4 - Energiteknik

Transcription

4 - Energiteknik

The Basics of Steam Generation
Sebastian Teir
STEAM BOILER TECHNOLOGY – The Basics of Steam Generation
Table of contents
Table of contents..................................................................................................................................2
Introduction..........................................................................................................................................3
Basics of boilers and boiler processes..................................................................................................5
A simple boiler.................................................................................................................................5
A simple power plant cycle..............................................................................................................6
Carnot efficiency..............................................................................................................................6
Properties of water and steam ..........................................................................................................7
Boiling of water ...........................................................................................................................7
Effect of pressure on evaporation temperature ............................................................................8
Basics of combustion .......................................................................................................................9
Products of combustion................................................................................................................9
Types of combustion....................................................................................................................9
Combustion of solid fuels ..........................................................................................................10
Combustion of coal ....................................................................................................................10
Main types of a modern boiler .......................................................................................................10
Heat exchanger boiler model .........................................................................................................12
Heat exchanger basics................................................................................................................12
T-Q diagram...............................................................................................................................12
Heat recovery steam generator model........................................................................................14
Heat exchanger model of furnace-equipped boilers ..................................................................15
References......................................................................................................................................16
2
Introduction
The world energy consumption has doubled in the last thirty years and it keeps on increasing with
about 1.5% per year (Figure 1). While the earth's oil and gas reserves are expected to deplete after
less than a hundred years, the coal reserves will last for almost five hundred years into the future
(taking into account estimations of fossil fuel reserves that have not yet been found) (Figure 2). In
Finland, 50% of the electrical power produced, is produced in steam power plants. But there are
more reasons to why electricity generation based on steam power plant will continue to grow and
why there still will be a demand for steam boilers in the future:
•
•
•
•
•
•
•
The world-wide dependency upon fossil fuels for power production (Figure 1, Figure 2, and
Figure 3)
The cost of the produced electricity is low
The technology has been used for many decades and is reliable and available
Wind and solar power are still expensive compared to steam power
The environmental impact of coal powered steam plants have under the past decade been
heavily diminished thanks to improved SOx and NOx reduction technology
The paper industry uses steam boilers as a vital utility to recycle chemicals and derive
electricity from black liquor (pulping waste)
Waste and biofuels can effectively be combusted in a boiler [1]
Coal
Hydroelectricity
Nuclear energy
Natural gas
Oil
*Prior to 1994 Combustible Renewables & Waste final consumption has been estimated based on TPES.
**Other includes geothermal, solar, wind, heat, etc.
Figure 1: Evolution from 1977 to 2002 of world primary energy consumption by fuel (Mtoe) [2]
3
Coal
Gas
Oil
Figure 2: The world’s reserves-to-production ratio for fossil fuels. [2]
Coal
Hydroelectricity
Nuclear energy
Natural gas
Oil
Figure 3: Regional primary energy consumption pattern 2002. [2]
4
Basics of boilers and boiler processes
In a traditional context, a boiler is an enclosed container that provides a means for heat from
combustion to be transferred into the working media (usually water) until it becomes heated or a gas
(steam). One could simply say that a boiler is as a heat exchanger between fire and water. The
boiler is the part of a steam power plant process that produces the steam and thus provides the heat.
The steam or hot water under pressure can then be used for transferring the heat to a process that
consumes the heat in the steam and turns it into work. A steam boiler fulfils the following
statements:
•
•
•
It is part of a type of heat engine or process
Heat is generated through combustion (burning)
It has a working fluid, a.k.a. heat carrier that transfers the generated heat away from the
boiler
• The heating media and working fluid are separated by walls
In an industrial/technical context, the concept “steam boiler” (also referred to as “steam generator”)
includes the whole complex system for producing steam for use e. g. in a turbine or in industrial
process. It includes all the different phases of heat transfer from flames to water/steam mixture
(economizer, boiler, superheater, reheater and air preheater). It also includes different auxiliary
systems (e. g. fuel feeding, water treatment, flue gas channels including stack). [3]
The heat is generated in the furnace part of the boiler, where fuel is combusted. The fuel used in a
boiler contains either chemically bonded energy (like coal, waste and biofuels) or nuclear energy.
Nuclear energy will not be covered in this material. A boiler must be designed to absorb the
maximum amount of heat released in the process of combustion. This heat is transferred to the
boiler water through radiation, conduction and convection. The relative percentage of each is
dependent upon the type of boiler, the designed heat transfer surface and the fuels that power the
combustion.
A simple boiler
In order to describe the principles of a
steam boiler, consider a very simple case,
where the boiler simply is a container,
partially filled with water (Figure 4).
Combustion of fuel produce heat, which
is transferred to the container and makes
the water evaporate. The vapor or steam
can escape through a pipe that is
connected to the container and be
transported elsewhere. Another pipe
brings water (called “feedwater”) to the
container to replace the water that has
evaporated and escaped.
Since the pressure level in the boiler
Figure 4: Simplified boiler drawing.
should be kept constant (in order to have
stable process values), the mass of the steam that escapes has to be equal to the mass of the water
that is added. If steam leaves the boiler faster than water is added, the pressure in the boiler falls. If
5
water is added faster than it is evaporated, the pressure rises. If more fuel is combusted, more heat is
generated and transferred to the water. Thus, more steam is generated and pressure rises inside the
boiler. If less fuel is combusted, less steam is generated and the pressure sinks.
A simple power plant cycle
The steam boiler provides steam to a heat
consumer, usually to power an engine. In a
steam power plant a steam turbine is used for
extracting the heat from the steam and turning it
into work. The turbine usually drives a generator
that turns the work from the turbine into
electricity. The steam, used by the turbine, can
G
be recycled by cooling it until it condensates
into water and then return it as feedwater to the
boiler. The condenser, where the steam is
condensed, is a heat exchanger that typically
uses water from a nearby sea or a river to cool
the steam. In a typical power plant the pressure,
at which the steam is produced, is high. But
when the steam has been used to drive the
turbine, the pressure has dropped drastically. A
pump is therefore needed to get the pressure
Figure 5: Rankine cycle
back up. Since the work needed to compress a
fluid is about a hundred times less than the work
needed to compress a gas, the pump is located after the condenser. The cycle that the described
process forms, is called a Rankine cycle and is the basis of most modern steam power plant
processes (Figure 5).
Carnot efficiency
When considering any heat process or power
cycle it is necessary to review the Carnot
efficiency that comes from the second law of
thermodynamics. The Carnot efficiency
equation gives the maximum thermal efficiency
of a system (Figure 6) undergoing a reversible
power cycle while operating between two
thermal reservoirs at temperatures Th and Tc
(temperature unit Kelvin).
η max =
TH − TC
T
=1− C
TH
TH
Hot reservoir Qh
(temperature Th)
Wcycle
=
Qh - Qc
(1)
The maximum efficiency as a function of the
steam exhaust temperature can be plotted by
keeping the cooling water temperature constant.
Assuming the temperature of the cooling water
is around 20°C (a warm summer day), the curve
gets the shape presented in Figure 7. Larger
temperature difference leads to a higher thermal
Cold reservoir Qc
(Temperature Tc)
Figure 6: Carnot efficiency visualized
.
6
efficiency.
Although no practical heat process is fully
reversible, many processes can be calculated
precisely enough by approximating them as
reversible processes.
Carnot efficiency
0,7
0,6
0,5
0,4
To give a practical example of the use of this
theory on steam boilers, consider the Rankine
cycle example presented in Figure 5. The
temperature of the hot reservoir would then be
the temperature of the steam produced in the
boiler and the temperature of the cold reservoir
would be the temperature of the cooling water
drawn from a nearby river or lake (Figure 8).
The formula in Equation 1 can then be used to
calculate the theoretical maximum thermal
efficiency of the process.
0,3
0,2
0,1
0
200
The theoretical amount of heat that can be
transferred from the combustion process to the
working fluid in a boiler is equivalent to the
change in its total heat content from its state at
entering to that at exiting the boiler. In order to
be able to select and design steam- and power-
600
800
1000
Temperature [K]
Figure 7: Carnot efficiency graph example.
Properties of water and steam
Water is a useful and cheap medium to use as a
working fluid. When water is boiled into steam
its volume increases about 1,600 times,
producing a force that is almost as explosive as
gunpowder. The force produced by this
expansion is the source of power in all steam
engines. It also makes the boiler a dangerous
device that must be carefully treated.
400
Hot reservoir Qh
(temperature Th)
Wp
Wt
Cold reservoir Qc
(Temperature Tc)
Figure 8: Carnot efficiency applied on the
Rankine cycle.
generation equipment, it is necessary to thoroughly understand the properties of the working fluid
steam, the use of steam tables and the use of superheat. These fundamentals of steam generation
will be briefly reviewed in this chapter. When phase changes of the water is discussed, only the
liquid-vapor and vapor-liquid phase changes are mentioned, since these are the phase changes that
the entire boiler technology is based on. [4]
Boiling of water
Water and steam are typically used as heat carriers in heating systems. Steam, the gas phase of
water, results from adding sufficient heat to water to cause it to evaporate. This boiler process
consists of three main steps: The first step is the adding of heat to the water that raises the
temperature up to the boiling point of water, also called preheating. The second step is the
continuing addition of heat to change the phase from water to steam, the actual evaporation. The
third step is the heating of steam beyond the boiling temperature of water, known as superheating.
7
Evaporation of water
Phase change
180
160
140
Temperature [C]
The first step and the third steps are the
part where heat addition causes a
temperature rise but no phase change, and
the second step is the part where the heat
addition only causes a phase change. In
Figure 9, the left section represents the
preheating, the middle section the
evaporation, and the third section the
superheating. When all the water has been
evaporated, the steam is called dry
saturated steam. If steam is heated beyond
its saturation point, the temperature begins
to rise again and the steam becomes
superheated steam. Superheated steam is
defined by its zero moisture content: It
contains no water at all, only 100% steam.
120
100
80
60
40
20
0
500
1000
1500
2000
2500
3000
Net enthalpy of water [kJ/kg water]
Evaporation
During the evaporation the enthalpy rises
Figure 9: Water evaporation plotted in a
drastically. If water is evaporated at
temperature-enthalpy graph.
atmospheric pressure from saturated liquid
to saturated vapour, the enthalpy rise
needed is 2260 kJ/kg, from 430 kJ/kg (sat.
water) to 2690 kJ/kg (sat. steam). When the water has reached the dry saturated steam condition, the
steam contains a large amount of latent heat, corresponding to the heat that was led to the process
under constant pressure and temperature. So despite pressure and temperature is the same for the
liquid and the vapour, the amount of heat is much higher in vapour compared to the liquid.
Superheating
If the steam is heated beyond the dry saturated steam condition, the temperature begins to rise again
and the properties of the steam start to resemble those of a perfect gas. Steam with higher
temperature than that of saturated steam is called superheated steam. It contains no moisture and
cannot condense until its temperature has been lowered to that of saturated steam at the same
pressure. Superheating the steam is particularly useful for eliminating condensation in steam lines,
decreasing the moisture in the turbine exhaust and increasing the efficiency (i.e. Carnot efficiency)
of the power plant.
