CONTENTS OF THE TRAINING MANUAL

1.INTRODUCTION TO BOILER AND SELECTION

1.1 What is a Boiler

1.2 Classification of Boilers
1.3 Guidelines for Water tube Boilers
1.4 Guidelines for Fire tube Boilers
1.5 Natural Versus Force Circulation boilers
1.6 Heat Recovery Steam Generator
1.7 Firetube Boilers
1.8 Firetube Boiler Design
1.9 Boiler Selection
1.10 Payback Analysis
2. CONSIDERATION IN DESIGN AND OPERATION OF SOLID FUEL
BOILER
3. FIRING SYSTEMS INCLUDING BURNERS
4. WATER TREATMENT FOR BOILERS
5. BOILER INSTRUMENTATION & CONTROL
6. DEAERATOR & DOSING SYSTEMS
7. BOILER EMISSION & CONTROL
8. VALVES & THEIR FUNCTIONS

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1.0 INTRODUCTION TO BOILER & ITS SELECTION
1.1 WHAT IS A BOILER
Broadly speaking a boiler is a device used for generating
a) Steam power generation, process use or heating
b) Hot water for heating purposes
A boiler is also closed pressure vessel for generating steam under pressure. It includes all the
mounting fitted to such vessels that remains wholly or partly under pressure when steam is shut –
off.
Steam Boiler : Consists only of the containing vessel and convectional heating surface.
Steam generator : Covers the whole unit, encompassing water wall tubes, super heaters, air
heaters and economizers.

1.2 CLASSIFICATION OF BOILERS

Boiler can be classified in many ways and some of the ways are as follows:-

1. By Uses
2. By Steam – water Circulation
3. By Pressure / Boiler Size
4. By type fuel or Heat Source
5. By Firing Method
6. By Method Of removing Slag In Furnace
7. By Boiler Layout Form
8. By Nature Of Support
9. By Nature Of Draft
10. By Number of drums

The above classification can be explained as follows:-

1. By Uses

Utility Boiler
To produce steam for electric power generation. Large capacity. High steam parameters,
high boiler efficiency, completely water cooled furnace with burners when pressure is grater than
or equal to 14mpa usually with reheater.

Industrial Boiler
To produce steam for heating and process, etc. Smaller capacity, lower steam parameters,
furnace with burners, stokers or fluidized beds, no reheater.

Marine Boiler
As a source of motive power for ships. Compact general shape, lighter boiler weight, mostly fuel
– oil fired, no reheater.

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2. By steam – Water Circulation
Natural – circulation Boiler
The circulation of the working fluid in the evaporation tube is produced by the difference in
density between the stem – water mixture in the risers and water in the downcomers. With one or
two drums, can only operate at subcritical pressure.

Forced Multiple Circulation Boiler

The circulation of the working fluid in the evaporation tube is produced
forcedly by means of a circulating pump included in the circulating circuit. With single drum or
separators, can only operate at subcritical pressure.

Once Through Boiler

No drum, the working fluid forcedly passes through the evaporating tubes only under the action
of the feed – water pump, can operate at subcritical and supercritical pressure.

Combined – circulation Boiler

There are a circulating pump, a back pressure valve, and a mixer in the circuit. At starting the
back pressure valve is opened and the boiler operates as a forced multiple circulation boiler, on
attaining the specified load, the circulating pump is switched off, the back pressure valve is
closed automatically, and the boiler operate at subcritical and supercritical pressure.

3.By Pressure

Low and middle pressure boiler (<10 Mpa)

Used as industrial boilers, natural circulation, some with boiler bank, furnace with burners or
with stockers, no reheater.

High Pressure boiler (10 – 14 Mpa)

Used as utility boilers for large capacity once through or combined circulation, with reheater, the
prevention of pseudo – film boiling and high temperature corrosion should be considered.

4. By Fuel or Heat Sources

Solid Fuel Fired Boiler

Cost is mainly used: The component of fuel and the characteristics of ash are important
influential factors for boiler design.

Fuel Oil Fired Boiler

With higher flue gas velocity and smaller furnace volume.

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Gas fired Boiler
Natural gas or blast – furnace gas are mainly used with higher flue gas velocity and smaller
furnace volume

Waste Heat Boiler

Utilizing waste heat from industrial process as the heating sources.

5. By Firing Method

Boiler with Stokers

Mainly used as industrial boilers.

Boiler with burners

Mainly used as utility boilers or large capacity industrial boilers

Boilers with Cyclone Furnace

Applicable at coal having low slag viscosity and low iron content; fuel is fired in a water –
cooled cylinder, and the flame is whirled by either tangential coat dust – air jets from burners or
tangential high speed jets of secondary air (80-120 m/s); as is removed from the furnace in liquid
form.

Boiler with Fluidized Bed

Solid – fuel particles (1-6mm) are place onto a grate and blown from burners with an air flow at
such a speed that the particles are lifter above the grate and are burned in suspending state; used
as industrial boilers for burning low – grade solid fuels.

6. By Method Of Removing Slag In Furnace

Boiler With Dry Ash Furnace

Applicable to coals with high – ash fusion temperature; the ash removed from the hopper bottom
of the furnace is solid and dry.

Dofer With Slag Tap Furnace

Liquid form slag flows to the wet bottom of the furnace (a pool of liquid slag) and tapped into a
slag tank containing water.

7. By Boiler Layout Form

Tower shape, inverted shape, etc

8. By Nature of Support

Bottom Supported Boilers

The whole boiler is supported at the bottom and expands upwards

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Top Supported Boilers
The whole boiler is supported from top through structural beams and expands downwards.

9. By the Type of Draft

Natural Draft Boiler

No fans in the system . Chimney natural draft is used for boiler

Forced Draft Boiler

The complete resistance of the boiler taken care by the forced draft fan. The boiler will be under
positive pressure.

Induced Draft Boiler

Complete resistance of the boiler is taken care by induced draft fan. The boiler will be under
negative pressure.

Balanced Draft Boiler

Boiler resistance upto furnace is taken care by FD fan. The resistance from furnace to chimney is
taken care by ID fan. The furnace will be near Zero Pressure. (-5 to –10 mmWC)

10.By Number Of Drums

Single Drum Boilers

Only one drum will be provided for the boiler.

Bi – drum Boiler
One steam drum and one water drum will be provided for the boiler.

Multi – Drum Boiler

More than two drums are provided.

1.3 GUIDELINES FOR WATER TUBE BOILERS

1. They are suitable for high steam pressure and temperature applications and large
capacity units, even exceeding a million pounds per hour of steam or gas flow

2. Extended surfaces can be used to make the design compact if the gas stream is clean.
Compared to a fire tube boiler, a water tube with extended surfaces is much smaller
and will weigh less, particularly if the gas flow is large, say exceeding 100 pph

3. Various types of fuels can be fired with ease including solid and fuels. The water
cooled membrane wall enclosure make an excellent furnace and can sized to match
any firing or ash disposal equipment.

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 4. If the gas stream is dirty, provisions can be made for cleaning the tubes by using
rapping mechanisms or soot blowers. Access lanes as required may be easily
provided. Wide spacing may be provided at the front end of the boiler, where there is
more chance for slagging or fouling, followed by the sections with smaller spacing at
the cooler end.

In a fire tube boiler, it is very expensive or not feasible to build the boiler in two
parts or use different tube sizes to accommodate slagging or temperature concerns.
The best that can be done is to use a multi – pass design with different tube sizes in
each pass. On – load cleaning is difficult in fire tube boilers

5. The superheater, if used, may be located in an optimum gas temperature region to

minimize corrosion concerns or to reduce the metal temperature. In a fire tube boiler,
the only locations for the seuperheater are at the front of rear end, making the design
less flexible.

6. Due to the lower volume of water hold up compared to a fire tube boiler, the start up
periods and the drum response to load changes can be quicker in a water tube boiler.

7. Of the gas pressure is higher, say 5 to 30 psig, then the water tube boiler may be
located inside a shell. However the cost increases significantly if the gas pressure
and size increase. A fire tube boiler may be better suite.

8. A water tube boiler is less forgiving to poor water chemistry and tube failures can
occur faster compared to fire tube type. On has also to be wary of water tube boilers
with extended surfaces, which operate at a much higher heat flux and tube wall
temperature compared to bare tube designs or fire tube boiler.

9. Due to the higher heat transfer coefficients associated with gas flow over the tubes,
water tube boilers required less surface area and hence the gas pressure drop can be
lower than in a fire tube boiler.

10. A water tube boiler will be more expensive in the smaller gas flow range say
50,000pphor less compared to fire tube type but less expensive for larger mass flows.
For some situations such as gas turbine exhaust where the ration of gas to steam flow
is high and the pinch point is low, water tube boilers with extended surface may be
the only choice as drop and will be extremely large.

1.4 GUIDELINES FOR FIRE TUBE BOILERS

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1. Usually limited to steam pressures, say a maximum of 1400 psig. for waste heat
recovery boiler but limited to 300 psi for fire tube boilers. For the same pressure the
thickness required for tubes subject top external pressure is much higher compared to
that for tubes subject to internal pressure. The thickness of the sheet also increases
with pressure. Thus the tube bundle weight and hence the cost increases steeply at
higher pressures compared to water tube designs.

2. Suitable for high gas pressures. In hydrogen plants for example once comes across
gas streams at very high pressure on the order of 300 to 600 psi; it is easy to handle
these streams in fire tube boilers compared to water tube designs. The boiler surfaces
have to be located inside large pressure vessels if a water tube design is used, making
it very expensive.

3. If the gas stream is dirty and contains dust it is easier to handle the gas stream in a
fire tube boiler as only the tubes have to be cleaned, whereas in a water tube boiler
the casing as well as the external surface of the tubes get dirty and are difficult to
clean. However if the gas stream has slagging constituents as in municipal solid
waste incineration plants, cleaning the boiler is easier with waste tube boilers with
soot blowers or rapping mechanisms.
If the front end of the tube sheet and the tube inlet get plugged. In a fire tube boiler,
online cleaning is difficult. One way of handling this situation is to use a multi pass
boiler. The first pass can be designed with very large tubes and the subsequent passes
can have smaller tubes.

4. When a large duty has to be transferred with a low pinch point as in gas turbine
exhaust boilers, the surface are and hence the length required and the gas pressure
drop become very large and hence uneconomical for such applications. With water
tube boilers on can use finned tubes for clean situations and hence make the boiler
compact with consequent lower gas pressure drop and cost. For comparable
velocities, the heat transfer coefficient inside the tubes is lower compared to that
outside bare tubes; hence bare tube water tube boilers are sometimes preferred to fire
tube boilers.

5. Fire tube boilers can handle high gas temperature on the order of 2400 °F if the tube
sheet is properly designed. The tube sheet is lined with refractory and ferrules are
used to transfer the heat flux at the tube sheet inlet the tubes where the water steam
mixture keeps them cool. Figure 2-2 shows the arrangement. The use of refractory
minimizes the temperature differential across the tube sheet and hence is
recommended when gas temperature exceeds say 1800 °F

6. High steam purity can be obtained by using an external elevated steam drum with
internals.

7. Economizer and superheater can be added as required, in a water tube boiler it is easy
to split up the evaporator and locate the superheater in a cooler temperature zone

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 beyond a screen section, while with a fire tube the choice of location is either at the
inlet or exit of the boiler. Alternatively two fire tube boilers could be built with a
superheater in between but this is an expensive proposition.

8. Since the water volume and weight in a fire tube boiler is more compared to a water
tube boiler, the response to load changes is netter with water tube boilers. while fire
tube boilers are sluggish.

1.5 NATURAL VERSUS FORCED CIRCULATION BOILERS

1. No circulations pumps
(Hence no power consumption, pump failure concerns)

2. Can tolerate higher heat fluxes due to vertical tubes.

3. More real estate required.

4. Lesser supporting steel but more stack material.

5. Tube wall temperatures are more uniform around tube periphery and hence less
thermal fatigue due to different heat transfer coefficients between steam and water,
the top of horizontal tubes are hotter compared to vertical tubes.

6. Startup rates is a function of overall heat transfer coefficients, which is dependent on

gas side flow, temperatures. Hence not much of a difference.

1.6 HEAT RECOVERY STEAM GENERATORS

Application

1. Gas Turbine Exhaust

2. Incineration System (Solid, liquid, Gaseous)

3. Sulfur Recovery / Sulfuric Acid Plants

4. Hydrogen Plants

5. Flue gas streams From Kilns

Types of Waste Heat Boilers

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 1. Single Shell Fire Tube

2. Elevated Drum Fire Tube

3. Single / Multi – Pass Fire tube

4. Single / Multi – Pass Water tube

5. A, D, O – Type Water tube Boilers

6. Combination Fire Tube / Water Tube (Bare / Finned)

1.7 FIRE TUBE BOILERS

The boiler is an energy conversion apparatus that takes in fuel, air and water in the right
proportion and produces hot gases, steam and radiant heat. The hot gases are allowed to escape
up the chimney when as much useful heat has been extracted from it. The radiant heat lost is kept
to a minimum by the insulation around the boiler. Steam is the only usable portion of the
process.

Boilers in the industry are the nerve center of the operation and its well being is of utmost
importance. Boilers that generate steam are used in the industry for the following functions:
1. Heating
2. Drying
3. Cooking
4. Laundry
5. Sterilizing
6. Power generation
7. Many other applications

Boiler Classification
Boilers are classified generally by the relative arrangement of the hot gas passages. Basically
there are four types of fire tube boilers.

In this type of boilers the construction can be of horizontal and vertical shell. The vertical shell
type of fire tube boilers are normally used in marine application due to space constrains. Most of
the industrial boilers are of horizontal construction.

These boilers are called fire tube boiler because the hot flue gas, after combustion. Passes
through the tubes and heat up the water. The water space surrounds the tubes. The tubes range
from sizes of 1¼” diameter up to as high as 3” diameter tubes. These tubes are usually straight
and relatively short in order for the hot gases to have a low-pressure loss in passing through
them.

