog formation.

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Carbon monoxide
This colorless, odorless gas is formed from incomplete
combustion of carbonaceous fuels. CO emissions from
properly designed and operated utility boilers are a relatively
small percentage of total combustion source CO emissions,
most of which come from the internal combustion engine in
the transportation sector. The primary environmental
significance of CO is its effect on human and animal health. It
is absorbed by the lungs and reduces the oxygen carrying
capacity of the blood. Depending on the concentration and
exposure time, it can cause impaired motor skills and
physiological stress.

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Particulate matter
Solid and liquid matter of organic or inorganic
composition which is suspended in flue gas or the
atmosphere is generally referred to as particulate. Particle
sizes from combustion sources are in the 1 to 100 μm
range, although particles smaller than 1 μm can occur
through condensation processes.
Among the effects of particulate emissions are impaired
visibility, soiling of surrounding areas, aggravation of
adverse effects of SO2, and human respiratory problems.

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PM10 and PM2.5
Subsets of particulate matter, PM10 is particulate matter 10
μm and finer and PM2.5 is particulate matter 2.5 μm and
finer. Fine particles are emitted from industrial and
residential oil combustion and from vehicle exhaust. Fine
particles are also formed in the atmosphere when gases such
as SO2, NOx and VOCs, emitted by combustion processes, are
transformed into fine particulate by chemical reactions in the
air (i.e., sulfuric acid, nitric acid, and photochemical smog).
PM2.5 is considered to have more deleterious health affects
than coarser particulate.
Others types of pollutions are:
VOC, (Volatile organic compounds) represent a wide range
of organic substances. Toxic air pollutants, Mercury, &
Carbon dioxide

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Others Types of Pollutions are:
VOC, (Volatile organic compounds) represent a wide range
of organic substances. Toxic air pollutants, Mercury, &
Carbon dioxide
Volatile Organic Compounds (VOC)
Volatile organic compounds (VOCs) are also gaseous
products of incomplete combustion. Its represent a wide
range of organic substances. These compounds consist of
molecules containing carbon and hydrogen, and include
aromatics, olefins and paraffins
As such, the emission of VOCs during wood firing is
influenced by the same factors affecting CO. Typically, VOC
emissions while stoker-firing wood and bark fuels do not
exceed 0.05 lb/106 Btu (0.02 g/ MJ) heat input, expressed as
methane.

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Toxic Air Pollutants
This is a large category of air pollutants that could have
hazardous effects. The EPA had only promulgated
standards for arsenic, asbestos, benzene, beryllium,
mercury, radio nuclides and vinyl chlorides for certain
defined industries. Toxic pollutants for which emissions
are to be regulated. The list includes a wide range of
simple and complex industrial organic chemicals and a
small number of inorganic+, particularly heavy metals.
The EPA has identified hundreds of categories of air
toxics sources, among which are municipal solid waste
combustors, industrial boilers, and electric utility boilers.
For these combustion sources, mercury has been the
primary focus.

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Mercury
Mercury Present in only trace amounts in coal,
mercury is released during the combustion process as
elemental mercury, and is predominantly in the
vapor phase at the exit of the furnace. Emissions from
utility plants are extremely low.
Mercury in some chemical forms is very toxic. From
whatever source, mercury can find its way into water
sources where it can be converted into water soluble
species such as methyl-mercury by microorganisms
and accumulate in the fatty tissues of fish.
Consumption of contaminated fish is the main
identified risk to humans.

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Carbon Dioxide (CO2)
CO2 is one of several so-called greenhouse gases which
may impact the climate and contribute to global
warming. CO2 is emitted from a variety of naturally
occurring and manmade sources including the
combustion of all fossil and hydrocarbon based fuels.
Improving the power cycle efficiency (more power
from less fuel) and the use of fuels with less carbon
content are potential methods to address CO2
emissions from any combustion source. Another
option is separation and capture followed by
sequestration.

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Air pollution control technologies
The strategies for control of all emissions from a utility or
industrial boiler are formulated by considering design fuels,
kind and extent of emission reduction mandated, and
economic factors such as boiler design, location, new or
existing equipment, age and remaining life.
SO2 control strategies and technologies
SO2 emissions from coal-fired boilers can be reduced using
pre-combustion techniques, combustion modifications and
post-combustion methods.
Pre-combustion These techniques include the use of natural
gas or low sulfur oil in new units or the use of cleaned
(beneficiated) coal or fuel switching in existing units.

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Combustion modifications
These techniques are primarily used to reduce NOx emissions but can
also be used to control SO2 emissions in fluidized-bed combustion
where limestone is used as the bed material. The limestone can
absorb up to 90% of the sulfur released during the combustion
process.
Sorbent injection technologies
Sorbent injection, while not involving modification of the combustion
process, is applied in temperature regions ranging from those just
outside the combustion zone in the upper furnace to those at the
economizer and flue work following the air heater. Sorbent
injection involves adding an alkali compound to the coal
combustion gases for reaction with the SO2. Typical calcium
sorbents include limestone [calcium carbonate (CaCO3)], lime
(CaO), hydrated lime [Ca(OH)2] and modifications of these
compounds with special additives. Sodium or magnesium based
compounds are also used.