Effect of pressure on evaporation temperature
It is well known that water boils and evaporates at 100°C under atmospheric pressure. By higher
pressure, water evaporates at higher temperature - e.g. a pressure of 10 bar equals an evaporation
temperature of 184°C. The pressure and the corresponding temperature when a phase change occurs
are called the saturation temperature and saturation pressure. During the evaporation process,
pressure and temperature are constant, but if the vaporization occurs in a closed vessel, the
expansion that occurs due to the phase change of water into steam causes the pressure to rise and
thus the boiling temperature rises.
When 22,12 Mpa is exceeded (the corresponding temperature is 374°C), the line stops (Figure 10).
The reason is that the border between gas phase and liquid phase is blurred out at that pressure. That
point, where the different phases cease to exist, is called the critical point of water.
8
1000
22,12 MPa
Pressure [bar]
100
10
1
0
100
200
300
400
0.1
0.01
Tem perature [°C]
Figure 10: Evaporation pressure as a function of evaporation temperature.
Basics of combustion
Combustion can be defined as the complete, rapid exothermic oxidation of a fuel with sufficient
amount of oxygen or air with the objective of producing heat, steam and/or electricity. The process
of combustion occurs with a high speed and at a high temperature. Essentially, it is a controlled
explosion. Combustion occurs when the elements in a fuel combine with oxygen and produce heat.
All fuels, whether they are solid, liquid or in gaseous form, consist primarily of compounds of
carbon and hydrogen called hydrocarbons (natural gas, coal fuel oil, wood, etc.), which are
converted in the combustion process to carbon dioxide (CO2) and steam. Sulphur, nitrogen, and
various other components are also present in these fuels.
Products of combustion
When the hydrogen and oxygen combine, intense heat and water vapor is formed. When carbon and
oxygen combine, intense heat and the compounds of carbon monoxide or carbon dioxide are
formed. These chemical reactions take place in a furnace during the burning of fuel, provided there
is sufficient air (oxygen) to completely burn the fuel. Very little of the released carbon is actually
"consumed" in the combustion reaction because flame temperature seldom reaches the vaporization
point of carbon. Most of it combines with oxygen to form CO2 and passes out the vent. The final
gaseous product of combustion is called a flue gas. As mentioned in the introduction to this
segment, combustion can never be 100% efficient. All fuels contain moisture. Other fuel
components may form by-products, such as ash, and gaseous pollutants that need emission control
equipment. [5]
Types of combustion
There are three types of combustion:
•
Perfect Combustion is achieved when all the fuel is burned using only the theoretical
amount of air, but as stated earlier, perfect combustion cannot be achieved in a boiler.
•
Complete Combustion is achieved when all the fuel is burned using the minimal amount of
air above the theoretical amount of air needed to burn the fuel. Solid fuels, such as coal, peat
9
or biomass, are typically fired at air factors 1.1 – 1.5, i.e. 110-150% of the oxygen needed
for perfect combustion.
•
Incomplete Combustion occurs when part of the fuel is not burned, which results in the
formation of soot and smoke.
Combustion of solid fuels
Solid fuels can be divided into high grade; coal
and low grade; peat and bark. The most typical
firing methods are grate firing, cyclone firing,
pulverized firing, and fluidized bed firing.
Pulverized firing has been used in industrial and
utility boilers from 60 MWt to 6000 MWt. Grate
firing (Figure 11) has been used to fire biofuels
from 5 MWt to 600 MWt and cyclone firing has
been used in small scale 3-6 MWt.
Figure 11:Photo of stoker or grate firing.
Combustion of coal
Oil and gas are always combusted with a burner, but there are three different ways to combust coal:
•
•
•
Fixed bed combustion (grate boilers, Figure 11)
Fluidized bed combustion (Figure 12)
Entrained bed combustion (pulverized coal combustion)
In fixed bed combustion, larger-sized coal is combusted
in the bottom part of the combustor with low-velocity
air. Stoker boilers also employ this type of combustion.
Large-capacity pulverized coal fired boilers for power
plants usually employ entrained bed combustion. In
fluidized bed combustion, fuel is introduced into the
fluidized bed and combusted. [4]
Main types of a modern boiler
In a modern boiler, there are two main types of boilers
when considering the heat transfer means from flue
gases to feed water: Fire tube boilers and water tube
boilers.
In a fire tube boiler (Figure 13) the flue gases from the
furnace are conducted to flue passages, which consist of
several parallel-connected tubes. The tubes run through
the boiler vessel, which contains the feedwater. The
tubes are thus surrounded by water. The heat from the
flue gases is transferred from the tubes to the water in
the container, thus the water is heated into steam. An
easy way to remember the principle is to say that a fire
tube boiler has "fire in the tubes".
Figure 12: Photo of fluidized bed
combustion.
10
1. Turning chamber
2. Flue
gas
collection
chamber
3. Open furnace
4. Flame tube
5. Burner seat
6. Manhole
7. Fire tubes
8.
9.
10.
11.
12.
13.
14.
15.
Water space
Steam space
Outlet and circulation
Flue gas out
Blow-out hatch
Main hatch
Cleaning hatch
Main steam outlet
16.
17.
18.
19.
20.
21.
Level control assembly
Feedwater inlet
Utility steam outlet
Safety valve assembly
Feet
Inslulation
Figure 13: Schematic of a Höyrytys TTK fire tube steam boiler [6].
In a water tube boiler, the conditions are the
opposite of a fire tube boiler. The water
circulates in many parallel-connected tubes.
The tubes are situated in the flue gas channel,
and are heated by the flue gases, which are
led from the furnace through the flue gas
passage. In a modern boiler, the tubes, where
water circulates, are welded together and
form the furnace walls. Therefore the water
tubes are directly exposed to radiation and
gases from the combustion (Figure 14).
Similarly to the fire tube boiler, the water
tube boiler received its name from having
"water in the tubes".
A modern utility boiler is usually a water
tube boiler, because a fire tube boiler is
limited in capacity and only feasible in small
systems. The various designs of water tube
boilers are discussed further in “Steam/water
circulation design”
Figure 14: Simplified drawing describing the water
tube boiler principle. [7]
11
Heat exchanger boiler model
If a modern water tube boiler utilizes a furnace,
the furnace and the evaporator is usually the
same construction – the inner furnace walls
consists solely of boiler tubes, conducting feed
water, which absorbs the combustion heat and
evaporates.
flue gas
process steam
In process engineering a boiler is modelled as a
network of heat exchangers, which symbolizes
the transfer of heat from the flue gas to the
steam/water in boiler pipes.
For instance, the furnace, abstracted as a heat
exchanger (Figure 15), consists of the following
streams: the fuel (at storage temperature),
combustion air (at outdoors temperature) and
feedwater as input streams. The output streams
are the flue gas from the combustion of the fuelair mixture, and the steam.
feed water
air
fuel
Figure 15: Furnace heat exchanger model.
Heat exchanger basics
The task of a heat exchanger is to transfer the
heat from one flow of medium (fluid/gas stream)
to another – without any physical contact, i.e. without actually mixing the two media. The two
interacting streams in a heat exchanger are referred to as the hot stream and the cold stream (Figure
16). The hot stream (a.k.a. heat source) is the stream that gives away heat to the cold stream (a.k.a.
heat sink) that absorbs the heat. Thus, in a boiler the flue gas stream is the hot stream (heat source)
and the water/steam stream is the cold stream (heat sink).
There are two different main types of heat
exchangers: Parallel-flow and counter-flow. In a
parallel flow heat exchanger the fluids flow in
the same direction and in a counter flow heat
exchanger the fluids flow in the opposite
direction. Combinations of these types (like
cross-flow exchangers and more complicated
ones, like boilers) can usually be approximately
calculated according to the counter-flow type.
T-Q diagram
A useful tool for designing a heat exchanger is
the T-Q diagram. The diagram consists of two
axes: Temperature (T) and transferred heat (Q).
The hot stream and the cold stream are
represented in the diagram by two lines on top
of each other. If the exchanger is of parallelflow type, the lines proceed in the same
direction (Figure 17). If the exchanger is a
counter-flow (or cross-flow-combination, like a
hot stream
cold stream
Figure 16: A heat exchanger model.
12
boiler), the lines points in the opposite direction
(Figure 18). The length of the lines on the Qaxis shows the transferred heat rate and the Taxis the rise/drop in temperature that the heat
transfer has caused.
Since the heat strays from a higher temperature
to a lower (according to the second law of
thermodynamics) the wanted heat transfer
happens by itself if and only if the hot stream is
always hotter than the cold stream. That is why
the streams must never cross. Since no material
has an infinite heat transfer rate, the “pinch
temperature” (Tpinch) of the heat exchanger
defines the minimum allowed temperature
difference between the two flows.
If the streams cross, the lines must be
horizontally adjusted (that is, external heating
and cooling must be supplied) in order to
correspond with the pinch temperature (Figure
19).
T
T1
hot stream
T2
t2
t1
cold stream
Q
Figure 17: T-Q diagram of a parallel-flow type
heat exchanger.
T
T1
T2
t2
t1
deltaQ
Q
Figure 18: T-Q diagram of a counter-flow type
heat exchanger.
T
t1
T1
Tpinch
T2
t1
Q
external heating
required
external cooling
required
Figure 19: Adjusted streams.
13
Heat recovery steam generator model
To give an example of the construction of a heat
exchanger model, a heat recovery steam
generator (HRSG) is constructed next as a heat
exchanger cascade. The HRSG is basically a
boiler without a furnace – the HRSG extracts
heat from flue gases originating from fuel
combusted in an external unit. Since the HRSG
only deals with two streams (flue gases as the
hot stream and steam/water as the cold stream),
it represents the simplest heat exchanger model
of a modern boiler application. Since the heating
of water occurs in three steps (Figure 9), the heat
exchanger model is usually divided into at least
three units.
The heat exchanger unit, where the evaporation
occurs is called the evaporator. Assuming that
water enters the evaporator as saturated water
and exits as saturated steam, the heat transferred
from the flue gas is the required heat to change
the phase of water into steam. The phase change
occurs (water boils) at a constant temperature,
and therefore the steam/water stream
temperature will not change in the evaporator.
In order to preheat the water for the evaporator,
another heat exchanger unit is needed. This unit
is called economizer, and is a cross-flow type of
heat exchanger. It is placed after the evaporator
in the flue gas stream, since the evaporator
requires higher flue gas temperature than the
economizer.
The heat exchanger unit that superheats the
saturated steam is called superheater. The
superheater heats the saturated steam beyond the
saturation point until it reaches the designed
maximum temperature. It requires therefore the
highest flue gas temperature to receive heat and
is thus placed first in the flue gas stream. The
maximum temperature of the boiler is limited by
the properties of the superheater tube material.
Today's economically feasible material can take
temperatures of 550-600 °C.
Economizer
water
Evaporator
saturated
water
saturated
steam
Superheater
Figure 20: Heat exchanger model of the HRSG.
T
Sup
Eva
Eco
Q
Figure 21: T-Q diagram of the HRSG model in
Figure 20.