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The water surrounding the tubes is usually contained by a large diameter cylinder vessel (drum).
For these reasons the fire tube boilers are seldom designed for more than 250 psig would require
thickness of the shell and tube plates to be excessive. Fire tube boilers have a fairly large volume
of containing water relative to the steaming rate, so that these considerable amount of store heat
energy in the boiler. This makes for steady steaming rates and smooth operation of the boiler.

Fire tube boilers can be classified as follows:

1. Single pass Boilers
2. Dry back Boilers
3. Wetback Boilers
4. Reverse Flame Fire tube Boilers

1. Single Pass Boiler

These are the first generation of fire tube boilers where combustion is normally by solid fuel
such as coal and wood. These boilers were used extensively on locomotives and have now
been transferred to industrial use. They consist of a water box chamber and a one pass fire
tube where the heat transfer is by convention.

2. Dry back Boilers

These are the old type of boilers where the radiant heating surface consists only of the
furnace. The reversal chamber consists of refractory work. A lot of valuable heat is lost to the
refractory at the reversal chamber. These boilers are cheaper to make as compared to the
other boilers.

3. Wetback Boilers
These are newly designed boilers where the radiant heating surface consists of the furnace,
the wrapper plate and the wetback rear plate.
To understand what wetback design really means requires an understanding of the principle
and purpose of the wetback design concept. The wetback design reemploys a completely
water cooled turn around (gas reversal chamber) where the product of combustion leaves the
furnace and enters the second pass. This high temperature zone at the furnace exit is water
cooled by the wetback chamber and increases the proportion of radiant heating surface. This
lowers the gas temperature into the convectional tubes and increases the overall fuel to steam
efficiency.

It has been shown that the rear tube plate metal temperature of the wetback boiler is
significantly lower compared to the dry back. This results is longer life, lower running cost
and lower thermal stress.

The wetback design also replaces the hot refractories and insulating material. The wetback
boilers can use both pressure jet and rotary cup type burners.

4. Reverse Fire Tube Boilers

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These boilers are constructed such that the flame or hot gas after combustion is made to
reverse in the furnace. There is no reversal chamber. The radiant heating surface consists
only of the furnace. The furnace is of a larger diameter as compared to the wetback chamber
to enable the flame to reverse.
The only type of burner applicable for this type of boiler is pressure jet burner. The flame
should be narrow and long and this would require very high fuel oil pressure and correct
nozzle size in order to produce this type flame pattern.
These boilers are normally two pass in nature.

1.8 FIRE TUBE BOILER DESIGN

The basic boiler design problem is to dispose the total heat absorbing surface in a manner
that will obtain the maximum available heat from the fuel and the product of combustion. At
the same time there is the economic problem of obtaining maximum efficiency at the lowest
cost (initial or long term evaluation). For maximum overall economy, each component part
and process must be correctly proportioned and properly related to the other elements and
processes so that the unit as a whole comprises a balanced design.

Whatever the design criteria, the steam or hot water, must be safely contained and must be
delivered in the desired condition with respect to capacity, pressure, temperature and steam
quality.

Fire tube Boiler Rating

One may be confused over the years over the various claims and counter claims concerning
the proper rating of boilers. When boilers were first made, it was ascertained that day
coupled with steam engines of the right size would create a system equivalent of a certain
number of horses in work performed. It was then the practice to rate the boilers by the
number of horses they replaced.

As years went by, it was determined that on the average the boilers were employing about 10
ft² of heat absorption surface for each boiler horsepower rating. Then came the high steaming
rate industrial boilers, where the old rating method was pushed aside. Today when the boiler
horsepower is used as the rating, it is often based on 5ft² of heating surface per boiler
horsepower.

Today it is a more acceptable practice to consider a boiler horsepower as being the

evaporation of 34.5 lb / hr of steam from and at 212 ºF.

However it’s a good idea to ignore the term horsepower as the boiler rating can be expressed
as:
1 The actual steam / hot water output per hour at the designed temperature and
pressure in lb / hr or kg / hr.
2 The actual heat output from the steam or hot water per hour expressed in
Btu / hr or MW / hr (Megawatt / hour)

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 3 Evaporation from and at 212 ºF which is the amount of water in lbs that would be
evaporated at 212ºF and 14.7 psig by the heat put into the steam at 212ºF.

Example
a) Boiler is rated at 20,000 lb / hr from and at 212ºF. But the actual
working pressure is 150 psig.
What would be the actual evaporation at 150 psig assuming the feed water
temperature is 86ºF (30ºC)?

Let H = Total heat require to evaporate 1 lb of steam

h = 1194.1 Btu / lb (total heat in one lb of steam at 150psig)
t = 86ºF
then H = h – (t - 32)
= 1194.1 – (86 - 32)
= 1140.1Btu / lb
Latent Heat of steam from and at 212ºF = 970.4 Btu / lb
Factor of evaporation
= 970.4 = 0.85
1140.1
Actual evaporation at 150 psi with feed water of 86ºF
= 20,000 x 0.85 = 17,0213 lb / hr

b) Boiler is rated at 20,000 lb / hr from and at 212ºF

What is the horsepower rating?
Boiler horsepower = 20000 / 34.5 = 579.7 Bhp
Heat transfer in Fire tube Boiler
Boiler capacity is directly related to the heat transfer efficiency and the amount of heating
surface.
Transfer of boiler heat from the fuel and the combustion products into the water or steam may
occur in three ways
1. By radiation
2. By convection
3. By conduction

Usually a combination of these modes enter into all the varied phases of heat transfer. The
transfer of heat is affected to varying degrees by the following factors.
1. The temperature of the flame of the combustion product.
2. Turbulence and impingement of the hot gases or the water backed surfaces.
3. Slag, fly – ash or soot accumulation of the fire side.
4. Scale or sludge accumulation on the water side.
5. Conductivity of the metal
6. Turbulence and movement of steam and water in its circulation path.

It is possible to absorb a great amount of furnace heat by radiation. As a result, careful

consideration must be given to the proper design and location of the radiant heat absorbing
surface. The hating surface on which the fire shines is referred to as the direct or radiant surface;

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the surface in contact with gases only is referred to as the indirect or convection surface. The
amount of heating surface, its distribution and the temperature or either side, all influence the
capacity of the boiler. Direct heating surface is more valuable than indirect as it is subjected to
higher temperatures, and also because it is in a position to receive the full radiant energy of the
fuel and its flame. With non – luminous flames, the direct heating surfaces lose their value and
hence require much bigger heat absorbing surfaces to deliver the same amount of steam or hot
water.

The proportion of heat transfer in package fire tube boiler area is determined by the furnace
diameter and length, the tube diameter and tube length as well as the number of tubes in various
passes.

The distribution of heat absorption in fire tube boiler maybe as follows depending on individual
designer.
1. Furnace + wetback chamber - 70 to 85%
2. Second Pass - 10 to 20%
3. Third Pass - 5 to 10%

In order for good transfer of heat, furnace diameter is critical – not too big to cause too much
drop in temperature hence causing carbon formation, but not too small to cause flame
impingement.
For convectional heat transfer areas, velocity of flow is very important as this is necessary to
create turbulence for better convection heat transfer effect.
A wetback boiler will have a smaller boiler dimension due to its additional direct heat absorption
surface and in package boilers and small steaming rate boiler, it is rarely necessary to introduce
the fourth pass on consideration of high draught losses.

Fire Tube Boiler Pressure

The properties of steam depend very much on its pressure. To understand this let us consider the
formation of steam at constant pressure. Take 1 lb of water initially at 0ºC being heated in a
vessel fitted with movable piston such that the pressure in the vessel will remain constant. The
temperature of the water will rise until the water boils at a temperature known as the saturation
temperature (Tsat), which depends on the pressure in the vessel.

After the boiler temperature is reached, steam begins to be formed, during which time the
temperature remains constant. When all the water is converted into steam, the contents of the
vessel will be a mixture of water and steam known as wet steam.

Eventually all the water, including those droplets held in suspension, will evaporate and at this
instant, the substance is known as Dry saturated steam. Temperature remains at Tsat.

As heating continues further, the temperature begins to rise again and the steam is now known as
superheated steam, and behaves as a gas. To define the condition of superheated steam it is
necessary to state both the pressure and temperature of the steam, and the term ‘degrees of
superheat’ is used to refer to the amount by which the temperature of the superheated steam
exceeds the saturation temperature for the exiting pressure.

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As the pressure of the steam changes, the proportion of heat required to convert the water from
one state to another also changes. The pressure rating of a boiler depends very much on the type
of material used and the thickness of the material which will meet allowable stress requirement
at the specific temperature and pressure.

Through the operating pressure for fire tube boilers rarely exceeds 250 psig, there are fire tube
boilers that have been designed to operate at 300 psig. Design of fire tube boilers at pressure
above 300 psig would call for very thick material to meet the allowable stress and fabrication of
such boiler would be very costly.

Boiler Steam Temperature

The pressure of the boiler determines the fire tube boiler steam temperature unless superheated
steam is produced. Hence in order to obtain the temperature of the steam required, the boiler may
be either designed to the operating pressure corresponding to the temperature required or if the
temperature is higher than the saturation temperature, super heaters are used to raise the steam
temperature to its desired value.

Superheaters are normally located at the end of the second pass outlet and third pass inlet. The
superheater-heating surface has to be large in order to accommodate the heat transfer, as the
space in fire tube boiler is limited.

The design temperatures for the various components of the boiler shall be determined as follows:
a) For the shell and other components not designed for heat transfer purposes,
the design temperature may be taken as the maximum temperature of the
contained water.
b) For fire tubes the design temperature shall be determined as follows:
t. = (ts+25)
ts = temperature of saturated steam.

Other factors Influencing Fire Tube Design

In addition to the basics of unit size, steam pressure and steam temperature. The boiler designer
must also consider other factors that influence the overall design of the fire tube boiler.

Fuel

As different fuel has different burning characteristic, flame temperature, ash content etc., the
furnace and combustion chamber must thus be designed in such a way so as to accommodate the
differences. Like for example, oil and gas have a much higher heat release rate per unit furnace
volume than solid fuel, fuel oil has a much higher radiant heat transfer property than gas, and the
designed of solid fuel fired furnace is determined to a very large extent by the quantity of ash
formed and the property of the ash.

Boiler back end temperature is also limited by the pressure of objectionable chemical elements
and compounds in the fuel e.g. sulphur which causes corrosion in various stages.

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Water / Steam Circulation

Adequate circulation results in the water absorbing heat from the tube metal at a rate which
maintains the tube temperature at or below design conditions. Adequate circulation also keeps
the tube within the other physical and chemical limitations required by the inside and outside
environment.

There are other detailed design considerations essential for an efficient boiler, amongst them:
1. Stream Separators
2. Combustion Air Supply
3. Foundation and Supports
4. Smoke Emission Problem
5. Ease of Operation and maintenance.

1.9 BOILER SELECTION

There may be many criteria than can be considered when selecting a boiler to meet the
application needs. Some of the criteria are as discussed here

1. Codes and standards requirements

2. Steam or Hot Water
3. Boiler load
4. Number of boilers
5. Performance considerations
6. Commercial value / payback

1.0 Codes and standards

There are a number of codes and standards, laws, and regulations covering boilers and related
equipment that should be considered when designing a system. Regulatory requirements are
dictated by a variety of sources and are all focused primarily on safety and health.

Codes commonly used are:

i. BS 2790 (Fire tube Boilers) BS 1113 (Water tube Boilers)
ii. ASME Section 1
iii. Australian Standards
iv. Din standards

2.0 Steam or Hot Water

Determine the facility’s application in order to see how the boiler will be used. Keep in mind, the
primary purpose of the boiler is to supply energy to the facility’s operation – for heat,
manufacturing process, laundry, kitchen, etc. The nature of the facility’s operation will dictate
whether a steam or hot water boiler should be used.
Hot water is commonly used in heating applications with the boiler supplying water to the
system 80 to 100ºC. The operating pressure for hot water heating systems usually is 30 psig to
125 psig. Under these conditions, there is a wide range of hot water boiler products available. If

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system requirements are for hot water of more than 115ºC a high temperature water boiler should
be considered.

Steam boilers are designed for low pressure or high pressure applications. Low pressure boilers
are limited to 15 psig design, and are typically used for heating applications. High pressure
boilers are typically used for process loads and can have an operating pressure of 75 to 700 psig.
Most steam boiler systems require saturated steam.

Steam and hot water boilers are defined according to design pressure and operating pressure.
Design pressure is the maximum pressure used in the design of the boiler for the purpose of
calculating the minimum permissible thickness or physical characteristics of the pressure vessel
parts of the boiler. Typically, the safety valves are set at or below design pressure. Operating
pressure is the pressure of the boiler at which it normally operates. The operating pressure
usually is maintained at a suitable level below the setting of the pressure relieving valve(s) to
prevent their frequent opening during normal operation.

Some steam applications may require superheated steam. It should be noted that superheated
steam has a high enthalpy, so there is more energy per pound of steam and higher (drier) steam
quality. One example of an application where superheated steam may be required is with a steam
turbine. The turbine’s blades require very dry steam because the moisture can destroy the blades.
When very high pressure or superheated steam is required, an industrial watertube boiler should
be selected.

3.0 System Load

System load is measured in either Btu / hr of steam (at a specific pressure and temperature).
When discussing the steam load, we will include references to both steam and hot water.
However, not all situations or criteria apply to both. It would be nearly impossible to size and
select a boiler(s).
Without knowing the system load requirements. Knowing the system load provides the following
information:
- The boiler(s) capacity, taken from the maximum system load requirement.
- The boiler(s) turndown, taken from the minimum system load requirement.
- Conditions for maximum efficiency, taken from the average system load
requirement.

Determining the total system load requires an understanding of the type(s) of load in the system.
There are three types of loads: heating, process and combination.

3.1 Heating Load

A heating load is typically low pressure steam or hot water, and is relatively simple to define
because there is not a great deal of instantaneous changes to the load. And once a heating load is
computed, the number can easily be transferred into the equipment size requirements. A heating
load is used to maintain building heat. Cooling loads, using steam to run an absorption chiller.
Also are included when computing a heating load. Characteristics of a heating load include large
seasonal variations but small instantaneous demand changes. The boiler should be sized for the
worst possible weather conditions.