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Wet and dry scrubbing technology
Worldwide, wet and dry scrubbing or flue gas desulfurization (FGD) systems
are the most commonly used technologies in the coal-fired electric utility
industry.
In the wet scrubbing process, a sorbent slurry consisting of water mixed
with limestone, lime, magnesium promoted lime or sodium carbonate
(Na2CO3) is contacted with flue gas in a reactor vessel. Wet scrubbing is a
highly efficient (> 97% removal at calcium/ sulfur molar ratios close to 1.0),
well established technology which can produce usable byproducts.
Dry scrubbing involves spraying an aqueous sorbent slurry into a reactor
vessel so that the slurry droplets dry as they contact the hot flue gas [~300
oF (~149 oC)]. The SO2 reaction occurs during the drying process and results
in a dry particulate containing reaction products and un-reacted sorbent
entrained in the flue gas along with fly-ash. These materials are captured
downstream in the particulate control equipment.
Dry scrubbing is a well established technology with considerable
operational flexibility. The waste residue is dry.

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NOx control technologies
NOx emissions from fossil fuel-fired industrial and utility
boilers arise from the nitrogen compounds in the fuel and
molecular nitrogen in the air supplied for combustion.
Conversion of molecular and fuel nitrogen into NOx is
promoted by high temperatures and high volumetric heat
release rates found in boilers. The main strategies for reducing
NOx emissions take two forms:
1) modification of the combustion process to control fuel and
air mixing, and reduce flame temperatures, and
2) post-combustion treatment of the flue gas to remove NOx.

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Combustion modification
This approach to NOx reduction can include the use of low NOx
burners, combustion staging, gas recirculation or reburn
technology.
Post-combustion
The two main post-combustion techniques for NOx control are
selective non-catalytic reduction (SNCR) and selective catalytic
reduction (SCR). In SNCR, ammonia or other compounds such
as urea (which thermally decomposes to produce ammonia)
are injected downstream of the combustion zone in a
temperature region of 1400 to 2000F (760 to 1093C). SCR
systems remove NOx from flue gases by reaction with
ammonia in the presence of a catalyst (see Chapter 34). SCR is
being used worldwide where high NOx removal efficiencies
are required in gas-, oil- or coal-fired industrial and utility
boilers.

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Particulate control technologies
Particulate emissions from boilers arise from the
noncombustible, ash forming mineral matter in the fuel that is
released during the combustion process and is carried by the
flue gas. Another source of particulate is the incomplete
combustion of the fuel which results in unburned carbon
particles.
Coal cleaning Historically, physical coal cleaning has been applied
to reduce mineral matter, increase energy content and provide
a more uniform boiler feed. Although reduction in flue gas
particulate loading is one of the potential benefits, coal
cleaning has been driven by the many other boiler performance
benefits related to improved boiler maintenance and
availability and, more recently, the reduction in SO2 emissions.

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Mechanical collectors
These are generally cyclone collectors and have been widely used on small
boilers when less stringent particulate emission limits apply. Cyclones are
low-cost, simple, compact and rugged devices. However, conventional
cyclones are limited to collection efficiencies of about 90% and are poor at
collecting the smallest particles. Improvements in small particle collection
are accompanied by high pressure drops.
Dust collector
Mechanical dust collectors are used after the last heat trap on the boiler to
collect the larger size flyash particulate, sometimes as protection for the ID
fan. They typically consist of multi-cyclone tubes enclosed in a casing
structure. The tubes consist of outer inlet tubes with spin vanes and inner
tubes used without recovery vanes. The dust collector efficiency is in the
range of 65 to 75% at an optimum draft loss of 2.5 to 3.0 in. wg (0.62 to 0.75
kPa). Due to the abrasive nature of the flyash, the outer collection tubes and
cones are made of high hardness (450 Brinell) abrasion resistant material.

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Precipitator Electrostatic Precipitators (ESP)
Precipitator Electrostatic Precipitators (ESP) are typically
used after the mechanical collector to reduce the particulate
concentration in the flue gas and to meet environmental
requirements. Due to the high carbon content in the fly-ash, it
is important to reduce the fire potential in the precipitator. It is
necessary to ensure no tramp air enters the precipitator and
that the fly-ash is continuously removed from the hoppers.
Hopper level detectors and temperature detectors alert the
operator. Installations can be equipped with fire fighting
apparatus such as steam inerting. Other suppliers recommend
de-energizing the precipitator if a predetermined oxygen
content in the flue gas is exceeded.
ESPs are available in a broad range of sizes for utility and
industrial applications. Collecting efficiency can be expected to

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Electrostatic precipitators (ESP)
be 99.8% or greater of the inlet dust loading. ESPs are
considered to be less sensitive to plant upsets than fabric
filters because their materials are not as sensitive to
maximum temperatures. They also have a very low
pressure drop. ESP performance is sensitive to fly-ash
loading, ash resistivity and coal sulfur content. Lower
sulfur concentrations in the flue gas can lead to lower ESP
collection efficiency. ESPs tend to collect coarser particulate
more easily, whereas a fabric filter tends to have a more
uniform collection efficiency across the particle size range.
Therefore, a fabric filter has higher collection efficiency of
fine particulate than an ESP. The desire to further control
sulfuric acid mist emissions and very fine fly-ash has led to
the utilization of wet ESPs downstream of wet flue gas
desulfurization systems.

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Fabric filters
These filters, also commonly referred to as bag-houses, are available in a
number of designs (reverse air, pulse jet, and shake/deflate), each having
advantages and disadvantages in various applications. Applications include
industrial and utility power plants firing coal or solid wastes, plants using
sorbent injection and spray dryer FGD, and fluidized bed combustors.
Collection efficiency can be expected to be at least 99.9% or greater. Fabric
filters have the potential for enhancing SO2 capture in installations
downstream of sorbent injection and dry scrubbing systems

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References:
1. Steam its Generation & Use
(Edition 41) by The Babcock &
Wilcox Company.
2. Wikipedia

Prepared by:
Saba Power Plant
shoeb.siddiqui@sabapower.com
shoeb_siddiqui@hotmail.com
www.youtube.com/shoebsiddiqui

Steam generator part 3

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Steam generator part 3