The result is a heat exchanger cascade of a HRSG (with a single pressure level), which can be found
in Figure 20. The T-Q diagram of the model is visualized in Figure 21.
14
Heat exchanger model of furnace-equipped boilers
The order of the heat transfer units on the water/steam side is always economizer - evaporator superheater (downstream order). The temperature levels and the temperature difference between the
flue gases and the working fluid usually limits the arrangement variation possibilities of the heat
transfer surfaces on the flue gas side.
In a boiler with a furnace, adequate cooling has to be maintained and material temperature should
not exceed 600°C. Thus the evaporator part of the water/steam cycle is placed in the furnace walls,
since the heat of the evaporation provides enough cooling for the furnace, which is the hottest part
of the boiler.
Since the furnace is inside the boiler, high flue gas temperatures (over 1000°C) are obtained. After
the flue gas has given off heat for the steam production, it is still quite hot. In order to cool down
the flue gases further to gain higher boiler efficiency, flue gases can be used to preheat the
combustion air. The heat exchanger used for this purpose is called an air preheater.
The result is a heat exchanger model of a furnace-equipped boiler (e.g. PCF-boiler, grate boiler or
oil/gas boiler), which can be found in Figure 22. The T-Q diagram of the model is visualized in
Figure 23
Air out
T
Eco
Eva Sup Air
Air in
Air preheater
Q
Figure 23: T-Q diagram of the heat exchanger
model in Figure 22.
Figure 22: Furnace equipped boiler with air
preheater.
15
References
1.
Vakkilainen E. Lecture slides and material on steam boiler technology, 2001
2.
BP statistical review of world energy 2003. Web page, read September 2003.
http://www.bp.com/centres/energy/primary.asp
3.
Ahonen V. “Höyrytekniikka II”. Otakustantamo, Espoo. 1978.
4.
Combustion Engineering. ”Combustion: Fossil power systems”. 3rd ed. Windsor. 1981.
5.
Zevenhoven R., Kilpinen P. Control of pollutants in flue gases and fuel gases. Energy
Engineering and Environmental Protection Publications TKK-ENY-4, Espoo 2002.
ISBN 951-22-5527-8.
6.
Höyrytys Oy. Web page, viewed at 8.9.2003.
http://www.hoyrytys.fi/vaporworks/hoyrykattilat/ttk_kattila.htm
7.
American Heritage® Dictionary of the English Language: Fourth Edition. Web page,
viewed at 10.8.2002. http://www.bartleby.com
16
The History of Steam Generation
Sebastian Teir
STEAM BOILER TECHNOLOGY – The History of Steam Generation
Table of contents
Table of contents................................................................................................................................18
Introduction........................................................................................................................................19
Early boilers .......................................................................................................................................19
Newcomen’s boiler ........................................................................................................................20
Wagon boiler..................................................................................................................................21
Cylindrical boiler ...........................................................................................................................21
The development of modern boiler technology .................................................................................22
Fairbarn’s fire tube boiler ..............................................................................................................22
Wilcox’ water tube boiler ..............................................................................................................22
Steam drum boiler..........................................................................................................................24
Tube walled furnace.......................................................................................................................24
Once-through boiler .......................................................................................................................25
Supercritical boiler.........................................................................................................................26
Graphs and timelines of development in boiler technology ..............................................................26
Steam boilers and safety ....................................................................................................................27
References..........................................................................................................................................29
18
Introduction
Steam was early used to get mechanical power.
Among the relics of ancient Egyptian
civilization over 2000 years old records are
found of the use of hot air for opening and
closing temple doors (Figure 1).
About the same time, mathematician Heron of
Alexandria experimented with steam power and
constructed among other things a rudimentary
rotary steam engine. It was a spinning ball
whose rotation was driven by steam jets coming
from two nozzles on the ball. Although the
inventor only considered it a toy, used for
teaching physics to his students, it is the first
known device to transform steam into rotary
motion and thus the world's first reaction turbine
(Figure 2). Hero’s experiments and theories can
be found in his book, The Pneumatics [1].
Strangely enough, steam wasn't seriously
considered a useful force until 1600 years later,
when two British inventors began to turn steam
power into practical devices - Thomas Savery in
1698 and Thomas Newcomen in 1705. James
Watt further improved on their inventions,
patenting several designs that earned him the
title of father of the modern steam engine.
Applications of steam power grew during the
1700s, when steam engines began to find use
powering stationery machinery such as pumps
and mills, and its usages expanded with time
into vehicles such as tractors, ships, trains, cars
and farm/industrial machinery. The age of steam
lasted almost 200 years, until the internal
combustion engine and the electricity took over.
Even so, efficient steam turbines are still used
today for submarine torpedo propulsion and for
naval propulsion systems. But more importantly,
steam power is still the most common means for
generating electricity. [2] [3] [4] [5] [6] [7]
Figure 1: Machine that uses steam to open
temple doors. [1]
Figure 2: Heron's steam engine. [1]
Early boilers
Furnaces were developed originally from a need to fire pottery (4000 B.C.) and to smelt copper
(3000 B.C.). Closely associated with furnaces are boilers, that were first used for warming water
and are of Roman and Greek origin. Early boilers were recovered from the ruins of Pompeii.
19
In 1698, Thomas Savery developed a steam-driven water pump. As the steam condensed, a vacuum
was created causing the water to be drawn into the cylinder. The boiler continued to be refined and
developed for use during the Industrial Revolution.
Newcomen’s boiler
The era of first boilers for industrial use stems from England in the 1700 - 1800. The first use of
boilers was pumping water out from mines. These boilers had a very low efficiency, but since there
was no lack of fuel supply the boilers replaced the horse driven pumps.
One of the first successful boilers was
Thomas Newcomen's boiler (Figure 3). It
was the first example of steam driven
machine capable of extended period of
operation. This type of boiler was called
shell boiler. The steam was produced at
atmospheric pressure. The boiler was made
from copper, using rivets and bent metal
sheets (Figure 4). In 1800, iron replaced
copper in order to make the boiler last for
increased pressures. Later the cylindrical
design was replaced by the wagon-type
design for increased capacities.
Figure 3: Newcomen's boiler, 1 - shell over the
boiling water, 2 - steam valve, 3 - steam pipe, 4 - float
for water level, 5 - grate doors. [2]
Figure 4: Different kinds of riveting techniques. Riveting was used as the main manufacturing
method of boilers until the 1950's. Riveting is today used when manufacturing aircraft aluminium
structures. [2]
20
Wagon boiler
When James Watt made some critical
improvements to the Newcomen steam engine
by separating the condenser from the cylinder
and thus improving the efficiency substantially,
the steam engine became in demand and
provided a rapid growth of boilers.
The earliest steam boilers were usually spheres
or sections of spheres, heated entirely from the
outside (Figure 5). Watt introduced the use of
the wagon boiler (shaped like the top of a
covered wagon), which is still being used with
low pressures.
Cylindrical boiler
Watt and Newcomen steam engines all operated
at pressures only slightly above atmospheric
pressure. In 1800 the American inventor Oliver
Evans built a high-pressure steam engine
utilizing a horizontal cylindrical boiler. Evans's
boiler consisted of two cylindrical shells, one
inside the other with water occupying the region
between them. The fire grate was housed inside
the inner cylinder, so flue gas flowed through
the smaller cylinder and thus heated the water,
permitting a rapid increase in steam pressure.
Figure 5: Wagon boiler. [2]
Figure 6: Cylindrical boiler.
As can be seen from the picture (Figure 6), the flue gas passes also around the cylindrical boiler.
One of the advantages of the cylindrical boiler is that it has a larger heat transfer surface per unit of
working fluid. Therefore cylindrical boiler can be built cheaper than the earlier boilers. The pressure
(and thus the temperature) can also be increased with the cylindrical design. Simultaneously but
21
independently, the British engineer Richard Trevithick developed a similar boiler, which was used
in the world's first practical steam locomotive that he invented in 1801. The cylindrical boiler was
later expanded to contain several passes and eventually formed the fire tube boiler.
The development of modern boiler technology
The steam boiler became ever more important towards the end of the last century. The industry and
transportation methods had become heavily dependant of steam power. Inventive engineers were set
to work to develop increasingly new boiler types. There was room for improvement as efficiency
and safety of many boilers frequently left a lot to be desired. Again and again there were boiler
explosions with catastrophic consequences. Hundreds of workers died. In the USA in 1880, for
instance, 170 notified boiler explosions are recorded involving 259 dead and 555 injured.
The principles of the boiler technologies introduced in this chapter are still in use today.
Fairbarn’s fire tube boiler
The first major improvement over Evans and Trevithick's boilers was the fire-tube Lancashire
Boiler (Figure 7) , patented in 1845 by the British engineer Sir William Fairbairn, in which hot
combustion gases were passed through tubes inserted into the water container, increasing the
surface area through which heat could be transferred. The saturated steam was led out from the top.
The main use was to run steam engines for motive power: It was used to power steamboats, railroad
engines and run industrial machinery via belt drives. Fire-tube boilers were limited in capacity and
pressure and were also, sometimes, dangerously explosive.
Figure 7: Cast iron fire tube boiler.
Wilcox’ water tube boiler
The water tube boiler (Figure 8 and Figure 9) was patented in 1867 by the American inventors
George Herman Babcock and Stephen Wilcox. The boiler had larger heating surfaces, allowed
better water circulation, and, most noteworthy, reduced the risk of explosion drastically. In the
water-tube boiler, water flowed through tubes heated externally by combustion gases through
radiation and convection and steam was collected above in a drum. The large number of tubes and
use of cross gas flow increases the heat transfer rate. Boilers of this type could be built with larger
heat transfer surface per unit of working fluid than the previous design. Due to the higher rate of
22
heat transfer cooler flue gases could be used. Tubes could be made inexpensively and with higher
quality than plate. [9]
The water-tube boiler became the
standard for all large boilers as
they allowed for higher pressures
than earlier boilers as well. Their
first use was to run the largest
steam machines but it quickly
became the boiler type of choice
for a steam turbine. Wilcox and
Babcock founded in 1867 the first
boiler-making
company
in
Providence. This company exists
still today and one of its former
subsidiaries delivers boilers in
Europe under the name Babcock
Borsig. [10]
Figure 8: Wilcox’ water tube boiler. [11]
Figure 9: A drawing of a Wilcox' water tube boiler. Bent tubes in a tight bundle receive heat from
flue gas mainly convectively. The tubes are in a tilted position in order to achieve a natural
circulation of water/steam. The furnace is usually made of bricks. [2]
23
Steam drum boiler
The next step was the emergence of the
drum boiler, which introduced a steam
drum for separating steam from water
(Figure 10). This coincided with the
spreading of a new tube manufacturing
technology, forming. This allowed cheap
and reliable joint between the drum and a
tube. Except from being easier to
manufacture, the drum boiler was also
beneficial by providing better control of
the water quality by having a mud drum.
Some early designs incorporated a number
of steam drums, as in the picture. A boiler
with two drums became quickly a
standard. The limitation of a tube shell is
its thickness required to withstand
pressure. If larger units were required
multiple boilers needed to be operated. In
late 1800 some ten water tube boilers
could be connected to a single steam
engine or a turbine. With the new design
much larger boilers could be built.