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3.2 Process Load
A process load is usually a high pressure steam load. A process load pertains to manufacturing
operations, where heat from steam or hot water are used in the process. A process load is further
defined as either continuous or batch. In a continuous load, the demand is fairly constant – such
as in a heating load. The batch load is characterized by short – term demands. The batch load is a
key issue when selecting equipment, because a batch – type process load can have a very large
instantaneous demand that can be several times larger than the rating of the boiler. For example,
based on its size a heating coil can consume a large amount of steam supply to fill and pressurize
the coil. When designing a boiler room for a process load with instantaneous demand, a more
careful boiler selection process load with instantaneous demand, a more careful boiler selection
process should take place.

3.3 Combination Load

Many facilities have a mixture of loads – different types of process loads and combination of
heating and process loads. The information given on heating and process loads should be taken
into consideration when dealing with a combination load.

3.4 Defining Load Variations

Loads vary and a power plant must be capable of handling the minimum load, the maximum load
and any load variations. Boiler selection is often dictate by the variation in load demand rather
than by the total quantity of steam or hot water required.

There are two types of loads variations daily and instantaneous.

3.5 Daily variations
Daily variation can occur due to variations in the work hours or the heat required at various times
of the day or weekend. Minimum and maximum seasonal variations mentioned earlier may
already reflect these changes if they occur daily. If not the minimum and maximum daily loads
should be included.
The daily variations define the size of the load that the boiler(s) must handle. Daily variations
also help define the number of boilers and turndown requirements.

3.6 Instantaneous Demands

Instantaneous demand is a sudden peak load change that is usually of short duration. These types
of loads are sometimes hidden. Many machines or processes are rated in pounds of steam per
hour or Btu / hr as running loads, under balanced operating conditions and there is no recognition
given to ‘cold startup’, ‘peak’ or ‘pickup loads’. The instantaneous load demand is important to
consider when selecting a boiler to ensure that these load variations are taken into account. If the
instantaneous demand is not included in the system load calculations, the boiler(s) may be
undersized.

3.7 System Load Summary

The load demand matrix should be analyzed in determining the minimum, maximum, and
average system loads.

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3.8 Load Tracking
Load tracking is the ability of a boiler to changes steam or hot water demand. Most often
associated with process loads, load tracking focuses on the boiler’s ability to supply a constant
volume of steam at the required pressure.

The ability of the boiler to track a variable load depends on the boiler type, burner turndown
capability, feed water valve control, combustion control design. If the analysis of the load shows
highly variable load conditions, a more complex control package may be necessary. This type of
control is achieved with sophisticated boiler management systems.

If the application has instantaneous load demands, whereby a large volume of a steam is required
for a short period of time, a boiler with a large energy storage reserve, such as a fire tube should
be considered. If the application dictates large variances in load demand. Where the load swings
frequently for long periods of time of time, the best choice is probably a water tube type boiler,
because it contains less water and can respond to the variances more rapidly.

In all cases, operation of the burner should be taken into account in selecting a boiler the meet
system demand. The burner will require proper operating controls that can accurately sense the
varying demands and be capable of the turndown requirements. The boiler feed water valve and
control designs are also critical if load swings are expected.

4.0 Number of Boilers

4.1 Back – Up Boilers
When selecting the boiler(s), consideration should be given to back up equipment to
accommodate future expansion, emergency repairs and maintenance. There are a number of
considerations for a backup boiler.

4.2 Back – Up Boilers

Heating systems and non-critical loads that do not resulting a sudden loss of production
generally have little or no backup. While this is not recommended. It is still common practice.
These types of applications rely on the ability to make repairs quickly to reduce downtime.
The risk involved in having no bake up is a total loss of heat when the boiler is not in service.

When process or heating loads use multiple boilers during peak times, and one boiler during
most other times, the availability of an additional boiler to provide full back up during
maximum demand should be considered.

In applications with critical steam or hot water requirements, laws or codes may require a
backup. Even if laws or codes do not require a backup, there are many cases where the
operation cannot tolerate downtime. For example, a hotel uses hot water 24 hours a day,
seven days a week. During periods of maintenance or in an emergency, a backup boiler is
required.

4.3 Downtime

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Another way to determine whether a backup boiler is a wise decision is to compute the cost
of downtime to the owner or the user as shown in the following example:
A chemical company manufactures dry cell battery compound in a batch process. The
process temperature must be maintained within 2 degrees. The boiler shuts down on a flame
failure. They have 20 minutes to recover steam or the batch is scrap. The value of the
products is $250.000

4.4 Boiler Turndown

Boiler turndown is the ratio between full boiler output and the boiler output when operating
at low fire. Typical boiler turndown is 4:1. For example 40000 Pound / hr boiler with a 4:1
turndown burner will modulate down to 10000 Pound / hr horsepower before cycling off.
The same boiler with a 10:1 turndown burner will modulate down to 40 horsepower.

The ability of the burner to turn down reduces frequent on and off cycling. Fully modulated
burners are typically designed to operate down to 25% of rated capacity. At a load that is
20% of the rated capacity, the boiler will turn off and cycle frequently.

A boiler operating at low load condition can cycle as frequently as 12 times per hour or 288
times per day. With each cycle pre and post purge airflow removes heat from the boiler and
sends it out the stack. The energy loss can be eliminated b keeping the boiler on line. And if
there’s a sudden load demand, the startup sequence cannot be accelerated. Keeping the boiler
on line assures the quickest response to load changes. Frequent cycling also accelerates wear
of boiler components. Maintenance increases and more importantly the chance of component
failure increases.

As discussed earlier, boiler(s) capacity requirement determined by many different types of

load variations in the system. Boiler over sizing occurs when future expansion and safety
factors are added to assure that the boiler is large enough for the application. If the boiler is
oversized the ability of the boiler to handle minimum loads without cycling is reduced.
Therefore capacity and turndown should be considered together for proper boiler selection to
meet overall system load requirements.

5.0 Performance Considerations

Three important considerations pertain to fuels, emissions and efficiency. All three have
important impact on boiler performance, and can affect long term boiler operating costs.

5.1 Fuels
Remember from an operating perspective fuel costs typically account for approximately 10%
of a facility’s total operating budget. Therefore fuel is an important consideration. Normally
the fuels of choice are natural gas, diesel or light fuel oil. Increasingly stringent emission
standards have greatly reduced the use of heavy oil and solid fuels such as coal and wood. Of
the fossil fuels, natural gas burns cleanest and leaves less residue : therefore less maintenance
is required.

It can be advantageous to supply a boiler with a combination burner that can burn two fuels
independently – for example oil or natural gas. A combination burner allows the customer to

19
take advantage of ‘peak time’ rates, which sustaintially reduces the cost of a term of gas
when operating ‘off peak’ by merely switching to the back up fuel. Dual fuel capability also
is beneficial if the primary fuel supply must be shut down for safety or maintenance reasons.

Some waste stream can be used as fuel in the boiler. In addition to reducing fuel costs firing
an alternate fuel in a boiler can greatly reduce disposal costs. Waster streams are typically
used in combination with standard fuels to ensure safe operation and to provide additional
operating flexibility.

5.2 Emissions
Emission standards for boilers have become very stringent because of the clean air
regulations. The ability of the boiler to meet emission regulations depends on the type of
boiler and burner options.

5.3 Efficiency
Efficiency is used in the measure of economic performance of any piece of equipment. In the
boiler industry, there are four common definitions of efficiency, but only one true
measurement. Following are the definitions and how to measure efficiency.

5.4 Combustion Efficiency

Combustion efficiency is the effectiveness of the burner only and relates to its ability to
completely burn the fuel. The boiler has little bearing on combustion efficiency. A well-
designed burner will operate with as little as 15 to 20% excess air, while converting all
combustibles in the fuel to useful energy.

5.5 Thermal Efficiency

Thermal efficiency is the effectiveness of the heat transfer in a boiler. It does not take into
account boiler radiation and convection losses – for example, from the boiler shell. water
column piping etc.

5.6 Boiler Efficiency

The term ‘boiler efficiency’ is often substituted for combustion or thermal efficiency. True
boiler efficiency is the measure of fuel – to – steam efficiency.

5.7 Fuel – To – Steam Efficiency

Fuel – to – Steam efficiency is the correct definition to use when determining boiler
efficiency. Fuel – to – Steam efficiency is calculated using either of two methods. The first
method is input – output. This is the ratio of Btu input x 100.
The second method is heat balance. This method considers stack temperature and losses,
excess air levels, and radiation and convection losses. Therefore, the heat balance calculation
for fuel – to – Steam efficiency is 100 minus the total percent stack loss and minus the
percent radiation and convection losses.

5.8 Stack Temperature and Losses

20
 Stack temperature is the temperature of the combustion gases (dry and water vapor) leaving
the boiler. A well-designed boiler removes as much heat as possible from the combustion
gases. Thus lower stack.

Temperature represents more effective heat transfer and lower heat loss up the stack. The
stack temperature reflects the energy that did not transfer from the fuel to steam or hot water.
Stack temperature is a visible indicator of boiler efficiency. Any time efficiency is
guaranteed; predicted stack temperature should be verified.

Stack loss is a measure of the amount of heat carried away by dry flue gases (unused heat)
and the moisture loss (product of combustion), based on the fuel analysis of the specific fuel
being used moisture in the combustion air, etc.

5.9 Excess Air

Excess Air provides safe operation above stoichiometric conditions. A burner is typically set
up with 15 to 20% excess air. Higher excess air levels result in fuel being used to heat the air
instead of transferring it to usable energy, increasing stack losses.

5.10 Radiation And Convection Losses

Radiation and convection losses will vary with boiler type, size, and operating pressure. The
losses are typically considered constant in Btu / hr, but become a larger percentage loss as the
firing rate decreases. Boiler design factors that also impact efficiencies of the boiler are
heating surfaces, flue gas passes, and design of the boiler and burner package.

5.11 Heating Surface

Heating surface is one criterion used when comparing boilers. Boilers with higher heating
surface per boiler horsepower tend to be more efficient and operate with less thermal stress.
Many package boilers are offered with five square feet of heating surface per boiler horsepower
as an optimum design for peak efficiency.

5.12Flue gas Passes

The number of passes that the flue gas travels before exiting the boiler is also a good
criterion when comparing boilers. As the flue gas travels through the boiler it cools and
therefore changes volume. Multiple path boilers increase efficiency because the passes are
designed to maximize flue gas velocities as the flue gas cools.

5.13 Integral Boiler / Burner Package

Ultimately, the performance of the boiler is based on the ability of the burner, the boiler, and
the controls to work together. When specifying performance, efficiency, emissions,
turndown, capacity and excess air all must be evaluated together. The efficiency of the boiler
is based in part, on the burner being capable of operating at optimum excess air levels.
Burners not properly designed will produce CO or soot at these excess air levels, foul the
boiler, and substantially reduce efficiency. In addition to the boiler and burner, the controls
included on the boiler (flame safeguard, oxygen trim etc) can enhance efficiency and reduce
overall operating costs for the customer. A true packaged boiler design includes the burner,
and controls as a single engineered unit.

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 1.10 PAYBACK ANALYSIS

There are many factors that affect the decision to purchase a particular piece of boiler room
equipment. There are economic considerations in the decision process. The procedure presented
can be applied to equipment selection and the economic evaluation of alternative systems.

The effect of a single piece of equipment can be a significant part of the overall transfer of
energy from the fuel burned to the thermal energy of the steam or hot water delivered. The
performance of equipment, such as the boiler, stack gas recovery systems (economizer),
condensate recovery systems (deaerator, etc) oxygen trim systems, and blow down heat recovery
systems should be considered. Efficiency gains from each piece of equipment need to be
evaluated individually in the overall system to determine the incremental fuel cost savings.
Savings from efficiency gains are used to evaluate the payback potential of the equipment.
Payback simply refers to the time period that will elapse before the cumulative cost savings will
equal the incremental capital cost of the equipment selected.

This section provides a procedure and a set of tables and figures to assist in assessing the
economic justification of purchasing higher performance equipment or additional energy savings
equipment (e.g. economizers, oxygen trim controls, etc). This procedure may also be used to
evaluate the operating cost impact of different system configurations.

Having defined a basic system configuration, and having identified equipment that would yield
incremental performance improvement (and investment), the pay back analysis sequence is
straight forward and can be summarized as follows:-
1. Estimate boiler fuel consumption rate
2. Estimate annual fuel use.
3. Estimate annual fuel cost
4. Determine potential incremental efficiency improvement.
5. Estimate potential annual fuel savings
6. Determine the pay back period for the investment
7. Refine the analysis
Remember, the lowest cost product is not necessarily the most economic choice. In fact, most
often it is not the best choice.

Step – 1: Boiler Fuel Consumption Rate

Compare the fuel consumption rates of two boiler configuration with different fuel – to – Steam
efficiency or, as a base fuel rate for a given boiler configuration. Find the appropriate boiler size
and the efficiency on the table to find the associated fuel consumption.

Step – 2: Annual Fuel Usage

Multiply the hourly fuel consumption rates by the annual hours of operation to determine the
annual fuel usage rate.

Step – 3: Annual Fuel Cost

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Step – 4: Incremental Efficient Improvement
If an improvement is being added to a boiler (economizer, oxygen trim, etc) that is designed to
improve the efficiency of the boiler by “x” percent (incremental efficiency gain). Use figure 1 to
take the base system efficiency (bottom) and the incremental efficiency gain (right side) to
determine the actual improvement in the efficiency to be used for the cost savings in Step 5.

Step – 5: Annual Fuel Savings

Determine the annual fuel savings based on the annual fuel cost and system efficiency
improvement.

Step – 6: Payback period

The payback period is the years required to recover the capital investment. To determine
payback simply divide the capital cost of the equipment by the annual savings.

To determine the amount of capital available based on a known payback period. multiply the
annual savings by the payback period required.

Step – 7: Refine the Analysis

Additional economic issues (maintenance, necessity of equipment, etc) should be considered in
order for the final conclusions to be reached.