Figure 10: Multi drum boiler of Stirling type. [2]
Tube walled furnace
The demand for even bigger boiler unit sizes to
drive steam turbines required larger furnace
volume, which eventually led to the
development of the tube walled furnace (Figure
11). The tube walled furnace finally integrated
the earlier separated combustion and heat
transfer into the same space by building heat
transferring tubes into the furnace. This meant
high savings and started rapid unit size
increase. About 1955 the first fully welded
furnace (membrane wall) was developed.
In a modern tube walled furnace the inside of
the furnace wall is completely covered of heat
transferring water tubes, welded together side
by side. Since the water tubes are in the furnace
the heat is being transferred mainly by radiation
from the combustion process. A utility boiler is
a boiler that is part of an industrial process.
Welding forms today the basis of all modern
steam boiler manufacture. The first applications
of welding to boiler manufacturing were in the
1930's (Figure 12).
Figure 11: Early boiler with tube walled furnace
[2].
24
Figure 12: Different methods of welding boiler tubes [2].
Once-through boiler
In order to be able to increase the current
unit size and efficiency of boilers, the
restriction of natural circulation boilers
needed to be overcome. The idea of a
once through boiler, were no steam drum
would be used and thus no circulation of
non-vaporized water would take place,
was not new. Patents for once through
boiler concepts date from as early as
1824.
The
first
significant
commercial
application of a once through boiler was
not made until 1923, when the
Czechoslovakian inventor Mark Benson
provided a small 1.3 kg/s once through
boiler for English Electric Co. The unit
was designed to operate at critical steam
pressure, but due to frequent tube
failures, the pressure had to be dropped.
The once through boiler uses smaller
diameter and thinner walled tubes than
the natural circulation boiler. In addition,
the once through boiler eliminates the
need for thick steel plate for the steam
drum. Due to limited material availability
in Europe, the once through philosophy
was followed during the 1930's and
1940's, while the United States continued
to rely on natural circulation boiler
design. [12]
Figure 13: Benson type once through boiler with tilted
tube wall. [2].
25
Supercritical boiler
The era following the Second World War brought on rapid economic development in the United
States and the desire for more efficient power plant operation increased. Improvements in both
boiler tube metallurgy and water chemistry technologies in combination with once through boilertechnology made a power plant, operating at supercritical water pressure, possible.
Figure 14: The world's first supercritical power plant, built by Babcock&Wilcox and General
Electric, started operating at 125 MW in 1957 with a main steam condition of 31 MPa and 621°C
[12].
Graphs and timelines of development in boiler technology
To conclude the chapter on the history of boiler technology up to date, we start with presenting a
timeline on how the unit sizes of boilers have changed throughout history (Figure 15).
The development of the main steam temperature in steam boilers increased until the 70's. The
limiting factor for raising steam temperature is the tube materials. Although there are power plants
running at main steam temperatures over 600°C, there are yet no good, economical materials that
can take temperatures above 550°C available (Figure 16).
The development of the main steam pressure increased also steadily until the 70's (Figure 17). The
peak that can be spotted about 1930 comes from the early trials of once through boilers, cause the
first once through boilers were run at critical steam pressures but later lowered since the tube
material available couldn't take the high pressures. The pressure was stabilized in the 70's in order
to correspond with steam temperature about 540-550°C.
26
Figure 15: Development of unit size. [2]
Figure 16: Graph presenting the development
of the main steam temperature of boiler. [2]
Figure 17: Graph presenting the development of
the main steam pressure of boilers. [2]
Steam boilers and safety
The safety--or lack of safety--of steam was an important part of its history. The boilers, which
contained the steam, were prone to explode. This occurred for a variety of reasons: undetected
corrosion or furring of the heated surfaces, clumsy repairs, or failure to keep the water up to the
required level, so causing firebox plates to overheat. As early as 1803 a safety device, a lead plug,
was invented. The plug was designed to melt if the firebox crown became overheated and release
steam before worse damage was done. However, this device was not adopted widely.
27
After an 1854 explosion in England that killed ten people, the Boiler Insurance and Steam Power
Company was started. Not until 1882, though, was safety legislation introduced in Britain. In the
United States there was no government regulation at all.
Following the action of safety legislation in England, the number of lives lost in England from
boiler accidents fell from 35 in 1883 to 24 in 1900 and to 14 in 1905. During a comparable time
period in the United States, 383 people were killed in boiler accidents. The problem of safety with
steam engines was eventually reduced by the introduction of new forms of power, including the
steam turbine. However, boiler accidents remain a fact of life even today, and continue to cause
fatalities. [5]
28
References
1.
Woodcroft B. (translator and editor) The pneumatics of Hero of Alexandria. London
1851. Online book, read September 2003. http://www.history.rochester.edu/steam/hero/
2.
Vakkilainen E. Lecture slides and material on steam boiler technology. 2001
3.
American Heritage® Dictionary of the English Language: Fourth Edition.
http://www.bartleby.com
4.
Two thousand years of steam (Steam Boat Days). Web page, read autumn 2001.
http://www.ulster.net/%7Ehrmm/steamboats/steam1.html
5.
Dreams of Steam: The History of Steam Power. Web page, read autumn 2001.
http://www.moah.org/exhibits/archives/steam.html
6.
The Growth of the Steam Engine. Web page, read September 2001.
http://www.history.rochester.edu/steam/thurston/1878/Chapter1.html
7.
Great Old Steam Pictures. Web page, read September 2001.
http://www.bigtoy.com/photo/old_steam.html
8.
Steamboats.com. A Short History of Steam Engines. Web page, read September 2003.
http://steamboats.com/engineroom4.html
9.
About.com. Inventors: Babcock & Wilcox. Web page, read September 2003.
http://inventors.about.com/library/inventors/blbabcock_wilcox.htm
10.
Boiler - Water Tube Type. Web page, read September 2001.
http://www.shomepower.com/dict/b/boiler_water_tube_type.htm
11.
Babcock & Wilcox. Printed brochure. http://www.babcock.com/
12.
Babcock & Wilcox. Supercritical (Once Through) Boiler Technology. PDF-file, read
October 2001. http://www.babcock.com/pgg/tt/pdf/BR-1658.pdf
29
Modern Boiler Types and Applications
Sebastian Teir
STEAM BOILER TECHNOLOGY – Modern Boiler Types and Applications
Table of contents
Introduction........................................................................................................................................33
Grate furnace boilers..........................................................................................................................33
Cyclone firing ....................................................................................................................................34
Pulverized coal fired (PCF) boilers....................................................................................................35
Fuel characteristics of coal.............................................................................................................35
Burners and layout .........................................................................................................................36
Oil and gas fired boilers .....................................................................................................................36
Fluidized bed boilers..........................................................................................................................37
Principles........................................................................................................................................38
Main types......................................................................................................................................38
Heat recovery steam generators (HRSG)...........................................................................................40
HRSGs in power plants..................................................................................................................41
Refuse boilers.....................................................................................................................................42
Recovery boilers ................................................................................................................................43
Bio-energy boilers..............................................................................................................................44
Packaged boilers ................................................................................................................................45
Scandinavian steam generator suppliers ............................................................................................46
References..........................................................................................................................................47
32
Introduction
Steam boilers can be classified by their combustion method, by their application or by their type of
steam/water circulation. In this chapter the following boiler types will be presented and briefly
described, to give the reader a perspective of the various types and uses of various steam boilers:
•
•
•
•
•
•
•
•
Grate furnace boilers
Cyclone boilers
Pulverized coal fired (PCF) boilers
Oil and gas fired boilers
Heat recovery steam generators (HRSG)
Refuse boilers
Recovery boilers
Packaged boilers
Grate furnace boilers
•
•
•
Removal of moisture - brown part
Pyrolysis (thermal decomposition) and
combustion of volatile matter - yellow part
Combustion of char - red part
Fu
e
l
R
n
tio
a
i
ad
m
fr o
lls
wa
Air
d
n an
iatio
Rad
tion
vec
con
Grate firing has been the most commonly used
firing method for combusting solid fuels in
small and medium-sized furnaces (15 kW - 30
MW)
since
the
beginning
of
the
industrialization. New furnace technology
(especially fluidized bed technology) has
practically superseded the use of grate furnaces
in unit sizes over 5 MW. Waste is usually
burned in grate furnaces. There is also still a lot
of grate furnace boilers burning biofuels in
operation. Since solid fuels are very different
there are also many types of grate furnaces. The
principle of grate firing is still very similar for
all grate furnaces (except for household
furnaces). Combustion of solid fuels in a grate
furnace, which is pictured in Figure 1, follows
the same phases as any combustion method:
Figure 1: Drawing of the combustion process in
a sloping grate furnace.
When considering a single fuel particle, these phases occur in sequence. When considering a
furnace we have naturally particles in different phases at the same time in different parts of the
furnace.
The grate furnace is made up a grate that can be horizontal, sloping (Figure 2) or conical (Figure 3).
The grate can consist of a conveyor chain that transports the fuel forward. Alternatively some parts
of the grate can be mechanically movable or the whole grate can be fixed. In the later case the fuel
is transported by its own weight (sloping grate). The fuel is supplied in the furnace from the hopper
and moved forward (horizontal grate) or downward (sloping grate) sequentially within the furnace.
33
The primary combustion air is supplied
from underneath the fire bed, by which
the air makes efficient contact with the
fuel, when blowing through the bed, to
dry, ignite and burn it. The secondary
(and sometimes tertiary) combustion air is
supplied above the bed, in order to burn
combustible gases that have been released
from the bed. The fuel is subjected to selfsustained burning in the furnace and is
discharged as ash. The ash has a relatively
high content of combustible matter. [1]
Cyclone firing
The cyclone furnace chambers are
mounted outside the main boiler shell,
which will have a narrow base, together
with an arrangement for slag removal
(Figure 4). Primary combustion air carries
the particles into the furnace in which the
relatively large coal/char particles are
retained in the cyclone while the air
passes through them, promoting reaction.
Secondary air is injected tangentially into
the cyclone. This creates a strong swirl,
throwing the larger particles towards the
furnace walls. Tertiary air enters the
centre of the burner, along the cyclone
axis, and directly into the central vortex. It
is used to control the vortex vacuum, and
hence the position of the main combustion
zone which is the primary source of
radiant heat. An increase in tertiary air
moves that zone towards the furnace exit
and the main boiler. [3]
Cyclone-fired boilers are used for coals
with a low ash fusion temperature, which
are difficult to use with a PCF boiler. 8090% of the ash leaves the bottom of the
boiler as a molten slag, thus reducing the
load of fly ash passing through the heat
transfer sections to the precipitator or
fabric filter to just 10-20% of that present.
As with PCF boilers, the combustion
chamber is close to atmospheric pressure,
simplifying the passage of coal and air
through the plant. [3]
Figure 2: Sloped grate furnace.
Figure 3: BioGrateTM - a rotating conical grate. [2]
Boiler
Burnout
Zone
Overfire
Air
Coal Reburn
Burners
Air
Secondary
Air
Reburn
Zone
Pulverized
Coal
Air
Preheater
Electrostatic
Precipitator
Stack
Coal
Air
Primary
Air
Cyclone
Burner
Main
Combustion
Zone
Dry Waste To Disposal
Water
Molten Slag
Slag to Disposal
Figure 4: Schematics of a 100 MW coal fuelled boiler
with a cyclone burner. [4]
34
Cyclone firing can be divided into horizontal and vertical arrangements based on the axis of the
cylinder. Cyclone firing can also be dry or molten based on ash behaviour in the cyclone. Based on
cooling media the cyclones are either water-cooled or air-cooled (a.k.a. air cooled). Cyclone firing
has successfully been used to fire brown coal in Germany. Peat has been fired in cyclones at Russia
and Finland.
Compared with the flame of a conventional burner, the high-intensity, high-velocity cyclonic flames
transfer heat more effectively to the boiler's water-filled tubes, resulting in the unusual combination
of a compact boiler size and high efficiency. The worst drawbacks of cyclone firing are a narrow
operating range and problems with the removal of ash. The combustion temperature in a cyclone is
relatively high compared to other firing methods, which results in a high rate of thermal NOx
formation. [1]
Pulverized coal fired (PCF) boilers
Coal-fired water tube boiler systems generate
approximately 38% of the electric power
generation worldwide and will continue to be
major contributors in the future. Pulverized
coal fired boilers, which are the most popular
utility boilers today, have a high efficiency
but a costly SOx and NOx control. Almost
any kind of coal can be reduced to powder
and burned like a gas in a PCF-boiler, using
burners (Figure 5). The PCF technology has
enabled the increase of boiler unit size from
100 MW in the 1950's to far over 1000 MW.
New pulverized coal-fired systems routinely
installed today generate power at net thermal
cycle efficiencies ranging from 40 to 47%
lower heating value, LHV, (corresponding to
Figure 5: PCF-burner. [5]
34 to 37% higher heating value, HHV) while removing up to 97% of the combined, uncontrolled air
pollution emissions (SOx and NOx). [7]
Fuel characteristics of coal
Coal is a heterogeneous substance in terms of its
organic and inorganic content. Since only
organic particles can be combusted, the
inorganic particles remain as ash and slag and
increase the need for particle filters of the
fluegas and the tear and wear of furnace tubes.
Pulverizing coal before feeding it to the furnace
has the benefit that the inorganic particles can be
separated from the organic before the furnace.
Still, coal contains a lot of ash, part of which can
be collected in the furnace. In order to be able to
remove ash the furnace easier, the bottom of the
furnace is shaped like a 'V' (Figure 6).
Boiler
Economizer
Electrostatic
Precipitator
Windbox
Ash
Secondary
Air Port
Coal
and
Air
Low-NOX Cell
Burner System
Stack
Secondary
Air Port
Coal
and
Air
Windbox
Low-NOX Cell
Burner System
Fly Ash To Disposal
Bottom Ash To Disposal
Figure 6: PCF Boiler schematics. [4]
35
Burners and layout
Another benefit from pulverizing coal
before combustion is that the coal air
mixture can be fed to the boiler through
jet burners, as in oil and gas boilers. A
finer particle is faster combusted and
thus the combustion is more complete
the finer the coal is pulverized and
formation of soot and carbon monoxides
in the flue gas is also reduced. The size
of a coal grain after the coal grinder is
less than 150 mm.
Figure 8 shows various arrangement
options of burners.
Figure 7: Schematics of a Low-NOx burner. [4]
Two broadly different boiler layouts are
used. One is the traditional two-pass
layout where there is a furnace chamber,
topped by some heat transfer tubing to
reduce the FEGT. The flue gases then
turn through 180°, and pass downwards
through the main heat transfer and
economiser sections. The other design is
to use a tower boiler, where virtually all
the heat transfer sections are mounted
vertically above each other, over the
combustion chamber. [4]
Oil and gas fired boilers
Oil and natural gas have some common
properties: Both contain practically no
moisture or ash and both produce the
same amount of flue gas when
combusted. They also burn in a gaseous
condition with almost a homogenous
flame and can therefore be burnt in
similar burners with very little air
surplus (Figure 9 and Figure 10). Thus,
oil and gas can be combusted in the same
types of boilers. The radiation
differences in the flue gases of oil and
gas are too high in order to use both
fuels in the same boiler. Combusting oil
and gas with the same burner can cause
flue gas temperature differences up to
100°C.
The construction of an oil and gas boiler
is similar to a PCF-boiler, with the
Figure 8: PCF-boiler with horizontal coal firing with
two-pass layout. [4]
Figure 9: Photo of a flame from a burner combusting
oil. [7]
36
exception of the bottom of the furnace, which can be horizontal thanks to the low ash content of oil
and gas (Figure 11). Horizontal wall firing (all burners attached to the front wall) is the most
affordable alternative for oil and gas burners. [1]
Figure 10: Photo of a flame from a burner
combusting gas. [7]
Figure 11: Oil/gas Boiler with horizontal wall
firing. [6]
Fluidized bed boilers
Fluidized bed combustion was not used for energy production until the 1970's, although it had been
used before in many other industrial applications. Fluidized bed combustion has become very
common during the last decades. One of the reasons is that a boiler using this type of combustion
allows many different types of fuels, also lower quality fuels, to be used in the same boiler with
high combustion efficiency. Furthermore, the combustion temperature in a fluidized bed boiler is
low, which directly induce lower NOx emissions. Fluidized bed combustion also allows a cheap
SOx reduction method by allowing injection of lime directly into the furnace.
FIXED BED
BUBBLING
MIN FLUID
VELOCITY
TURBULENT
ENTRAINMENT
VELOCITY
CIRCULATING
PARTICLE
MASS FLOW
∆p
(LOG)
VELOCITY (LOG)
Figure 12: Regimes of fluidized bed systems [8].
37
Principles
The principle of a fluidized bed boiler is based on a layer of sand or a sand-like media, where the
fuel is introduced into and combusted. The combustion air blows through the sand layer from an
opening in the bottom of the boiler. Depending on the velocity of the combustion air, the layer gets
different types of fluid-like behaviour, as listed and described in Figure 12. This type of combustion
has the following merits:
•
•
•
•
Fuel flexibility; even low-grade coal such as sludge or refuse can be burned
High combustion efficiency
Low NOx emission
Control of SOx emission by desulfurization during combustion; this is achieved by
employing limestone as a bed material or injecting limestone into the bed.
• Wide range of acceptable fuel particle sizes; pulverizing the fuel is unnecessary
• Relatively small installation, because flue gas desulfurization and pulverizing facilities are
not required
Main types
There are two main types of fluidized bed
combustion boilers: Bubbling fluidized bed
(BFB) and circulating fluidized bed (CFB)
boilers.
BUBBLING FLUIDIZED BED BOILER
30.8 MWth, 11.9 kg/s, 80 bar, 480 °C
In the bubbling type, because the velocity of the
air is low, the medium particles are not carried
above the bed. The combustion in this type of
boiler is generated in the bed. Figure 13 and
Figure 14 show examples of BFB boilers.
The CFB mode of fluidization is characterized
by a high slip velocity between the gas and
solids and by intensive solids mixing. High slip
velocity between the gas and solids, encourages
high mass transfer rates that enhance the rates of
the oxidation (combustion) and desulfurization
reactions, critical to the application of CFBs to
power generation. The intensive mixing of
solids insures adequate mixing of fuel and
combustion products with combustion air and
flue gas emissions reduction reagents.
In the circulating type (Figure 15), the velocity
of air is high, so the medium sized particles are
carried out of the combustor. The carried
particles are captured by a cyclone installed in
the outlet of combustor.
©PIIRTEK OY #8420
SALA-HEBY ENERGI AB
SWEDEN
Figure 13: Example of a BFB boiler. [9]
Combustion is generated in the whole combustor with intensive movement of particles. Particles are
continuously captured by the cyclone and sent back to the bottom part of the combustor to combust
unburned particles. This contributes to full combustion.
38
Figure 14: BFB boiler used in a CHP power plant, [10]
The CFB boiler (Figure 16) has the following
advantages over the BFB Boiler:
•
•
Higher combustion efficiency
Lower consumption of limestone as a
bed material
• Lower NOx emission
• Quicker response to load changes
The main advantage of BFB boilers is a
much larger flexibility in fuel quality than
CFB boilers. BFB boilers have typically a
power output lower than 100 MW and CFB
boilers range from 100 MW to 500 MW. In
recent years, many CFB boilers have been
installed because of the need for highly
efficient, environmental-friendly facilities.
Figure 15: Cutaway of a CFB furnace and cyclone.
[11]
39
Figure 16: A CFB boiler schematics. [9]
Heat recovery steam generators (HRSG)
As the name implies, heat recovery steam
generators (HRSGs) are boilers where heat,
generated in different processes, is
recovered and used to generate steam or
boil water. The main purpose of these
boilers are to cool down flue gases
produced by metallurgical or chemical
processes, so that the flue gases can be
either further processed or released without
causing harm. The steam generated is only a
useful by-product. Therefore extra burners
are seldom used in ordinary HRSGs.
HRSGs are usually a link in a long process
chain, which puts extremely high demands
on the reliability and adaptability of these
boilers. Already a small leakage can cause
the loss of the production for a week.
Problems occurring in these boilers are
more diverse and more difficult to control
than problems in an ordinary direct heated
boiler. Figure 17 shows an example of a
HRSG with horizontal layout. Figure 18
explains the different parts of the same
HRSG.
Figure 17: A HRSG with horizontal layout. [12]
40
1
2
3
4
5
6
Inlet Duct
Distribution grid
HP Superheater 1
Burner
Split Superheater
HP Superheater 2
7 CO Catalyst
8 HP Steam Drum
9 Top Supports
10 SCR Catalyst
11 LP Steam Drum
12 HRSG Casing
13 Deareator
14 Stack
15 Preheater
16 DA Evaporator
17 HP/IP Economizer
18 IP Evaporator
19 IP Superheater
20 HP Economizer
21 Ammonia Injection Grid
22 HP Evaporator
Figure 18: Various parts of the HRSG in Figure 17 explained. [12]
HRSGs in power plants
Gas turbines and diesel engines are
nowadays commonly used in
generating electricity in power
plants. The temperature of the flue
gases from gas turbines is usually
over 400°C, which means that a lot
of heat is released into the
environment and the gas turbine
plant works on a low efficiency.
The efficiency of the power plant
can be improved significantly by
connecting a heat recovery boiler
(HRSG) to it, which uses the heat
in the flue gases to generate steam.
This type of combination power
generation processes is called a
combined cycle (Figure 19).
Figure 19: Simplified combined cycle, utilizing a HRSG. [12]
Since the flue gases of a gas turbine are very clean, tubes can be tightly seated or rib tubes can be
used to improve the heat transfer coefficient. These boilers are usually natural circulation boilers. If
the life span of the power plant is long enough, the boiler is usually fitted with an economizer. If
more electrical power output is wanted, but the temperature of the flue gas is insufficient, the boiler
41
can be equipped with an extra burner (that burns the same fuel as the gas turbine) in order to
increase the flue gas temperature and thus generate steam with a higher temperature.