2.CONSIDERATION IN DESIGN AND OPERATION OF SOLID

FUEL BOILER
INTRODUCTION
Industrial steam generation is a vast and diverse field. Such diversities as nature and extent of
steam requirements, modes of operation, boiler types and sizes, fuels and firing methods, present

23
themselves in their multitudes. In this presentation an attempt is made to cover as
comprehensively as possible, the design considerations of solid fuel fired industrial boilers, most
extensively used in this part of the World, more particularly boilers using Palm Fibre, Wood
Waste as Fuel. For the purposes of this presentation, an “Industrial Boiler” is taken to be a
stationary boiler in which part or all of the steam generation occurs in convective tubes (as
compared to all steam generation occurring in radiant tubes in a Power / Utility Boiler)

CLASSIFICATION
Apart from the statute classification (like Class-I, etc) one might classify a boiler from various
angles, based on:
- Tube side medium : Smoke Tube / Water Tube
- Fuel fired / heat source : Coal / oil / Gas / Cellulose (Bio- mass) Waste heat
- Construction : Bi-drum, single drum, shell & tube
- Circulation : Natural / Forced
- Draft : Balanced / Pressurized
- Installation : Outdoor / Indoor

Each of the above signifies distinctive and characteristics design methodologies. If the
parameters of the boiler are prefixed, a comprehensive two-line description of the boiler
emerges:
e.g.
20 TPH, 21 kg / sq.cm (g), dry saturated, Bi-drum Natural Circulation, Water tube, Palm Fibre
fired, Balanced Draft indoor Boiler.

DESIGN INPUTS
Following are the basic design input conditions required, so as to proceed with thermal design.
1.Boiler Parameters:
Steaming capacity, outlet steam pressure, steam temperature, feed water inlet temperature.
2.Fuel:
Fuel characteristics and fuel ash characteristics.
3.Boiler Efficiency:
4.Ambient Conditions

There are several other requirements arising out of statutory conditions, individual preference
and stipulations concerning mechanical construction and auxiliaries selection, etc.

INFLUENCE ON DESIGN & OPERATION

Based on the above inputs, how these influence the design and operation of the boiler in general
and more specifically, palm waste fired boiler is discussed further.

BOILER PARAMETERS
The basic thermal performance design is set out to meet with the given boiler outlet parameters
of steam flow, temperature, pressure and the feed water inlet temperature of the boiler beginning
with the determination of heat duty.

24
The heat duty of the boiler is the difference in the heat content of the steam at the outlet
parameters and the water at the inlet conditions.

This heat duty is distributed amongst the various heat transfer sections.

In a smoke tube boiler, between flue tube and convective tube, in water tube boiler, between
furnace water walls, super heater boiler bank, economizer and air heater. Economizer or air
heater or super heater may or may not be present in all boilers (In certain older generation of
water tube boilers even furnace water walls were not provided)

A judicious distribution of the heat pick up in various heat transfer sections of the boiler give rise
to an optimal thermal design.

The feed water inlet temperature has a bearing with reference to low temperature corrosion at the
back end economizer section of the boiler. Depending upon the fuel sulphur content flue gas
outlet temperature, there could be a problem of dew point corrosion. A low feed water
temperature results in corresponding low metal temperature of economizer tube leading to dew
point corrosion problems.

A low boiler flue gas temperature also leads to the problem of low temperature corrosion for
both economizer as well as air preheater. Some steps considered to resolves these are:
- Keep higher level of flue gas outlet temperature
- Preheat feed water so as to increase feed water inlet temperature to
economizer.
- Use protective cast iron sleeves on the economizer
- Eliminate economizer or air preheater
- Provide corrosion resistant material for air preheater
- Compromise on increased replacement maintenance of back end heat
recovery sections.

The steam pressure and temperature parameters of the boiler completely dictate the mechanical
design, as per the mandatory code of the pressure parts of the boiler.

EFFICIENCY
The overall thermal efficiency of the boiler influences the initial cost as well as the running fuel
cost. High efficiency increases the initial cost and decreases the running fuel cost while low
efficiency has the opposite effect.
While from energy conservation point of view, the heat available in the fuel must be utilized to
the maximum for generation of steam, there is a techno – economic optimum level to be chosen
depending upon the individual circumstances.
Expensive fuels which are purchased by the end user would dictate high efficiency levels. Waste
fuels which are generated during the process (and not purchased from outside), most often the
boiler efficiency would be dictated by balancing the plant steam requirement us, the waste fuel
generated in the process in – house. This is particularly so when disposal of excess waste fuel is
not very attractive. Perhaps such is the case in a typical palm oil mill where palm waste.(palm

25
fibre, shell) is used as a fuel. However, there could be instances where high efficiency could be
adopted to generate excess steam out of the available waste fuel, use the excess steam to generate
additional power either for own use or for exporting. This is basically an exercise in steam –
waste fuel power balance. Various configurations are possible in such a co – generation system.

The boiler efficiency depends on several factors:

- Excess air
- Flue gas outlet temperature leaving the boiler
- Moisture and hydrogen content in the fuel
- Ambient temperature and moisture
- Completeness of combustion
- Effectiveness of insulation
Out of the above factors, the fuel analysis and ambient conditions are not controllable by the
designer.

Based on the above, following heat losses occur in a boiler that contribute to higher or lower
efficiency
- Dry gas loss
- Moisture loss
- Radiation loss
- Unburnt carbon loss
- Other unaccounted loss

When the above losses are expressed as percent of Heat input, efficiency in percentage is given
as 100 – percent losses.

Typical excess air levels for various fuels are given below for industrial boilers.

Fuel Excess Air

Coal : 30 – 40%
Natural gas : 10%
Oil : 15%
Low Btu gas : 15%
Cellulose : 30 – 45%

Typical flue gas outlet temperature is in the range of 180 Deg.C to 250 Deg.C

AMBIENT CONDTIONS
The ambient conditions where the boiler would be located also influence the thermal design and
to such an extent the mechanical design of the boiler. The ambient temperature, relative
humidity, plant site elevation have an effect in the performance design of the boiler. The seismic
zone factor is to be taken into account while carrying out the mechanical structural design.

GENERAL ARRANGEMENT

Based on the above considerations, typical General Arrangements of boiler are discussed below.

26
ARRANGEMENT – I (fig.09)
This shows the arrangement of a Palm Fibre Fired Water Tube Boiler.
The boiler is of bi-drum type with water walls and boiler bank tubes for steam generation. There
are no back end heat recovery surfaces like Economiser or Air Preheater. This boiler is a
balanced draft with ID and FD fans and is of bottom support design.
The combustion System is of pneumatic spreader with stationary grate.

ARRANGEMENT – II (fig.10)
Another typical arrangement of a modern high efficiency water tube boiler firing cellulose fuel is
shown in the figure.

This boiler has membrane water wall, pendant superheater, cross baffled boiler bank, economizer
and an air heater as the heat transfer sections. The combustion system comprises of pneumatic
spreader with dumping grate.

ARRANGEMENT – III (fig.11)

A typical pressure part arrangement of smoke tube (shell and tube) is given in the Figure.

This is with the construction called three pass Full Wet back. In this arrangement, the flue gases
pass through the first furnace pas and are reversed back by a fully immersed reversal chamber.
The flue gases then enter the second pass of multi tubular section. They further reverse in
direction in the front smoke box and enter into the third pass of multi tubular smoke tube section.
The flue gases leaves the boiler through a rear smoke box section.

PRESSURE PART ARRANGEMENT

A typical pressure part arrangement of a bi – drum water tube boiler is shown in the fig.No.12

Water walls
The water walls (radiant section) of the boiler can be made of different constructions
(Ref.fig No13)

Spaced tube
With refractory backed, the water wall tubes are pitched widely and connected in the circulation
system through headers or directly from drum to drum. The water wall tubes are backed with
layers of refractory and insulation bricks, further supplemented with wool insulation and cased
by sheet steel. Some times an outer red bricklayer is provided. This is some what an older design.

Tangent Tube
Here the water wall tubes are placed almost tangent nearly touching each other. On the ambient
side of the tubes, thin layer of castable refractory is applied. An additional layer of insulation is
kept and cased. The furnace effectiveness is improved over the spaced tube. However this type
of design entails difficult mechanical construction and is not the preferred design.

Welded wall (Membrane wall )

27
This is the most modern concept where the tubes are placed at a fairly close pitch and closed
with a flat fin making the water-cooled furnace a gas tight chamber. On the outside, only a layer
of insulation is provided and cladded. This gives the maximum effectiveness of the furnace,
minimum air ingress (i.e. good control over excess air of operation), nil refractory or insulation
bricks, fast response of the boiler and lower installation cycle time. With the advent of highly
improved welding techniques over the past few decades, this type of design has become the most
preferred choice.

Boiler Bank
The boiler bank comprises of several rows of tubes connecting the upper drum (Steam Drum)
and lower drum (Water drum). These are usually expanded into the drum. This arrangement
shows a cross-baffled design which increases the effectiveness of the bank tubes.

Drum Internals
It is important that the steam is delivered with low moisture and very high purity of the order of
98 to 99% by means of effective steam water separation. The steam drum is provided with
internals of suitable design to achieve this. Purity of steam assumes greater importance when
there is a superheater in the boiler and when the steam is fed to a turbine.

Superheater
When a superheater is provided, this is usually located at the furnace outlet above the “Nose”
portion of the furnace and before the boiler bank. The superheater receives some portion of direct
radiation from the furnace and the balance heat is picked up as convective heat along with non –
luminous radiation. The superheater design is quite critical both from performance design as well
as mechanical design points of view. Too high or too low superheat temperature is adversely
affect the performance of the down stream turbine. The fact that superheater has a vapour
medium flowing inside and is located in a high temperature zone and there is a possibility of
moisture carry over from drum, makes it a critical component from the stand point of design.

COMBUSTION SYSTEM
A typical air and gas scheme for the cellulose fired boiler (e.g. palm fibre) is given in the Figure
No.14

The fuel is fed into the furnace by the fuel feeders and pneumatically injected through a
pneumatic spreader mounted on the front of the boiler combustion chamber. The SA fan delivers
high pressure air to achieve pneumatic spreading through spreader (at times a separate fuel air
fan can be used for this purpose). A stationery grate is provided at the bottom of the furnace
(alternately, a dump grate can be used). The fuel undergoes partial suspension firing and the
balance is burnt on the grate. The secondary air is attempted into the furnace above the grate has
high velocity jets through suitable nozzles located above the grate. The primary and secondary
air systems are provided with necessary dampers, so as to achieve proper proportioning and
distribution of the air.

ECONOMIZERS

28
 Depending on stack temperature, an economizer can save up to 6% or more in fuel dollars
by recycling the invisible heat in the flue gas being lost to the atmosphere.

There is certainly nothing new about an economizer but heretofore they were only
economically feasible in new, larger boiler installations. With the cost of fuel rising and out
commitment to conserve energy. a low cost, easy to install economizer is a logical
investment for any size boiler.

The economizers are developed with both the new and retrofit market in mind. The
economizer can be in – line installed in either a vertical or horizontal position.
Complicated, space consuming ducting and transition pieces are not required.

Ample flue gas area provides negligible flue gas pressure drop eliminating the necessity of
boiler adjustments. The flue gas heat is literally scrubbed out by means of spiral type flue
gas spinners. Should the flue exhaust temperature drop below desirable minimums. It is a
simple matter to shorten each gas spinner to raise the stack temperature to prevent
condensation. This is merely a safety feature and will normally not be required providing
the initial selection is correct.

A 1% increase in efficiency is obtained for every 6ºC of temperature increases in boiler

feed water. For instance, if you raise feed water from 90ºC to 120ºC you will decrease the
fuel required providing the initial stack temperature, the more Bru’s can be recycled.

Another way to express fuel savings is approximately a 1% increase in efficiency is

obtained for every 19ºC reduction in flue exhaust temperature.

On a multiple economizer installation, one feature worth considering would be small return
line from the economizer to the Deaerator. The purpose of the line would be to preheat the
unit with hot feed water before starting the boiler. This will significantly reduce any stack
condensation from initial firing. If you are doubt as to perspective purchaser’s stack
temperature, it might be a good idea to purchase a thermometer for this purpose. You can
almost always get someone to drill a small hole in the breeching to install thermometer.

Comparison Of Economizer Vs Combustion Air Heater

The use of a economizer in retrofit applications has several advantages over a combustion
air heater.

Economizer Air heater

1. First cost is less 1. Higher first cost
2. Low draft loss 0.5 – 1.0” W.C 2. Draft loss between 3.0–5.0” W.C
3. Does not affect location of fans 3. Requires remote location of forced draft
fan

29
 4. No adverse effect on burner or adjustments 4. Requires enlarged, insulated burner wind
box
5.Only requires piping to convey heated 5. Large insulated ductwork needed to co
water convey heated air
6.Reduces pollution by a reduction in 6. Because combustion temperature is
nitrous oxides increased an increase in nitrous oxides
results cannot be used with today’s low
NOx burners
7. Easily cleaned with use of soot 7.Must be shut down to be cleaned by
Blower while in operation washing.
8.Avoids severe cold end corrosion because 8. Requires steam coil to heat incoming
feedwater temperature keeps metal temperature air or bypassing of flue gas at low
above water dew point even at low ends loads to prevent severe cold end
Corrosion.
9.Steam generator absorption and combustion 9. An air heater is not effective in these
efficiency increased by lowering firing rate ways.
and heat release while als acting as a heat
accumulator.

10.Boiler heating surface is increased 10. Boiler capacity cannot be increased

allowing greater boiler output if to same degree by adding an air heater
required
11. Can be arranged to serve more 11.Almost impossible to arrange an air
than one boiler heater to serve more than one boiler.
12. Does not affect the type or 12.Requires more costly parallel or
Performance of combustion control metering combustion control system.
equipment .

3.0 FUELS & FIRING SYSTEMS INCLUDING BURNERS

FUEL
Fuel is the single most important factor in determining the design of the boiler. Fuel and the
associated fuel ash characteristics play a vital role in designing the boiler configuration and firing
system design.