Refuse boilers
The standard refuse (or waste) recovery boiler incinerates solid or liquid waste products. This boiler
type is not to be mixed with the recovery boilers used in pulp and paper industry. Therefore, we will
always refer to refuse boilers when talking about waste and recovery boilers when we mean the
specific chemical recovery process used in the pulp and paper industry.
The combustion of waste differs radically compared to other fuels mostly due to the varying
properties of waste. Also, the goal when combusting waste is not to produce energy, but to reduce
the volume and weight of the waste and to make it more inert before dumping it on a refuse tip.
1 storage bin
2
3
4
13
furnace with grate
post combustion
boiler
bottom ash conveyor
5 electrostatic precipitator
6 economizer (not typically here)
7 draft fan
8
9
10
11
12
wet scrubber 1
wet scrubber 2
SCR DENOx
dioxin removal
stack
Figure 20: Municipal Solid Waste Incineration plant.
Waste is burned in many ways, but the main method is to combust it in a grate boiler with a
mechanical grate (Figure 20). Other ways to burn waste is to use a fixed grate furnace, a fluidized
bed for sludge or rotary kilns for chemical and problematic waste. Waste is usually “mass burned”,
i.e. it is burned in the shape it was delivered with minimal preparation and separation. The main
preparation processes are grinding and crushing of the waste and removal of large objects (like
refrigerators). Waste has to be thoroughly combusted, so that harmful and toxic components are
degraded and dissolved.
Waste can be refined into fuel, by separating as much of the inert and inorganic material as
possible. This is called refuse derived fuel (RDF) and can be used as the primary fuel in fluidized
bed boilers or burned as a secondary fuel with other fuels. RDF is becoming more common
nowadays.
42
Recovery boilers
All paper is produced from one raw material:
pulp. One of the most common methods used
to produce pulp is the Kraft process, which
consists of two related processes. The first is a
pulping process, in which wood is chemically
converted to pulp. The second is a chemical
recovery process, in which chemicals used in
pulping are returned to the pulping process to
be used again. The waste liquid, from where
chemicals are to be recovered, is called black
liquor.
The largest piece of equipment in power and
recovery operations is the recovery boiler
(Figure 21). It serves two main purposes. The
first is to "recover" chemicals in the black
liquor through the combustion process
(reduction) to be recycled to the pulping
process. Secondly, the boiler burns the organic
materials in the black liquor and produces
process steam and supplies high pressure
steam for other process components.
Black liquor is injected into the recovery
boiler from a height of six meters (Figure 22).
The combustion air is injected at three
different zones in the boiler. The burning
black liquor forms a pile of smelt at the
bottom of the boiler, where complicated
reactions take place. The smelt is drained from
the boiler and is dissolved to form green
liquor. The green liquor is then causticized
with lime to form white liquor for cooking the
wood chips. The residual lime mud is burnt in
a rotary kiln to recover the lime. Energy
released by the volatilization of the liquor
particles in the recovery boiler yields a heat
output that is absorbed by water in the boiler
tubes and steam drum. Steam produced by the
boiler is utilized primarily to satisfy heating
requirements, and to co-generate the
electricity needed to operate the various pieces
of machinery in the plant.
Figure 21: Recovery boiler schematics. [13]
Figure 22: Schematics of the black liquor spraying
in the furnace of a recovery boiler. The pile on the
bottom is the smelt. [13]
43
Bio-energy boilers
Renewable energy production is becoming a worldwide priority as countries strive for sustainable
growth and better living conditions. Many countries (e.g. EU) have already set demanding targets to
increase electricity production using bio-energy resources and have introduced attractive incentives
to accelerate this process. Bio-energy solutions are based on a local fuel supply and thus provide
price stability, a secure supply of heat and power, and also local employment. Biofuels are
increasingly becoming locally traded commodities, which will further secure fuel price stability and
availability. At the same time, green certificates and emission trading offer new opportunities for
financing bio-energy projects. Figure 23, Figure 24, and Figure 25 shows examples of biofuel
combusting boiler applications.
Figure 23: Firetube hot water boiler in a Wärtsilä 8 MWth thermal plant, combusting biofuels. [14]
Figure 24: Wärtsilä CHP plant using a water tube boiler connected to the furnace. [14]
44
Boilers combusting biofuels can be used to produce only electricity, but they are mostly used in
combined heat and power (CHP) plants and district heating plants. These boilers are designed to
operate on a wide variety of biofuels, including extremely wet fuels such as wood residues, wood
chips, bark and sawdust. Smaller boilers use grate firing technology for biofuel combustion, while
larger plants use fluidized bed combustion technology. Smaller grate fired plants for thermal heat
production, (<10 MWth), have fire tube boilers (Figure 23), while larger ones are fitted with
integrated water/fire tube boilers. [2]
One of the world's largest solid biofuel-fired circulating fluidized bed (CFB) boiler (550 MWth) has
been built at Alholmens Kraft power plant at Pietarsaari, Finland (Figure 25). The CFB boiler with
auxiliary equipment and the building was delivered by Kvaerner Pulping Oy and commissioned in
autumn 2001.
Figure 25: Schematic of the CFB boiler at Alholmen. Power output: 550 MWth, Steam parameters:
194 kg/s, 165 bar, 545°C. [11]
Packaged boilers
Packaged boilers are small self-contained boiler units (Figure 27). Packaged boilers are used as hot
water boilers, aiding utility boilers and process steam producers. Packaged boilers can be both water
tube and fire tube boilers. Packaged boilers can only be used with oil and gas as fuel without
separate preparation devices. A packaged boiler can also be rented if there is a need for a temporary
boiler solution (Figure 26).
The benefits of packaged boilers over common utility boilers are:
•
Short installation time and low installation costs
45
•
•
•
•
Small space usage
Lower acquisition cost
Better quality surveillance in work
Standardized units
The drawbacks of packaged boilers are:
•
•
Higher power consumption
Cleaning periods more frequent
Figure 26: Trailer-mounted boiler for rental.
[16]
Figure 27: Fire tube packaged boiler. [15]
Scandinavian steam generator suppliers
•
•
•
•
•
•
Andritz (http://www.andritz.com/)
o Recovery boilers
Foster Wheeler (http://www.fwc.com/)
o CFB and BFB boilers
o Coal (PC) and oil fired boilers
o Packaged Boilers
o HRSGs
Kvaerner (http://www.kvaerner.com/powergeneration/)
o CFB and BFB boilers
o Recovery boilers
Noviter (http://www.noviter.fi )
o Packaged boilers
o Oil fired boilers
o Biomass boilers
Wärtsilä (http://www.wartsila.com/ )
o Grate furnace boilers for biofuel
o Package boilers
Höyrytys (http://www.hoyrytys.fi/)
o Package boilers
o Steam & Heating services
o Boiler rentals
46
References
1.
Vakkilainen E. Lecture slides and material on steam boiler technology. 2001.
2.
Wärtsilä. Bio-energy solutions from Wärtsilä. PDF brochure, viewed September 2003.
http://www.wartsila.com/english/index.jsp
3.
IEA Coal Research Centre. Cyclone fired wet bottom boilers. Web Page, read 15.8.2002.
http://www.iea-coal.org.uk/CCTdatabase/cyclone.htm
4.
Clean Coal Technology Compendium. Demonstration of Coal Reburning for Cyclone
Boiler NOx Control. Los Alamos National Laboratory. Web Page, read September 2003
http://www.lanl.gov/projects/cctc/index.html
5.
Andritz. Recovery boiler operation manual. Ahlstrom Machinery Corporation © 1999.
CD-rom. http://www.andritz.com/
6.
Babcock & Wilcox. Printed brochure. http://www.babcock.com/
7.
Combustion Engineering. ”Combustion: Fossil power systems”. 3rd ed. Windsor. 1981.
8.
CFB Engineering Manual, extract supplied by Foster Wheeler. http://www.fwc.com/
9.
Pictures and schematics supplied by Foster Wheeler. http://www.fwc.com/
10.
Picture supplied by Härnösand Energi&Miljö Ab, Fortum. http://www.fortum.com
11.
Picture supplied by Kvaerner Power Division.
http://www.kvaerner.com/powergeneration/
12.
Nooter/Erikssen. Web page, read September 2003.
http://www.ne.com/hrsgs_framed.html
13.
Pictures supplied by Andritz. http://www.andritz.com/
14.
Pictures supplied by Wärtsilä. http://www.wartsila.com/english/index.jsp
15.
Höyrytys Oy. Web page, read September 2003. http://www.hoyrytys.fi/
16.
Nationwide Boiler Inc. Web page, read September 2003.
http://www.nationwideboiler.com/
47
Steam/Water Circulation Design
Sebastian Teir, Antto Kulla
STEAM BOILER TECHNOLOGY – Steam/Water Circulation Design
Table of contents
Introduction........................................................................................................................................51
Large volume boilers .........................................................................................................................51
Shell type boilers............................................................................................................................51
Fire tube boilers .............................................................................................................................52
Water tube boilers ..............................................................................................................................53
Natural circulation boilers..............................................................................................................54
Natural circulation principle ......................................................................................................54
Advantages and disadvantages...................................................................................................55
Natural circulation design ..........................................................................................................56
Circulation ratio .....................................................................................................................56
Driving force of natural circulation .......................................................................................56
Downcomers ..........................................................................................................................57
Wall tubes ..............................................................................................................................58
Headers...................................................................................................................................59
Boiling within vertical evaporator tubes................................................................................60
Heat transfer crisis .................................................................................................................60
Optimization of natural circulation design.............................................................................61
Special designs.......................................................................................................................61
Assisted or forced circulation boilers.............................................................................................62
Principle of forced circulation....................................................................................................62
Flow distribution between parallel riser tubes ...........................................................................63
Boilers types...............................................................................................................................63
La Mont boilers......................................................................................................................63
Controlled circulation boilers.................................................................................................63
Once-through boilers......................................................................................................................64
Once-through boiler types..........................................................................................................65
Benson design ........................................................................................................................65
Sulzer design ..........................................................................................................................65
Ramzin design........................................................................................................................66
Spiral wall tubes.........................................................................................................................66
Multiple pass design...................................................................................................................66
Operation....................................................................................................................................67
Manufacture and use of once-though boilers.............................................................................68
Combined circulation boilers .........................................................................................................68
References..........................................................................................................................................69
50
Introduction
As presented in the previous chapter, boilers can be classified by their combustion method, by their
application or by their type of steam/water circulation.
This chapter will describe the different types of steam/water circulation in boilers. It will not discuss
steam/water circulation for the applications listed in Figure 1 under “Others” (i.e. nuclear, solar, and
electric). [1]
Steam boilers
Large volume
Water tube
Others
Fire tube
Natural
circulation
Solar
Gas tube
Assisted/forced
circulation
Electric
Shell
Once-through
Nuclear
Combined
circulation
Figure 1: Steam boiler types according to steam/water circulation.
Large volume boilers
Shell type boilers
A steam boiler can be either a large volume
(shell) type boiler or a water tube boiler. Shell
type boilers are boiler that are built similarly to
a shell and tube heat exchanger (Figure 2). In
large volume type boilers a burner or a grate is
situated inside a big tube, called chamber. The
chamber is surrounded by water in a pressure
vessel that functions as the outer boiler wall.
Thus, the water absorbs the heat and some of
the water is converted to saturated steam. Flue
gases continue from the chamber to the stack
so that they are whole the time situated inside
the tubes. Nowadays fire-tube boilers are the
most used type of large volume boilers. Also
electric boilers where water is heated with an
electrode source can be considered large
Figure 2: Shell type boiler: Höyrytys TTKV-fire
tube boiler. [2]
51
volume boilers. However, large volume boilers are today used for small-scale steam and hot-water
production only and, overall, they are not common in large-scale industrial use anymore. [1]
Fire tube boilers
Modern fire tube boilers are used in
applications that require moderate pressures
and moderate demand. As the name implies,
the basic structure of a fire tube boiler consists
of tubes, where fuel is burned and flue gas is
transported, located in a pressurized vessel
containing water. Usually boilers of this type
are customized for liquid or gaseous fuels, like
oil, natural gas and biogases. Fire tube boilers
are used for supplying steam or warm water in
small-scale applications. [3]
Usually fire tube boilers consist of cylindrical
chambers (1-3) where the main part of
combustion takes place, and of fire tubes. In
most of the cases, fire tubes are situated
horizontally (fire tubes placed above
chambers).
1. Turning chamber
2. Flue gas collection
chamber
3. Open furnace
4. Fire tube
5. Burner seat
6.
7.
8.
9.
10.
11.
Figure 3: Höyrytys TTK fire tube steam boiler.
[2]
Fire tubes
Manhole
Hatch
Cleaning hatch
Steam outlet
Water inlet
12.
13.
14.
15.
16.
Flue gas out
Blow-out hatch
Feet
Insulation
Figure 4: Schematic of the Höyrytys TTKV-fire tube hot-water boiler from Figure 2. [2]
Fire tube boilers generally have tubes with a diameter of 5 cm or larger. They are usually straight
and relatively short so that the hot gases of combustion experience a relatively low pressure drop
while passing through them. The path of the flue gases goes from burners/grate, through one of the
52
chambers, to the other end of the chamber. There the flue gases turn to reverse direction and return
through the fire tubes and continue then to the stack (Figure 4).
1. Turning chamber
2. Flue
gas
collection
chamber
3. Open furnace
4. Flame tube
5. Burner seat
6. Manhole
7. Fire tubes
8.
9.
10.
11.
12.
13.
14.
15.
Water space
Steam space
Flue gas out
Blow-out hatch
Main hatch
Cleaning hatch
Main steam outlet
16.
17.
18.
19.
20.
21.
Level control assembly
Feedwater inlet
Utility steam outlet
Safety valve assembly
Feet
Inslulation
Figure 5: Schematic of the Höyrytys TTK fire tube steam boiler from Figure 3. [2]
Fire tube boilers have a fairly large amount of contained water so that there is a considerable
amount of stored heat energy in the boiler. This also allows for load swings where large amounts of
steam or hot water are required in a relatively short period of time, as often happens in process
applications. Fire tube boilers can take a great deal of abuse and inattention and still function at
competent levels. Fire tube boilers have a life expectancy of 25 years or more. Boilers that are older
than 75 years are still known to be in operation. Consistent maintenance and careful water treatment
go a long way towards insuring the long life of these boilers.
Nowadays fire tube boilers are mostly used as district heating boilers, industrial heating boilers and
other small steam generators, as in biofuel fired plants. Fire-tube boilers are not anymore used for
electricity production because of their upper limits (4 MPa steam pressure and about 50 kg/s steam
mass flow). The steam pressure limit is based on the fact that when the steam pressure in the boiler
rises, thicker fire tubes and chambers are needed – thus the price of the boiler rises. As a result of
this, boiler types where water/steam mixture is inside the tubes have lower prices for the same
steam capacity and pressure. Fire-tube boilers can reach thermal efficiencies of about 70 percent.
There are also special types of fire-tube boilers such as scotch marine boilers and firebox boilers,
but they will not, however, be discussed further here. The rest of this chapter concentrates on the
main types of water tube boilers.
Water tube boilers
In contrast to large volume boilers, the steam/water mixture is inside the tubes in water tube boilers,
and is heated by external combustion flames and flue gases. The water tube boilers are classified by
53
the way of the water/steam circulation: natural circulation, forced or assisted circulation, oncethrough and combined circulation type boilers. All boilers for power generation are nowadays water
tube boilers.
Natural circulation boilers
The natural circulation is one of the oldest principles for steam/water circulation in boilers. Its use
has decreased during the last decades due to technology advances in other circulation types.
Natural circulation principle is usually implemented on small and medium sized boilers. Typically
the pressure drop for a natural circulation boiler is about 5-10 % of the steam pressure in the steam
drum and the maximum steam temperature varies from 540 to 560 °C.
Natural circulation principle
The water/steam circulation begins from
the feed water tank, from where feed
water is pumped. The feedwater pump
(Figure 6) raises the pressure of the
feedwater to the wanted boiler pressure.
In practice, the final steam pressure
must be under 170 bar in order for the
natural circulation to work properly.
Superheaters
Steam drum
Economizer
The feed water is then preheated in the
economizer almost up to the boiling
point of the water at the current
pressure. To prevent the feed water from
boiling in the economizer pipes, the
water temperature out of the economizer
temperature is on purpose kept about 10
degrees under the boiling temperature.
In other words, the approach
temperature is 10 K.
Downcomers
Mud drum
Evaporator
(riser tubes)
Feedwater
pump
From the economizer the feed water
Figure 6: Natural circulation principle.
flows to the steam drum of the boiler. In
the steam drum the water is well mixed
with the existing water in the steam drum. This reduces thermal stresses within the steam drum.
The saturated water flows next from the steam drum through downcomer tubes to a mud drum
(header). There are usually a couple of downcomer tubes, which are unheated and situated outside
the boiler.
The name "mud drum" is based on the fact that a part of the impurities in the water will settle and
this 'mud' can then be collected and removed from the drum.
The saturated water continues from the header to the riser tubes and partially evaporates. The riser
tubes are situated on the walls of the boiler for efficient furnace wall cooling. The rises tubes are
sometimes also called generating tubes because they absorb heat efficiently to the water/steam
mixture (steam being generated). The riser tubes forms the evaporator unit in the boiler.
54
After risers, the water/steam mixture goes back to the steam drum. In the steam drum water and
steam are separated: the saturated water will return to the downcomer tubes and the saturated steam
will continue to the superheater tubes. Thus also salts, minerals and other impurities are separated
from the steam. The purpose of this separation is to protect the inside of the superheater tubes and
turbine for impurity deposition.
The steam from the steam drum continues to the superheater, where it is heated beyond its
saturation point. After the last superheater stage the steam exits the boiler.
This type of circulation is called natural circulation, since there is no water circulation pump in the
circuit. The circulation happens by itself due to the water/steam density differences between the
downcomers and risers. [5]
Advantages and disadvantages
Natural circulation (NC) boilers have the following advantages compared to other circulation types:
•
•
•
NC boilers are more tolerant on feed water impurities than other types of water tube boilers
NC boilers have lower internal consumption of electricity than other water tube boiler types.
NC boilers have a simple construction. Therefore the investment cost is low and the
reliability of the boiler high.
• NC boilers have a wide partial load range, practically even 0-100 % have the feature to be
held in a stand-by state, which means "warm at full pressure".
• NC boilers have constant heat transfer areas independent of boiler load, since the drum
separates the three heat exchangers - economizer, evaporator and superheater - from each
other.
• NC boilers have simpler process control, due to the big volume of water/steam side, which
behaves as a "buffer" during small load rate changes.
Natural circulation boilers have the following disadvantages compared to other circulation types:
•
•
•
•
•
•
•
NC boilers have a high circulation ratio (between 5 and 100), which leads up to massive
dimensions of the evaporator as the amount of water circulating in wall tubes can be up to
100 times of the mass flow of steam generated. This increases the requirement for space and
steel.
NC boilers need large diameters (large volume) of all tubes where the water/steam mixture
flows. This is because smaller diameters in tubes would cause pressure drop and thus higher
boilers would be needed for adequate pressure difference.
NC boilers need more accurate dimensioning as compared to other boiler types.
NC boilers are quite slow in start-up and "stop" situations (also when the load rate changes a
lot) because of the large water/steam tube volume (about 5 times the water/steam volume of
a once through boiler).
NC boilers are only suitable for subcritical pressure levels (practically for steam pressures
under 180 bar in the steam drum). This is due to the lack of density difference in
supercritical steam, and thus the lack of a driving force.
NC boilers have problems with more frequently occurring tube damages, due to the relative
large diameter of the boiler tubes.
NC boilers are sensitive to pressure variations. Sudden pressure drops or build-ups causes
increased rate of evaporation and thus the steam drum water level will also rise. This can
55
lead to water passing into the superheater tubes and water circulation problems that lead to
tube damages.
• NC boilers require a steam drum, which is a very expensive part of the boiler.
Natural circulation design
The following chapters concentrate on some
design issues in natural circulation boilers:
This chapter will use graphics and photos of an
Andritz
recovery
boiler
(Figure
7,
manufactured by Foster Wheeler), which is the
same boiler that was presented in “Modern
Boiler Types and Applications” on chemical
recovery boilers. [4]
Circulation ratio
The circulation ratio is one important variable
when designing new boiler. It is defined as the
mass rate of water fed to the steam-generating
tubes (raisers) divided by the mass rate of
generated steam. Thus, it is meaningful to
define the circulation ratio only for water tube
steam boilers with a steam drum:
U=
m& raisers
m& feedwater
(1)
Figure 7: The feedwater circulation construction
of the recovery boiler using natural circulation
drum. [4]
The variations in circulation ratio result from
the pressure level of the boiler, therefore high-pressure boilers have low ratios and low-pressure
boilers have high ratios, respectively. Other parameters that affect the circulation ratio are the height
of the boiler, heating capacity of the boiler and tube dimension differences between riser and
downcomer tubes.
For certain natural circulation applications dimensioning the circulation ratio is very difficult. The
circulation ratio varies between 5 and 100 for natural circulation boilers. The circulation ratio of
forced circulation boilers is normally between 3 and 10. For La Mont type of boilers the normal
values are between 6 and 10, for controlled circulation boiler between 4 and 5, respectively. Once
through boilers generate the same mass rate of steam as has been fed to boiler, thus their circulation
ratio is 1.
Driving force of natural circulation
The driving force of the natural circulation is based on the density difference between water/steam
mixture in riser and downcomer tubes, of which the riser tubes represent the lower density mixture
and downcomer tubes the higher density mixture. The driving pressure can be defined as follows:
∆pd = g ⋅ (H evaporator − H boiling )⋅ ( ρ dc − ρ r )
(2)
56
where g is the gravitational acceleration (9,81
m/s2), the heights are according to Figure 8
[m], and ρ dc − ρ r the difference in the average
density between the downcomers (dc) and
raiser (r) tubes [kg/m3], which is the most
difficult parameter to determine.