Fuel Analysis
Based on the heat duty of the boiler, boiler efficiency and heating value of the fuel, the quantum
of fuel to be fired is arrived at. With the fuel analysis known and excess air selected, the quantity

30
of total combustion air required, flue gas generated, dry flue gas and moisture in flue gas, flue
gas combustion and other characteristics are derived. These form the basis for further efficiency
and heat transfer calculations. Typical fuel analysis of palm fibre is given below.
Proximate analysis % By weight
Fixed Carbon 11 - 12
Volatile matter 44 – 45
Total moisture 38 – 39
Ash 5–6
Higher heating value 5250 Btu / pound
High volatile matter indicates high ignitability and burnability of the fuel. High fixed carbon
indicates difficult – to – burn fuel.

Ultimate Analysis % by weight

Hydrogen 3.7
Carbon 28.8
Sulphur 0.2
Nitrogen 0.8
Oxygen 22.4
Ash 5.1
Moisture 39.0
100.0

Fuel Ash
The characteristics of the fuel ash determine the fouling tendencies, corrosion and erosion nature
and influence the layout of the various boiler sections. The ash temperatures are used to predict
the slagging potential on the furnace walls. The ash quantity has a direct bearing on the deposit
build up on the furnace walls. The silica present in the ash gives an indication with regard to the
erosion property.

One of the key indices in the thermal design of the boiler is to choose proper furnace exit gas
temperature and the ability to predict the same. The selection of proper temperature ensure that
the down stream convective section will not be affected by excessive fouling while at the same
time an optimal level of radiation heat pick up takes place.

Sodium and potassium salts may condense as sticky deposits on super heater tubes causing high
temperature corrosion. For solid fuels, such as poor grade coals, lignite etc. careful
considerations must be given regarding the fuel ash characteristics while designing the furnace.
Apart from ash quantity, ash fusibility temperatures, certain other ratios like base / acid, iron /
calcium, silica / alumina, etc. are required to be analyzed while sizing the furnace.
The nature and characteristics of ash in the palm waste are not severe.
Typical ash analysis of palm fibre:
Initial deformation temperature : 1120 Deg.C
Softening temperature : 1180 Deg.C
Fluid temperature : 1280 Deg.C

Typical composition % by weight

31
Sio2 63.0
AI2O3 4.5
CAO 7.2
FE2O3 3.9
MGO 3.8
NA2O 0.8
K2O 9.0
SO3 2.8
CO2 2.2
Others Balance

FIRING SYSTEM
Depending upon the fuel characteristics and capacity of the boiler, several firing system
configuration are available for solid fuels like:
- Manual stoking with fixed grate
- Gravity feeding with chain grate
- Spreader stoker with traveling grate
- Spreader stoker with fixed or dump grate
- Pulverized fuel firing (for coal / lignite)
- Fluidized bed combustion

When palm fibre is the fuel, one of the best choices of firing system would be spreader stoker
with fixed / dump grate. This is due to the following factors.
- High volatile matter in palm fibre gives good ignitability and burnability.
- Low ash content indicates simple grate designs.

Hence this fuel lends itself easily to part suspension firing and balance firing on the grate when
employed in a spreader stoker fixed grate / dump grate system.

With reasonable quality coal and high capacity units, pulverized fuel firing would be dictated.
With poor quality coals and difficult to burn fuels, high sulphur fuels, medium capacity units, the
choice would be Fluidized Bed Combustion.

Air Distribution
With appropriate selection of firing system, a proper air distribution scheme must be employed
for effective combustion. Ability to distribute the fuel uniformly and providing proper mixing of
fuel and air, form the key to good combustion. A good firing system design takes care of the
following important aspects in terms of air distribution in a typical cellulose-firing unit.
- Divisioning, apportioning and locating different air streams are vital. The
total air required for combustion is divisioned and distributed as follows:
- Part of the air to pneumatically spread the fuel. This should be aimed at
proper trajectory of the fuel, distribution of fuel covering the full furnace
action.
- Under grate primary air.
- Secondary air above the grate at adequate penetration velocities.

32
 - Optionally part of the air as tertiary air just above the furnace.

OIL & GAS FIRING SYSTEMS

FUEL OIL

Crude is produced from the oil fields and undergo many changes through numerous
processing in refinery. A modern refinery typically consists of atmospheric distillation unit to
recover cooking gas, petrol and kerosene. This is followed by vacuum distillation where
additional diesel and light fuel oil is produced. The heavy residual oil further undergoes
catalytic cracking to increase products of lighter oil fractions like petrol, gas, kerosene and
diesel oil.

The advanced process of thermal cracking and catalytic cracking produce fuel oil having
higher percentage of carbon. Therefore, these fuels are more difficult to burn.

IMPURITIES IN THE FUEL OIL

Fuel oil contains impurities that would effect in combustion properties. Some of the
impurities are discussed briefly.
1) WATER

Practically all the fuel oils contain water in varying amount. Water contamination occurs
from condensation, steam leakage, air vent and also from fuel suppliers. The water
contamination varies from trace to as high as 10%. Water is found either in emulsified
form or as entrapped droplets.

Water in emulsified form is not harmful for combustion. It rather helps combustion. But
water promotes corrosion of tank, pipeline and oil heater. Water decreases calorific value
of the fuel. Large droplets of water may produce the vapour lock in oil preheaters or
effect atomization.

2) SLUDGE

Sludge is commonly found in the industrial fuels. Sludge is black to brown semi-solid
product of oil. It mainly consists of emulsified oil, water, solid sediment and asphaltenes,
polymerization, oxidation and biological action on oil. During storage, these sludges
slowly settles. Heating of oil during storage increases the settling rate. Water,
temperature and oxygen from air increase the sludge formation during storage.

Sludge accumulates at the bottom of the tank and leads to filter chocking and strainer
plugging. It fouls the oil preheater and progressively reduces the oil preheat temperature.
Sludge also plugs the burner nozzle. Oil sludge sediment has the higher calorific value.
But it is difficult to atomize sludge at normal burner pressure and temperature. Therefore

33
 sludge doesn’t burn efficiently and leave behind unburnt products like tar, soot and
clinker.

3) ASPHALTENES

Asphaltenes are solid organic compounds in fuel oil. The percentage of such compounds
varies in the fuel. Use of secondary refining processing like visbreaking and catalytic has
sharply increased the percentage of asphaltenes in fuel oils. Typically, asphaltenes have
82-86% and have higher carbon to hydrogen ratio. Asphaltenes should be regularly
dispersed in fuel. They however, tend to accumulate and form tar like lumps. Such lumps
are formed at the bottom of the tank, in sludge, pipelines and in strainers. Separation of
as asphaltenese reduces fuel calorific value. The agglomerated asphaltenese are difficult
to burn and lead to formation of soot clinkers in boiler and increase stack emission. Fuel
additives keep asphaltenese in dispersed condition and improve their combustion.

4) WAXES

Fuel oil contains large amount of waxes or paraffins. Waxes have high melting points.
Therefore, at room temperature wax precipitates out from the fuel oil. This cause gel or
solidification of the fuel. The temperature at which the fuel turns solid-gel or it stops
flowing is called as pouring point. Waxes increase the pour point of oil.

5) ASH

The ash content in the fuel oil seldom exceeds 0.2%. Generally, ash contents increases
with asphaltenese in fuel. Vanadium, Iron, Sodium, Nickel, Zinc and common ash
constituents. Vanadium, Nickel and Sodium are most predominant in the fuel,
concentration in crude range from 1 to 400 ppm depending upon source Table-1.

In refining process, these impurities get concentrated in residual oil, which is used as fuel oil in
industries.

The ash is released as inorganic oxides at high temperatures and due to oxidation in high flame
zone during combustion, organic vanadium oxidizes to V2O3, V2O5. Sodium is usually present
as salt, Vaporizes in flame, and reacts with Vanadium and Sulphur. This reaction takes place in
the following manner.

Na2So4 + V2O5 2NaVo3 + So3

Sodium vanadyl vanadate, and sodium vanadate have lower melting point. The molten ash form
slag on metal surface and causes corrosion. Vanadium also catalyses formation of So3 which
leads to cold end corrosion. Fuel additives alter the nature of Vanadium ash making it non-
sticky.

FUSION TEMPERATURES OF COMPUNDS TYPICALLY FOUND IN ASH OF BOILER

FIRED ON RESIDUAL FUELS

34
Non Slag: Forming components of ash : Ash Fusion Temperature oC

Aluminium Oxide –Al2O3 2030

Calcium Oxide – CaO 2570
Nickel Oxide – NiO 2090
Vanadium Tetraozide – V2O4 1967
Vanadium Triozide – V2O2 1967

Slag: Forming Components of ash:

Magnesium Sulphate – MgSo4 1124

Vanadium Pentoxide – V2O2 690
Sodium Sulphate – Na2So4 888
Nickel Sulphate – NiSo4 841
Sodium meta vendate – Na2O V2O5 629
Sodium pyro vendate – 2Na2O V2O5 654
Sodium orthovandate – 3Na2 V2O5 866
Nickel ortho vandate – 3NiO V2O5 899
Sodium vanadyl Vandate – Na2O V2O4 V2O5 624

SULPHUR
Crude oil contains in inorganic sulphate and in organic form as di sulphides, thiophenes,
thivasten and marcaptans. Sulphur gets concentrated in residual oil which id then used in as fuel.
Most of the sulphur is removed during the refining process. The sulphur contents in the fuel oil
depend on source of crude oil and refining process. It is upto 4.5% in furnace oil and 1.5% in
LSHS.

Inorganic sulphates during combustion react with vanadates to form low melting slag formation
o
compounds. Sodium sulphates have melting point as low as 480 C. They promote fouling,
slag formation and corrosion. Organic sulphur is converted to So3 during combustion. Higher
concentration of S03 in the flue gas Causes severe cold-end corrosion. Fuel additives reduce
slag formation compounds and So3 formation.

VARIATIONS IN FUEL OIL

Crude oil properties are different at each oil production well and change over a period of time.
This is always reflected in furnace oil or LSHS. Also fuel oil is blend of various grades obtained
during refining. Therefore, the quality fuel obtained depends on the refinery, as some of these
factors are given below:

- Crude quality
- Refining process
- Blending process
- Storage method
- Storage time

35
 - Storage temperature

Therefore, continuous variation in the fuel quality is expected. Though, the burners are designed
to take care of some variations, the change in fuel quality affects the boiler efficiency and fuel
consumption.

OIL FIRING SYSTEMS

• Ring Main System – Oil Pressure & Temperature regulation

• Steam and/or electric heater banks

• Gas ignition on start-up

GAS FIRING SYSTEMS

• Gas Pressure Regulators

• High & Low gas pressure switches

Description Rotary Cup Pressure Jet

Turn-down ratio 8:1 4.5 : 1

Operating Pressure 40 psi 300 psi
Pressure drop across burner Low Medium
Maintenance Regularity Daily Fortnightly
Maintenance Cost Low Medium
Air / Fuel Ratio Constant Variable
Fuel Blockages Minimum High
Installed Electrical Power Lower Higher
Medium Oil Temperature 64 Deg.C 110 Deg.C

36
BURNERS

TYPES OF BURNERS

1. Rotary Cup

2. Pressure Jet – On/Off, High-Low, Modulating

3. Steam / Air Atomising

FUNCTION OF BURNERS

• Break-down of oil into fine droplets.

• Mixing with air for optimum combustion (air / fuel ratio)

• Monitoring of air damper movement during start-up.

• Flame supervision (Photo-electric cell, Ultra-Violet Cell and/or ionisation probe) – Dark
& Lighted check).

• Oil Temperature control – low oil start / stop & regulation

• Prepurge & Post-purge operation.

• Fan running conditions – Auxiliary Switches on fan contactor and/or air pressure switch
for separate oil pump drive motor.

ROTARY CUP BURNERS

PRIMARY AIR
Insufficient primary air will result in unsatisfactory atomisation of the oil. Excessive primary air,
particularly on fuel turndown, can result in flame front instability. To assist in the optimisation
of the primary air flow, a butterfly type damper is fitted within the burner machine hinge. This
damper is operated by direct linkage from the burner modutrol motor, so that the flow can be set
correctly for all load conditions and is modulated automatically with load change.

SECONDARY AIR

The secondary air flow, representing approximately 90% of total requirements, is used for flame
shaping and reinforcing flame front stability patterns. The air is usually drawn from the
atmosphere by a backward curved centrifugal fan. Silencers may be fitted to the fan inlet to suit
Noise specifications. The secondary air is distributed evenly within the wind box by adjustable
guide blades. The air is finally discharged through the secondary nozzle, where swirl blades can
be preset to impart the required swirl component.

37
A two blade damper is incorporated in the wind box, on the discharge side of the fan, and is used
to regulate the air flow to match the modulated fuel flow, care being taken to minimise the
excess air level.

TERTIARY AIR

Tertiary air is a very small proportion of the secondary air, part of which is diverted around the
outside of the primary air nozzle and is constrained on the outside by the nozzle shield. The
remainder is fed through holes in the nozzle shield refractory. Basically it is used to keep the
primary air nozzle clean by inhibiting the reversal of small oil droplets onto the primary air
nozzle. It also affects the plane in which the flame front stabilizes.

BLANCED DRAUGHT

The forced draught fan when supplied with the burner, is normally sized to overcome the total
system resistance. In some instances, however, an additional fan is situated at the exit of the
boiler to overcome resistance as the gas passes within the boiler. In this case, a damper on the
exit fan is modulated to maintain a constant pressure in the boiler furnace. The burner fan then
only has to overcome the resistance of the combustion equipment, a constant furnace suction
control unit being fitted to modulate the boiler exit damper.

BOILER CAPACITY & FIRING RATES

Boiler is quoted at 10,000 kg/hr from and at 100 Deg.C

Therefore, Energy output from Boiler = 10,000 x 2256.7

7
= 2.2567 x 10 kJ/hr

If incoming water is at 70 Deg.C energy input = 203 kJ/kg

If boiler steaming at 10 barg (11 bar abs) energy = 2781 kJ/kg

Therefore Actual steam output = 2.2567 x 107 = 9.070 kg/hr

(2781 – 293)

Boiler is quoted at 87% efficiency, thus if the oil used is 42 MJ / kg,

Oil consumption is 2.2567 x 107 = 617.6 kg/hr

42 x 103 x 0.87
Metering of oil is usually in litres and oil density quoted by the oil supplier must be corrected at

the metering point temperature.

Volume correction factor per 1 deg.C = 0.00068

38
Example : Oil density at 15 Deg.C = 0.95

Oil density at 35 Deg.C = 0.95 – ((35-15) x 0.00068)

= 0.936

COMBUSTION PRACTICE

It can be shown that any fuel requires a certain amount of oxygen for chemically correct
(stoichiometric) perfect combustion, i.e.

HEAVY OIL 1 lb of oil required 13.8 lbs/air ) Stiochiometric Air / Fuel Ratios
GAS OIL 1 lb of oil required 14.4 lbs/air )
NATURAL GAS 1 lb of gas required 14.8 lbs/air )

If CO2% sample is taken from the results of the above combustion process, then the percentage
level in the exhaust gases would be:

HEAVY OIL 15.9 – 16.1 % ) Stoichiometric CO2% values

GAS OIL 15.3 – 15.5% )
NATURAL GAS 11.7 – 11.9% )

The above figures are the results of laboratory tests and cannot be achieved on the average boiler
/ burner combination due to lack of time and space within the combustion chamber. If an attempt
were made to achieve these figures the result would be dirty, incomplete combustion, i.e.
excessive smoke and CO on oil firing and excessive CO on oil firing and excessive CO when
firing gas.

Hence, extra air must be added to the process in order to achieve clean combustion, this being
generally known as EXCESS AIR.

Unfortunately, this excess air does lead to various problems.

1. Reduction in the CO2% in exhaust gases (increase O2)

2. Increase in heat loss at the boiler exit.

Both of the above lead to a decrease in COMBUSTION EFFICIENCY, so although excess air
is necessary only sufficient for clean combustion should be used and no more (present practice).

TYPICAL COMBUSTION FIGURES

39
 CO2% O2 CO ppm SMOKE SPOT NO.

Heavy Fuel Oil H.F. 13.0 – 13.5 3.3 Below 250 ppm Below No.4
L.F. 11.0 – 11.5 5.9
“ “ “ “
Gas Oil H.F. 12.0 – 12.5 3.8
L.F. 10.5 – 11.0

Natural Gas H.F. 9.5 – 10.0 3.5 “ “ “ “

L.F. 7.5 - 8.0

RELATIONSHIP BETWEEN CO2, O2 AND EXCESS AIR

CO2 STIOCHIOMETRIC
CO2 ACTUAL = TOTAL AIR

O2% = 20.9 - 20.9 __

Total Air

EXAMPLE An actual CO2% in exhaust gas of 13.5% on heavy fuel oil

TOTAL AIR = 16 = 1.185 = 18.5% Excess Air

13.5

O2% = 20.9 - 20.9 = 3.26%

1.185

CONVERSELY For an O2% of 3.26% on H.F.O.

Total Air = 20.9 = 1.185 i.e. 18.5% Excess Air

20.9 – 3.26

CO2% = 16 (Stoich) = 13.5%

1.1185 (Total Air)

COMBUSTION EFFICIENCY (STACK LOSS)

The easiest method of determining heat lost at the boiler exit, on a day to day basis, is by
monitoring:

A. CO2 (or O2%) in exhaust gases

40
 B. Nett exit gas temperature deg.C i.e. gross – Ambient

EXAMPLE A Burner firing on H.F.O.

HIGH FIRE CO2% 13.5 Nett exit temp. 240 deg.C
LOW FIRE CO2% 11.5 Nett exit temp. 185 deg.C

By use of combustion or calculator chart:

STACK LOSS HIGH FIRE 15.9% (apparent 84.1% Efficiency)

LOW FIRE 14.4% (apparent 85.6% Efficiency)

The above are only combustion losses and seem to indicate that the boiler is more efficient at
low fire than at high fire ?????? This is not the case because there are other losses to be
accounted for when assessing the overall plant efficiency.

These losses are known as “standing” losses and are an accumulation of losses, i.e. Radiation,
blow down, leaks,etc.

Hence : TOTAL LOSS = STACK LOSS + STANDING LOSSES

EXAMPLE Assume with previous example that the standing losses are 3% and the burner
Has a turndown ratio of 6:1

THEN Total loss at High Fire = 15.9 + 3 = 18.9%

= 81.7% overall efficiency

HOWEVER Total loss at Low Fire = 14.4 + (3 x Turndown ratio)

= 14.4 + 18 = 32.4%
= 67.6% overall efficiency
This leads to various conclusions:

1. Minimise standing losses

2. Carry out combustion testing and tuning
3. Avoid whenever possible operating plant at low fire.

COMBUSTION RELATED PROBLEMS

Oil fired burners are easier to control as the variation in quality of the fuel oil are not found over
short periods. The combustion of the fuel takes place in the vapour phase and it is necessary to
fire the oil in such a way that its vapourization is quick and continuous. The heat used for
vapourization is obtained from the flame itself and from the surrounding radiating surface. In
order to vapourize quickly, large surface area is required. This is done by atomization of the fuel
oil. The oil as it passes through the burner, breaks down into minute droplets of 30-50 micron
size. The burner spreads these droplets evenly into the combustion zone. Various burner designs
are available which atomize the oil in different ways. Some of the designs are:

41
 a) Pressure jet: The oil itself is pressurized and passed through a small hole to produce even
spray. Various burner designs are available to improve oil atomization.
b) Steam or air atomization: Compressed air or steam under pressure is used to inject a fine
spray of oil in combustion zone.
c) Rotary cup burner: The rotating cup throw oil droplets in combustion zone. Due to
centrifugal action, the oil is broken down to smaller droplets.

The burner design ensures, intimate, quick oil-air droplets mixture for efficient combustion.

The impurities in the fuel cause problems in combustion process. They are outlined below:

a) Water droplets: The water vapour puts of the flame. This is also known as puffing
flames
b) Sediment: Sediment particle plug the burner tip, which leads to poor
atomization
c) Asphaltene: Solid asphaltene particles cannot atomize easily and lead to
formation of soot and increase emission. Asphaltenes also form
resin like compound at burner tip reducing oil flow.
d) Wax-Paraffin: Predicted wax increases viscosity causes poor atomization and
combustion.

In summary, the impurities in the untreated fuel cause burner plugging, poor atomization,
inefficient combustion and increase stack emission.

POST COMBUSTION PROBLEMS:

The post combustion problem in a system is typical and depends on many factors.

1) Tar-Clinker Formation:

The asphaltene or sludge don’t burn efficiently. The unburnt residue is similar to tar. In
combination with other difficult to burn impurities like waxes and ash, it forms tar-
clinker in furnace. This tar is very hard fused and is extremely difficult to remove. The
clinker is complex compound of carbon-sulphur and ash.

The clinker is acidic in nature and causes corrosion of the furnace and superheater. Its
accumulation causes differential heating of the furnace and excessive deposition may
alter flame geometry and combustion process. This clinker is hard, sticky and it is
difficult to remove by normal methods.

Incomplete combustion of asphaltenes forming soot, which reduce heat transfer and
increase smoke number. The overall combustion efficiency is reduced by cause of
incomplete combustion of asphaltenes.

2) Slagging:

42
 The release of ash depends on the rate of oxidation and extent of oxidation of oil
droplets. During combustion, organic metallic vanadium is oxidized to V2O3, V2O4 and
then V2O5. In flame zone, large pert of vanadium is in V2O5 vapour form. Sodium
reacts with sulphur vapour to form Sodium sulphate. The reactions are:

V + O2 V2O5

Na + So2 + O2 Na2So4

Na2So4 + V2O5 2NaVo3 + So3

Sodium, Vanadium, Sulphur and iron oxides are the most significant elements in fuel ash
deposition. This is because they form they form melting compound having MP 480 -
1250 oF. The flue gas temperature falls within this range. The molten ash sticks to the
tube surface and acts as a nuclear for other ash particles. The slag clinker forming
tendency of oil can be predicted from ash contents, sodium to vanadium ratio, ash
melting temperature and sulphur contamination in the fuel.

3) High temperature corrosion:

Ash causes high temperature corrosion in the furnace. Sodium, Vanadium and sulphur
containing ash causes severe corrosion of furnace tubes and superheater. The corrosion is
caused by the dilution of protective iron oxide film by molten ash and exposure of base
metal to dissolved oxygen in the molten ash. Increase in sodium and vanadium in fuel
increases corrosion rate of high temperature metal surfaces.

4) Acid Smut-Soot emission:

Under certain conditions, oil fired boilers using oil having higher sulphur content,
emitting acidic particulates. The acid smut is generally formed on the surfaces operating
at temperature lower than dew point of the flue gas. Soot absorbs sulphuric acid and such
acidic soot is carried away through stack.

5) Low temperature Corrosion:

Organic sulphur is oxidizes during combustion to sulphur-di-oxide, which is further

oxidized to suphur-tri-oxide. Vanadium-pentaoxide and iron oxide catalyze the above
reaction. So2 condenses with water in low temperature region like air preheater,
economizer and chimney as sulphuric acid. Acid precipitation causes severe corrosion
and promotes fouling of heat exchanging surface.
The dew point, at which sulphuric acid condenses depending on the So3 concentration, is
known as dew point corrosion.
The So3 formation itself depends upon excess air used for combustion.
FUCTION OF FUEL ADDITIVES

43
Fuel oil contains various impurities, each creating unique problems in the boilers. In
order to solve each problem, blends to various chemicals are required. The typical
constituents of the blend are described below:-

Active constituents in Fuel additives

A) Emulsifier:

The emulsifiers are surface-active agents synthesized to emulsify finer droplets of

water in oil and prevent water separation. Larger droplets of oil are however
separated from oil in storage tank.

B) Corrosion inhibiters:

Organic soluble amines are good corrosion inhibiters at lower concentrations.

They absorb on metal surface forming a thin layer preventing attack of salty
water on metals.

C) Sludge dispersants:

Sludge dispersants are polymeric compound and surface-active agent. The

dispersant keeps sludge in suspension. Surface-active agent doesn’t allow
agglomeration and settling due to storage.

D) Pour point Depressant:

The pour point depressant is again a polymeric compound, which doesn’t allow
wax to crystallize and gel. It keeps wax in dispersed condition increasing oil
flowability.

E) Surfactant:

It is a detergent like material, which prevents agglomeration of asphaltene. It also

keeps the heat-exchanging surface clean. The surfactant reduces surface tension
of the oil and helps in atomization to form smaller droplets.

F) Antioxidants:

These chemicals prevent oxidation, polymerization and micro biological

degradation of fuel oil during storage. Antioxidants reduce sludge formation
during storage.

G) Combustion Catalyst:

The catalyst speeds up combustion process in furnace. Fuel burns in shorter and
most completely in the presence of catalyst. Thus asphaltenes, sludge and wax in

44
 fuel burns faster and completely reducing soot formation. Catalyst increases
combustion efficiency and allows operation at lower percentage of excess air.

H) Slag Modifier:

The slag is made non reactive and its fusion temperature is increased by slag
modifier, reducing slagging in boiler.

EFFICIENCY IMPROVEMENT BY BURNER ADJUSTMENT

The principle method of improving boiler efficiency and involves operating the boiler at
lowest practical excess O2 level. These O2 levels will be at certain operating margins
above absolute minimum O2 which is at the threshold of smoke or combustible emission
formation. Although peek boiler efficiency will occur close to minimum O2, it is not
practical to operate at this condition unless the boiler is equipped with highly
sophisticated combustion controls and flame quality monitoring to prevent any small
deviation into unsafe or unacceptable combustible conditions. Since the control features
are not similar for most industrial boilers, some margin of operating cushion above the
minimum O2 will be necessary to accommodate normal variation in the flue gas
properties and atmospheric conditions, repeatability and response characteristics of the
combustion control system, and other operational factors.

If minimum O2 levels are found to be expensive, then burner adjustments are

recommended as possible means reducing the burner’s minimum O2 requirement. High
minimum O2 can also result from improper maintenance of the burner equipment
(plugged orifice, Broken diffusers, etc.) but these problems may be minimized by
performing the preliminary boiler inspection with lower excess O2, the dry stack gas
losses are minimized leading to higher efficiencies.

Setting up a boiler for low excess O2 firing will be accomplished through a systematic,
organized series of tests. Following a test that documents as found conditions, the lowest
possible level of excess oxygen for the boiler will be established. The lowest level should
be found at several firing rates within the boiler’s operating range. The actual number of
boiler firing rates tested will depend on the boiler control system. Enough firing rates
should be tested to assure that after the final control adjustments are made, the optimum
excess O2 conditions are maintained at all the intermediate firing rates. At each firing
rate tested, the excess O2 should be varied over a range from 1 to 2 above the normal
operating point down to the point where the boiler just starts to smoke or CO emission
rise above 400 ppm. This low excess O2 condition is referred to as the smoke or the CO
threshold limit or simply the minimum O2. The smoke limit applies to the coal and oil-
firing smoking will generally occur before CO emission reach significant levels. The CO
limit applies to gas fuels and is the lowest possible excess O2 level while maintaining CO
below 400 ppm.

The smoke limit for solid or oil fuels is the lowest possible excess O2 level where
acceptable stack condition can be maintained. When performing the boiler tests to

45
determine minimum excess O2, curves such as those in Figures 1 & 2 will be
constructed. Based on the measurements obtained during the tests, these curves will show
how the boiler smoke and CO levels change as the excess O2 is changed. Each of the
figures contains two distinct curves to illustrate the extremes in smoke and CO behavior,
which may be encountered. The curves labeled (1) exhibit a very gradual in CO or smoke
as the minimum O2 conditions are reached. In contrast, the curves labeled (2) are gradual
at the first but as the excess O2 is reduced further and minimum O2 is approached, the
smoke or CO are potentially unstable condition can occur in small change in excess O2
and extreme caution is required. When making O2 changes near the smoke or Co limit,
do so in very small steps until there are enough data to show whether the boiler has a
gradual or steep characteristic curve for smoke and CO [curve (1) versus curve (2)]. It is
important to note that the boiler may exhibit a gradual smoke or CO behavior at one
firing rate and steep behavior at another.

High minimum O2 may be the indication of a burner malfunction or other fuel or

equipment related problems. But it should be realized that different burner designs and
fuels will generally have different minimum O2 requirement. Many burners will also
exhibit higher minimum O2 requirement at lower firing rates. For these reasons, it is
difficult to specify in these guidelines a range O2 levels which would be considered to be
normal. However, based on various minimum O2 tests, at industrial boiler installations,
the following table has been prepared to assist in judging whether the minimum O2 levels
that are measured are typical values.

Fuel types Typical ranges of minimum

Excess O2 at high firing rates

Natural gas 0.5 – 3.0 %

Oil Fuel 2.0 – 4.0 %

Boiler start- up records showing initial excess O2 conditions can provide a valuable
comparison with current minimum O2 conditions that are available. If it is apparent that
current minimum O2 levels are higher than expected levels, there may be a need for
maintainace or repairs, which would be completed before attempting the excess O2
optimization procedure.

Once the minimum O2 is established, the next step will be to determine the appropriate
O2 margin or operating cushion above the minimum O2 where the boiler can be routine
operated. This will be the lowest practical O2 for the boiler and will be the optimum
setting for the high efficiency (and in the most cases the lowest NO emissions). The O2
margin above the minimum O2 is necessary to account for the uncontrollable variations
in the excess O2 resulting from: -

1) Rapid boiler modulation, which could result in smoking or combustible

without an adequate O2 margin.

46
 2) Non-repeatability or Play in the automatic controls (excessive Play should
be corrected).
3) Normal variations in the atmospheric conditions, which can also change
excess O2 on unit not equipped with temperature and pressure,
compensated combustion air systems. This is a very important factor,
which is neglected. (Extreme variation in the ambient conditions can
easily produce the changes in excess O2 for 1% or more).
4) Changes in fuel properties, which may require varying amounts of excess
air.

Typical O2 margins above the minimum O2 may range from 0.5% up to 2.0% O2,
depending on the characteristics of the particular boiler control system and fuels. When
the boiler is going to be operated at a consistent firing rate for extended periods, the
lowest possible O2 margin should be selected.

A simple test to determine whether there is excess play (or poor repeatability) in the
boiler controls can be made by simply repeating the same firing condition, allowing the
fuel and air conditions in a normal manner. When performing this test, approach the
particular firing point from both the high side and low side, (i.e., from higher and lower
firing rates). A comparison of stack excess O2 after the boiler has stabilized indicates
whether there is excessive wear tolerance problem in air dampers, control shafts, valve
cams, controllers etc. Excess O2 should repeat to within a few percent excess O2.

Atmospheric variations are reflected in excess O2 variation due to changes in air density
at the forced draft fan inlet as the air pressure and temperature change. The fan will
deliver a certain volume of air to the burner, but as the air density changes, the pounds of
air supplied to the burner will vary, thus changing the burner excess air and excess O2.
when the combustion air is supplied from the boiler room, maintaining constant boiler
room temperatures will minimize this problem, but the atmospheric pressure effects are
unavoidable.

4.0 WATER TREATEMENT FOR BOILERS

47
Introduction
Water is one of the nature’s gift to mankind. Human beings, animals, birds, insects, plants all
depend on water for their survival. Any industry needs large quantity of water either as a coolant
in a process or for raising steam for power generation or in chemical processes. Water is also
required in large quantities for domestic use, in laundries, for making beverages and in food
processing, pharmaceuticals, etc. ad infinitum. Hence water is called universal solvent. Scientists
discovered that when 2 molecules o hydrogen and one molecule of Oxygen combine, water is
formed as per the reaction

2H2 + O2 2H2O
Pure water is clear, colorless, odorless and devoid of any taste and impurities. Three fourth of
Earth surface is covered with water, but we seldom see a water bearing all the qualities of pure
water.

Source of Natural supplies of water

Oceans provide our natural supplies of water. Suns radiant heat evaporates the sea water and
clouds are formed, which are driven off to land by wind. On consideration or precipitation it falls
as rain snow, hail etc., on reaching earth they form water bodies like river, lake, pond or
percolate into the ground. The excess water flows back to the ocean through rivers.

Now that we have identified the sources of water, we can group them to two major
classifications.
S.No Group Example
1 Surface Water Rivers, Streams, lakes, Ponds and large reservoirs
2 Ground Water Springs, Wells

How impurities are picked

Water vapour in the clouds is quite pure but during condensation, rain water picks up dust and
gases. On reaching the ground rain water picks up other impurities like suspended matter,
siliceous material and also mineral constituents solubilised from the rocks and earth. Added to
this it also pick up organic matter, colors from sewage and decaying vegetation it is believed that
after a heavy shower the next condensation from cloud is the purest form of water with traces of
dissolved gases, as impurities.

The ground water from underground supplies undergoes filtration, when it percolates down the
strata of soil and thus will be relatively free form suspended and organic matter. But it will have
more dissolved mineral matter due to its contact with earth’s crust. Thus compounds of calcium,
magnesium, iron, silicon, manganese, etc are dissolved in water rendering water unfit for use, for
specific purposes.

Classification of impurities in water?

The impurities in water can be classified into three major groups.
1. Dissolved ionic mineral impurities consisting of positively charged cations like Ca, Mg,
Fe, Mn, and negatively charged anions like Cl, SO4, HCO3,SiO2, CO3, OH, PO4,etc
2. Insoluble non-ionic impurities like color, turbidity, oil, colloidal silica, etc.
3. Gaseous impurities like dissolved CO2, H2S, NH3, O2, Cl2 etc.

48
How impurities are identified?
The impurities are identified and quantified by testing water. The importance of water analysis
can never be over emphasized. Water analysis give vital information on the quality of water, the
level of harmful impurities and the techniques to be followed for treatment of water supplies for
removal of impurities. The analysis data can be extrapolated to identify whether particular water
can cause ‘Scale’ of ‘corrosion’.

Harmful effects of impurities in water

The adage “what applies to goose also apply to Gander” does not apply on the quality of water
required for different industries like Boilers / Heat exchangers, Food processing industries, Metal
treatment plants, Electronic industry, domestic supply, etc. Different impurities in water
influence the quality of the product in a process industry or cause harmful effects leading to
catastrophic failure of equipment.

E.g:-
- Staining of clothes by Fe and Mn in Laundering
- Causing disease to babies and infants by excess Nitrate Ions, Mottling of teeth
by excess Fluoride Ions in water.
- Formation of scale / deposit in boiler tubes and heat exchangers resulting in
poor heat exchanger and overheating, ending up in tube failures.
- Poor quality of stem, containing impurities can cause fouling of turbines and
affect the processes.

Major impurities in water.

Ionic and dissolved Non Ionic and
Gaseous
+ve -ve undissolved
Calcium Bicarbonate Turbidity Carbon – di – oxide
Magnesium Carbonate Suspended matter Hydrogen sulphide
Sodium Hydroxide Organic matter Ammonia
Potassium Sulphate Colloidal silica Oxygen
Iron Chloride Oil Chlorine
Manganese Phosphate Micro organism
Ammonium Nitrate Bacteria
Silica
Colour

Water quality for boilers

49
Boilers are pressure vessels in which water is converted into steam, by heat of the fuel burnt,
which is used either to run a turbine for generation of power or in a chemical process either for
evaporating and concentrating liquids or in a chemical process itself. The purity of water / steam
assume importance for continuous operation of a plant and to prevent, uneconomic forced
outages.

Two major problems caused by impurities in natural untreated supplies of water are ‘corrosion’
and ‘scaling’. Both ‘corrosion; and ‘scaling’ if not prevented will bring forced outages ending in
huge losses. The indirect losses are always very high than the direct losses.

Corrosion
Corrosion is the slow eating away of metals and materials by its reaction with its environment, a
corroding medium. Simplest and most familiar form of corrosion is rusting of Iron and steel by
its reaction with water vapour and oxygen. We also know that strong acids and alkalis corrode
steel.

Scale / Deposit

We have seen that natural water contain ionic impurities in soluble form. The presence of
calcium and magnesium cations in combination with anions like bicarbonates, carbonates,
chlorides and sulphates in the water supplies make the water hard. Soaps do not lather easily in
hard water. Besides on heating thebicarbonates of calcium and magnesium precipitate and come
out of solution and deposit onto the walls of the steels surface along withother anionic
combinations like sulphate and chloride.

These deposites are very hard and act as insulators preventing the smooth heat transfer, by
forming a bridge between heating area and water.

Ca(HCO3)2 + Heat CaCO3 + H2O + CO2

Mg(HCO3)2 + Heat MgCO3 + H2O + CO2

Consequently failures are caused by overheating. As the temperature of the metal increases the
available stress of the material at that temperature decreases, until it cannot hold on to the same
pressure. Rupture of the steel material takes place. Refer diagram on the effect of water side
scale in boilers.

Water – Terminologies :

In any boiler the water to be used for raising steam require removal of impurities. The quality of
water plays paramount importance and certain parameters are to be strictly controlled and
maintained. Some of the terminologies on water commonly used are explaine for clarity.

1. Raw Water : Untreated water from natural supplies like rivers,

50
 2. Treated water : Water treated chemically or otherswise to suit an
industry or for other uses.

3. Filtered water : A supply of water that had been filtered through sand,
anthracite coal or other filtering medium to remove
suspended matter.
4. Soft Water : A water that had been taken through a H/ Na ion
exchange process for removal of calcium and
magnesium ions (Removal of hardness)

5. Design-mineralised water : A very pure form of water. A water that has

undergone stripping of cationic and ionic
impurities by ion exchange process.

6. Feed water : A water that had undergone treatment mentioned in

Sl.No.2 and 4 or 5 and additionally treated
intenally for prevention oof corrosion in a boiler.

7. Boiler water : The water inside a boiler drum treated with chemicals
to maintain alkalinity and prevent corrosion and
scaling.

VARIOUS METHODS OF WATER TREATMENT

Removal by Hydrogen cation exchange

In the process the hydrogen takes the palce of sodium and the removal of calcium and
magnesium is as per the following reaction.

Ca } { (HCO3)2 Ca } 2H2CO3
Mg } { SO4 H2Z Mg } H2SO4
2Na } { Cl2 2Na } Z + 2HCl
2K } { 2K }

During regeneration with HCl following cycle takes place:

Ca } Ca }
Mg } Mg }
2Na } Z + 2 HCl Na2 } Cl2 + H2Z
2K } K2 }

Sodium Bicoarbonate in the effluent neutralizes free mineral acidity and carbonic acid is
split into carbon di oxide and water.

51
Removal of manganese and Iron

These elements are removed by

a. Oxidation and precipitation

b. Ion exchange by Na or Heat cation exchangers.

Alkalinity

Natural waters are slightly alkaline due to the presence of bicarbonates. Lime
softening removes alkalinity and hardness. The second process is hydrogen cation
Exchange.

Removal of silica

Silica removal is accomplished by three methods:

1. Addition of Ferric sulphate in the lime soda process. The ferric hydroxide
formed in the reaction absorbs silica.

2. Magnesium hydroxide precipitated in thelime treatment also absorbs silica and they
are removed by setting and filtration.

3. By ion exchange in the anion exchange column.

Internal Treatment

The internal treatment of water in Boiler applications consists of injecting certain

selective chemicals in the feed water. This is to raise it pH and also to remove any
oxygen in the water. These controls takes care of corrosion and pitting. The chemical
dosed for raising the pH to 8.5 is ammonia at 0.5 ppm concentration. Hydrazine is dosed
toscavenge oxygen from feed water and hydrazine residual is maintained. Sodium
sulphite is also an oxygen scavenger.

By dosing sodium phosphate to the boiler drum the alkalinity is maintained to protect
steel and any residual ingress of calcium and magnesium is also precipitated down as
Tricalcium and Tri magnesium phosphate which can be blown down. Formation of scale
and prevention of corrosion is thus controlled by internal treatment. Recommended feed
water and boiler water quality parameters is given separately.

52
 Chemical Requirements of Boiler water for low and medium pressure Boilers

Parameters Requirements
Upto 20 Kg/sq.cm. 21 to 40Kg/sq.cm. 41 to60 Kg/sq.cm.
Total Hardness Not detectable Not detectable Not detectable
Total Alkalinity
(DR) as CaCO3 100 – 700 40 – 500 30 – 150
PPM (Max)
Caustic Alkalinity
As CaCO3 ppm 50 – 350 20 – 250 15 – 75
(Max)
PH value 10.0 to 10.5 10.0 to 10.5 9.8 to 10.2
Residual sodium
sulphites as 20 to 40 5 to 10 -
Na2SO3 ppm
Residual Hydrazine
As N2H4 ppm 0.1 to 1 .1 to .5 .05 to .3

Ratio Na2SO4 /
Caustic Alkalinity Above 2.5 Above 2.5 Above 2.5
(ppm as NaOH)
Phosphates (as
PO4), ppm 20 to 40 15 to 30 10 to 20
Total dissolved
Solids (DR) ppm 500 – 3500 200 – 2500 150 – 750
(Max) (DR)
Silica as Sio2 ppm Less than .4 of Less than .4 of -
(Max) caustic alkalinity caustic alkalinity

DR : Dual Range – Lower value for DM water make-up andhigher value for soft water
make –up. If feed water inlet temperature (at the economizer inlet) isabove 105 Deg. C
hydrazine dosing may be resorted to.

5.0 BOILER CONTROLS AND INSTRUMENTATIONS

The controls and instrumentations to be provided in boiler are based on

- Essential requirement for safe and smooth operation
- Extent of remote operation desired
- Extent of automation desired

There are boilers with just basic essential instrumentation and those with extensive automation.

53
The various controls that can be considered in the boiler are given below:
Combustion Control
Here the boiler outlet pressure is maintained by modulating the fuel and air. This can be done
either manually or remote manually or automatically. Cellulose fuel firing like palm fibre etc.
dose not easily lend itself for automating the combustion control. Normally for solid fuels, the
combustion control requires certain level of intermediate storage of the fuel. Such a storage in
case of fibrous fuels becomes difficult both on account of very low density and poor flow ability.
Hence the preferred control would be remote manual.

In case of other solid fuels like coal,etc. the coal feeder speed is modulated along with FD fan to
maintain the outlet pressure. Additionally some times the oxygen is measured in the flue gas and
“Oxygen Trimming” is done so as to control excess air levels.

Furnace Draft Control

In balance draft units, the furnace draft is required to be maintained slightly negative. This is
done by modulating the ID fan. This can be done either remote manually or automatically.

Drum level Control

This is most essential and important control and should be considered as a basic essential
requirement. This control is necessary, so that starvation of tubes does not occur resulting in tube
failure on one hand, and also any water carry over is prevented, so that damage to superheater or
down stream turbine is avoided.
The usual control is either two element or three element. The drum level stream flow and feed
water flow are three elements from which resultant signal is sent to the level control valve (of
feed control station). This control valve is modulated in order to maintain the water level in the
steam drum. It is strongly recommended that this control is provided as fully automatic.

Superheater steam temperature control

Many of the industrial Boilers of water tube type in the medium capacity range have
uncontrolled superheater. i.e. superheat temperature is allowed to float within a range. If the
boiler / superheater is properly designed within a reasonable load range, it is possible to have
superheat temperature to vary within, say + / - 15 Deg.C. This kind of variation is accepted in the
most of the cases of down stream applications.

There are instances particularly when the operating boiler pressure is high, say, 42 kg/sq.cm (g)
And above, the superheat temperature may have to be controlled within a closer range say + / - 5
Deg.C. In such cases, automatic control of superheat temperature is recommended. This can be
done by introducing a spray type attemperator either at the exit of the superheater or at the
intermediate stage between sections of superheater. the superheat temperature is maintained by
automatically modulating a water spray control valve.

Another method of controlling the superheat temperature is to take part of the steam through a
cooling coil (immersed in the drum) or an external heat exchanger and re-mix it with the main
steam. This is done through a three way valve in the superheater line. Superheat temperature is
controlled by modulating the three way valve (i.e. by modulating the quantity of steam being
cooled)

54
There are other methods of superheat steam temperature control which are not discussed here
due to their being considered as outside the purview of this presentation.

Indicating / Recording instrumentation are provided to guide the operator. It is a good practice to
regularly log the readings. The logged / recorded readings help a great deal to continually
improve the unit performance, to make adjustments with periodic changes in load pattern, fuel,
etc. These log data become essential to diagnose any mechanical / performance problem faced in
the unit.

Modulated feedwater Verses On-Off

Modulating feedwater to the boiler has got to be the most important portion of the
Boiler/Feedwater system. Once understand, modulating has so many advantages over on-off
feedwater addition, it is difficult to visualize any other system. Boilers with modulating firing
controls are quite common and but boilers with modulating system are not common.

Modulating feedwater:

Eliminates pump problems

We know through our experience that pump problems are on systems that have on-off feedwater
control. These pump problems are usually system problems generated due to a poor pump
selection and then misapplied. We seldom have a system problem with modulation.

Increases boiler efficiency

With on-off feedwater addition, it is necessary to select a pump that is at least two or three items
maximum steam capacity since an on-off system is always playing catch up. When the pump
starts it literally overloads the boiler with water at a substantially lower temperature than that in
the boiler. If your boiler had a window and you could actually see the effect of this surging
quench, you would be amazed. What you would see is a boiler happily steaming away until the
pump starts and this colder surge collapse the bubbles and disrupts the natural thermal
circulation. The result is a slight loss in pressure which signals the firing control to add more fuel
resulting in a wasteful cyclical firing action. When compared to the smooth operation of a
modulating system, one can imagine the effect this constant cycling has on the fuel consumption.

Stabilities deaerator operation and effluent quality

Did you stop to consider what on-off does to deaerator performance? For example, suppose you
have a 400 hp boiler and 400 hp Deaerator. Your on-off pump selection would be roughly three
times 400 hp or equivalent to 1200 hp. Now remember your deaerator is arted at only 400 hp so
in effect your deaerator operates at 1200 hp one-third of the time and Zero load for two-thirds of
the time. This unbalanced cyclical loading has a definite adverse effect on the quality of the
feedwater plus the fact it drives your level and temperature or pressure controls crazy.

55
One pump may be used on multiple boilers

Continuous modulation affords the opportunity to furnish a more efficient centrifugal pump
rather that multiple pump system. A good example of this is a where three (3) boilers with one
pump for standby. The system can be with a modulating system, which would utilize two
centrifugal pumps, only one of which operates leaving the other for 100% standby. This system
cost less to purchase (indicating three (3) sets of modulating controls for the boilers) but uses less
total electrical energy. Installation costs can also the reduced substantially. The on-off system
required a separate feed line to each boiler plus a regular jungle gym of valves for the standby
pump. The modulating system involved connecting both pump discharge together and only one
header to all the boilers with a short take off for each boiler. Since the flow to the boilers was
modulated, the single header size was the same as each individual line to each boiler for the on-
off system.

Pump size can be reduced

With modulating feed water, it is not necessary to drastically oversize the boiler feed pumps
since the boiler input match boiler steam output. Modulating valves function as an engineered
restriction in the feed line thus preventing the pump from overloading, and allowing the selection
of smaller, more efficient, lower horsepower pumps. With a light overcapacity for surge loads a
pump can be selected for 125% to 150% of the boiler(s) rated output.

Many system variations available

The system can be made such that the modulating system, which automatically starts the Boiler,
feed pump when the feedwater valve is just opening on the boiler and continues to operate until
water is no longer required. On multiple boilers, the pump can be automatically started when any
one of the boilers need water. This system has the advantage of eliminating the need for a
recirculating orifice since the pump is never allowed to operate against a closed valve or dead
end situation.

There are many variations to the above system. One is where we furnish two (2) P/E switches;
the second switch set to operate a second or lag pump should any one of the feed water valves
goto a full open position. This allows the selection of a lead pump for light boiler loads and then
automatically starts a second pump for heavy loads. Or perhaps a pump more closely sized to
actual operating conditions with built-in surge capability.

Another variation is utilizing a low switch in the discharge manifold which signals a selected lag
pump to pick up the volume whenever the flow exceeds a single pump capability. This type of
system is particularly useful on jobs that have varying capacities due to variable process
requirements, summer/winter heating loads, etc., with this system three pumps are used in lieu of
two larger pumps. With electrical horsepower figuring at RM700.00 to RM900.00 per year per
horsepower, using smaller pumps and/or eliminating wasteful recirculating orifices is very cost
effective. A third variation includes a pressure switch on the discharge manifold to automatically
starts a second or lag pump should the lead pump fail. An alarm can also be added to this system.

56
 6.0 DEAERATOR AND DOSING SYSTEMS
The Need For Removal Of Air From Steam System

Air is always present during equipment startup and in the boiler feed water. In addition, feed
water may contain carbonates that dissolve and release carbon dioxide gas. If the feed water
is deaerated almost all of the dissolved gases shall be removed.

If air that is not removed from the steam system air will act as an excellent insulator. Air with
its excellent insulating properties can “plate out” on heat transfer surfaces as steam
condenses and greatly reduces efficiency. Under certain conditions, as little as ½ to 1% by
volume of air in steam can reduce this heat transfer efficiency by 50%

With the presence of air in the steam, due to the partial pressure of air and steam, the
temperature shall be lower than that of pure steam system. See table:

Pressure temperature of steam temperature of steam (ºC) mixed various % of air

(Pig) (ºC) with 100% with by
steam 10% volume20% 30%

10.3 115.6 112.4 108.9 105.0

25.3 130.7 127.2 123.4 119.0
50.3 147.8 143.9 139.7 135.1
75.3 160.2 156.0 233.0 146.6
100.3 170.0 165.7 161.0 155.8

Why Deaerate

Deaeration of boiler feed water not only removes oxygen and carbon dioxide; it also
improves heat transfer and saves energy.

The necessary of deaerating boiler feedwater has become so recognized that even small
plants can now be assured of longer equipment life, reduced pipeline and equipment
replacement costs, and lower overall maintenance by using some type of deaeration. The
initial cost of adeaerator is a small price to pay for the peace of mind afforded by its
inclusion in your boiler plant’s operation. Today, deaeration is an essential factor in the
efficient and economical operation of any modern boiler plant, regardless of size.

The question “Why deaerte?” can be answered by detailing the five primary reasons for
including a deaerator as part of the boiler / steam / condensate cycle. They are as follows:
1. Oxygen removal
2. Carbon dioxide removal
3. Basis for improved operation
4. Improved heat transfer
5. Energy savings

57
Oxygen removal
Oxygen removal is the primary reason for deaerating water. It is probably the first thing one
things of when considering adeaertor. It has been determined that dissolved oxygen is up to 10
times more corrosive than equal quantities of dissolved carbon dioxide, especially at higher
temperatures. For example, condensate with equal quantities of dissolved oxygen is 2 ½ times
more corrosive at 90ºC than it is at 60ºC water to the boiler. The bicarbonate and carbonate
alkalinity, when subjected to boiler temperature, undergoes thermal decomposition and liberates
carbon dioxide, which becomes entrained with the steam:

2(HCO3) - + heat = (CO3) + CO2 + H2O

The other possible and usually minor source of carbon dioxide is the free, gaseous carbon
dioxide that is dissolved in most natural waters. Free carbon dioxide, because it is almost
completely eliminated initially by efficient feed water deaeration, is not a major factor. It is
extremely important, however, that the carbon dioxide liberated by thermal decomposition be
deaerated immediately and not allowed to recycle or concentrate in the steam condensate cycle.

Improved operation
In addition to removing the free oxygen and carbon dioxide, a Deaerator using steam as the
scrubbing gas also provides the advantage of heating the boiler feed water. Adding hot feed
water to the boiler greatly reduces the chance of thermal shock caused by the expansion
and contraction of heating surfaces.

Thermal shock is greatly aggravated in systems that have on – off pumping cycles because
the pump’s flow rate must be substantially higher both to make up lost ground and to
maintain steam requirements at the same time. These on – off cycles, even in deaerated
systems, seriously upset thermal circulation by surging or flooding the boiler with excess
water, which collapses the active steam bubbles. This can cause unstable water levels and
fluctuating firing rates.

Improved Heat Transfer

Aside from the serious destructive corrosion that takes place in the steam / condensate
cycle when steam high in oxygen and carbon dioxide is produced, these gases seriously
affect process equipment and its operation. Noncondensable gases have a severe adverse
effect on heat transfer.

It is well known that air is an excellent insulator. When air is allowed to concentrate in
process equipment designed to furnish heat transfer, it significantly impairs that heat
transfer. Since air is not kinetic in its desire to give up heat, it tends to plate out on the
heating surfaces. Under certain conditions, as little as 0.5 percent of air by volume can
reduce heat transfer by as much as 50 percent.

Of course, while it is vitally important to rid the steam processing equipment of unwanted
no condensable gases, it is equally important to see that these gases are not allowed to enter
the system in the first place or to be recycled. These gases must be eliminated from the
system as quickly as possible.

58
 Energy savings
The potential saving in heat that can be recovered by a Deaerator is another excellent
reason for its installation. The Deaerator can act as the hub of the plant heat balance. High-
pressure returns formerly trapped to atmosphere can now be trapped directly back to the
Deaerator. The flash steam recovered by the Deaerator from an average high-pressure
trapped system can amount to 20 percent of the fuel required to provide heat for that
process. Making low pressure systems trap less and pumping the condensate directly into
the Deaerator can save up to 6 percent in fuel. The deaerator to preheat mackup water lost
to atmosphere can use exhaust steam and flash steam, formerly preferentially.

In these days of high-energy costs the obvious sometimes escapes notice. For instance, a
well designed steam / condensate loop can save many times more fuel than when an
economizer is used alone. The Deaerator can be the major factor in the savings. This is
illustrated in Fig.3

Another excellent source of potential energy savings may be realized with an effective
blow down heat recovery system. Up to 3 percent fuel savings are possible with a payback
often realized in matter of months. Continuous blow down heat recovery can easily be
incorporated into the Deaerator cycle with a minimum of installation expense.

Blow Down

Substantial energy savings can be achieved by keeping boiler tubes clean and minimizing
blowdown rates.

Boiler blowdown is needed to maintain dissolved – solids concentrations in boiler water at

acceptable levels. This operation is wasteful of energy, since the purged steam is at the
same temperature as the steam generated in the boiler. Minimizing blowdown rates reduces
energy losses and improves boiler efficiency.

Example
In a plant where the cost of steam is RM 7 / Btu analysis of the makeup and blowdown
streams indicates a TDS (total dissolved solids) concentration of 150 and 1500 ppm,
respectively. Saturated steam at 150 psig is generated in the boiler at a rate of 42000 ld /h
Estimate the yearly (8,760 hr/yr) saving from a water treatment program that reduces the
makeup TDS concentration to 50 ppm and at the same time increases the blowdown TDS
concentration to 3000 ppm without cousing fouling of heat transfer surfaces.

From fig 1, we obtain the following information

Before After
Change change
Mackup TDS, ppm 150 50
Blowdown TDS,ppm 1500 3000
Blowdown ratio,

59
 Lb blowdown / lb steam 0.11 0.016
Energy lost in blowdown
Mbtu / h. 0.34 0.045

Valuable Heat Lost During Blow Down To Test For Water Level

Water level alarms are installed on an industrial package boiler in two ways:
i. Side mounted float on separate chambers
ii. Top mounted float on top of the shell / drum

It is a frequent practice that the alarm be tested on a shift change as a minimum or on an hourly
basis by some boiler operators. During this test a substantial mount of boiler water is lost i.e.
flashed to the atmosphere depending on the type of water level alarm that are installed. Slide
mounted float on separate chamber looses the least amount of boiler water during the testing of
alarms.

The top mounted float loses enormous amount of boiler water during the alarm testing. There
has been times when the pressure in the boiler drops as a result of alarm testing as low
temperature water is feed into boiler to make up for the water level. Alarm testing on the top
mounted alarm system can only be done by opening the blow down valve.

Due to this large amount of heat lost amount of heat and boiler performance deteriorating most
often than not the alarm is not tested and eventually creating operational problem.

60