The conditions in the steam drum are such that
H2O is there as saturated water. There will be a
slight increase in water pressure because of the
hydrostatic pressure when the water travels
down in downcomer tubes. Thus, the water is
subcooled in the header (mud drum) after
downcomer tubes. Hence, in riser tubes the
water has first to be heated up till the water has
reached the evaporation (boiling) temperature
before it can evaporate. The boiling height, i.e.
the height where water has high enough
temperature to boil, can be calculated using the
circulation ratio and water/steam enthalpies:
H boiling =
h ′′ − h ′
⋅ H evaporator
∆h ⋅ U
(3)
Figure 8: A representation of the height
parameters of the driving force.
where h” is the enthalpy [kJ/kg] of saturated steam, and h’ enthalpy of saturated water (at the
pressure of the steam drum), U is the circulation ratio, and ∆h is the enthalpy change caused by the
rise in evaporation pressure (because of the subcooling of water in downcomer tubes).
Downcomers
Downcomer tubes have a relatively large diameter because the entire water amount for the
evaporator flows through the downcomer tubes before it is lead to wall tubes (riser tubes). Normally
the amount of downcomer tubes is between one and six.
Downcomer tubes are placed outside the boiler to prevent the water from evaporating, which could
decrease the driving force of natural circulation (decrease average density in downcomer tube). If
downcomer tubes have to be placed inside boiler construction, heat load to downcomers has to be
strongly restricted to prevent downcomer tubes from water boiling. Possible boiling in downcomer
tubes complicates circulation because the steam bubbles travel upwards and thus increase pressure
loss.
An ideal downcomer tube is as short as possible and the flow velocity of the water transported is as
high as possible. Figure 9 and Figure 10 show examples of downcomers in the chemical recovery
boiler.
57
Figure 9: Downcomers and the steam drum.
[4]
Figure 10: Downcomers from the steam drum.
[4]
Wall tubes
Pressure loss caused by wall tubes (or risers, evaporator tubes) of a natural circulation boiler should
be at low level because of the natural circulation principle. Thus, vertically installed riser tubes in
natural circulation boilers have a larger diameter than riser tubes in forced circulation boilers.
Figure 11: Water tubes. [4]
Figure 12: Furnace walls and floor. [4]
All natural circulation boilers must have an upwards-rising arrangement of wall tubes because of
the circulation principle. There are variations on how sharp the rise is:
58
In conservative vertical furnace boilers the wall tubes are placed in a straight vertical direction
(Figure 11 and Figure 13). In corner tube (Eckrohr) boilers the wall tubes are arranged as slightly
rising or horizontal wall-tube banks.
This particular boiler has a furnace height of 40 m. The diameters of the water tubes are about 60
mm. The riser tubes are all welded together, and form a gas-tight panel construction, a tube wall.
Since the boiler is a recovery boiler, the floor barely slopes (Figure 12 and Figure 14), in order to
support the smelt, and is therefore a different structure than coal-fired boilers (which have a wedgeshaped floor for collecting ash).
Figure 13: Front furnace wall being installed.
[4]
Figure 14: Furnace walls in place. [4]
Headers
The word "header" (Figure 15) is used in boiler
technology for all collector and distributor pipes,
including the mud drum (Figure 16). The most
important design parameter for headers is
diameter. It is defined by the flow rate and the
number of tubes connected to the header (here
the number of riser tubes).
Header construction is basically a miniature
version of a simple steam drum (diameters are
smaller than the ones of steam drums). However,
in headers there are usually no internals except
the orifices in forced circulation and oncethrough principle boilers. Small diameter headers
are constructed from a tube with welded front
and end plates, whereas the big headers are made
of bent steel plates in the same way as steam
drums.
Figure 15: Photograph of the economizer
header. [4]
59
Figure 16: Mud drum and collector headers. [4]
Boiling within vertical evaporator tubes
The boiling process in a vertical riser tube
begins with single-phase water flow in the
lowest part of the evaporator. Heat transfer from
the furnace produces initially some steam
bubbles.
Continuous heat transfer increases the steam
content in the mixture. In the annular boiling
state of the steam/water mixture the tube wall is
still covered by a water film, but as the steam
content increases water can be found in the tube
as mist only. This state is called the misty/drop
state (Figure 17).
Figure 17: Different types of water/steam flow
during the boiling process. [1]
Heat transfer crisis
Boiling process can be considered also in heat transfer terms. The heat flux in a furnace generated
by the combustion process is extremely high. There is a critical value that the heat flux can reach
which results in a sudden decrease of the heat transfer capacity of the tube. This is called departure
from nucleate boiling (DNB), dryout, burn out, critical heat flux, or heat transfer crisis (Figure 18).
The phenomenon responsible for this problem is the transition from annular boiling state to
misty/drop state. In the misty/drop state, the boiler wall is no longer covered with water. This
dryout causes the drastic fall in the waterside heat transfer coefficient.
Critical heat flux is dependant on operating pressure, steam quality, type of tube, tube diameter, flux
profiles and tube inclination. For a boiler design to be acceptable the critical heat flux for the
60
furnace walls must always be greater by a margin than the heat flux generated in the combustion
chamber.
Optimization of natural circulation design
The following are some of the main methods
used for natural circulation optimisation. All
methods lead to an increase in the driving
force:
1. Increase furnace height or elevate
steam drum at higher level.
2. Increase density in downcomer tubes
by
increasing
steam separation
efficiency in the steam drum, by
pumping feedwater to the steam drum
as sub-saturated liquid or by
minimizing the axial flow in the steam
drum.
3. Decrease density in riser tubes by
increasing temperature in lower
furnace.
Figure 18: Dryout occurring in an evaporator
tube. [1]
Special designs
There are some special applications of natural
circulation principle that are not currently
covered here, but can be found elsewhere on
the net (eg. http://www.steamesteem.com).
These specific boiler types are:
•
Natural circulation boilers with two or
more steam drums (Figure 19).
• Conservative vertical furnace boilers.
• Corner tube or Eckrohr boilers, which
received its name for having
downcomers in the corners of the
furnace.
Figure 19: Recovery boiler utilizing two steam
drums. [4]
61
Assisted or forced circulation boilers
In contrast to natural circulation boilers, forced circulation is based on pump-assisted internal
water/steam circulation. The circulation pump is the main difference between natural and forced
circulation boilers. In the most common forced circulation boiler type, the La Mont boiler, the
principles of forced circulation is basically the same as for natural circulation, except for the
circulation pump.
Thanks to the circulation pump, the operation pressure level of forced circulation boiler can be
slightly higher than a natural circulation boiler, but since the steam/water separation in the steam
drum is based on the density difference between steam and water, these boilers are not either
suitable for supercritical pressures (>221 bar). Practically the maximum operation pressure for a
forced circulation boiler is 190 bar and the pressure drop in the boiler is about 2-3 bar.
Principle of forced circulation
The water/steam circulation begins
from the feed water tank, from
where feed water is pumped. The
feedwater pump raises the pressure
of the feedwater to the wanted
boiler pressure. In practice, the final
steam pressure is below 190 bar, in
order to keep the steam steadily in
the subcritical region.
The feed water is then preheated in
the economizer almost up to the
boiling point of the water at the
current pressure.
The steam drum is usually the same
kind as those used in natural
circulation boilers.
Figure 20: Principle of forced/assisted circulation. Same
symbols used as in Figure 6, except for the circulation pump,
marked with an arrow.
In a forced/assisted circulation
boiler, the circulation pump (Figure
20) provides the driving force for
the steam/water circulation. Since the pump forces the circulation, the evaporator tubes can be built
in almost any position. Greater pressure losses can be tolerated and therefore the evaporator tubes in
a forced circulation boiler are cheaper and have a smaller diameter (compared to natural circulation
evaporator tubes).
The saturated water flows next from the steam drum through downcomer tubes to a mud drum
(header). There are usually a couple of downcomer tubes, which are unheated and situated outside
the boiler. The headers that distribute the water to the evaporator tubes are equipped with chokers
(flow limiters) for every wall tube in order to distribute the water as evenly as possible. The water
continues to the riser tubes, where it evaporates.
The steam is separated in the steam drum and continues through the superheaters, as in natural
circulation boilers.
62
This type of circulation is called forced circulation, due to the existence of a water circulation pump
in the circuit. The steam/water circulation is forced by the pump and does not rely on density
differences as in natural circulation.
Flow distribution between parallel riser
tubes
Smooth flow distribution from header to riser
tubes prevents riser tubes from overheating. In
forced circulation boilers (in this context oncethrough boilers and combined circulation
boilers belong to this group as well)
water/steam is pushed through evaporator
tubes with a pump. Pressure loss strongly
defines the water distribution between several
parallel-coupled tubes. The tubes with biggest
steam fraction (highest pressure loss) get thus
the least amount of water (i.e. not enough
cooling water).
It has been marked that a smooth water
Figure 21: Schematic of an orifice for water
distribution between tubes is easiest to practice
tubes
with orifices (chokes, flow limiters) situated in
inlet of each riser tube (Figure 21). They give
extra pressure loss in each tube and thus the proportional differences in flow losses between parallel
tubes become insignificant. Orifices are dimensioned separately for each riser tube to provide a
smooth distribution of flow between parallel riser tubes (evaporator tubes).
Another possibility is to place small diameter tubes as mouthpieces in each riser tube and thus
increase the pressure losses. However, tubes utilizing orifices is a more common practice.
Boilers types
La Mont boilers
The most usual type of forced circulation boilers is the La Mont type, named after an engineer who
developed this boiler type. In this type of boilers the pump forces the steam/water circulation. The
operational pressures remain below 190 bar because with higher pressures the share of the heat of
evaporation becomes too low. The wall tube direction arrangement is not limited for the La Mont
type. The pressure loss in wall tubes is 2-3 bar.
Applications for La Mont boilers:
•
•
Customized boilers, where the boiler dimensions are determined e.g. by the building where the
boiler will be placed.
Heat recovery steam generators (HRSGs) and boilers equipped with separate combustion
chambers
Controlled circulation boilers
The controlled circulation principle is also known as thermal, pump-assisted circulation. It has been
developed mainly in the USA and it is one kind of modification of La Mont boiler. In this type of
boilers the pump merely assists the steam/water circulation. The benefit of controlled circulation
63
boilers is the less need of pumping energy because natural circulation principle is partially used for
circulation. Controlled circulation boilers are used for high subcritical pressures up to 200 bar and
usually for relatively large boilers.
The advantages of forced circulation (FC) boilers are:
•
•
•
•
•
FC boilers can use tubes with smaller diameter than boilers based on natural circulation due
to the more efficient (pump-assisted) circulation.
FC boilers have a wide suitability range of power plant sizes.
An FC boiler gives also more freedom for placement of heat transfer surfaces and can be
designed in almost in any kind of position (thus forced circulation is very common in
HRSG:s, boilers in gas turbine based combined-cycle power plants).
FC boilers have a low circulation ratio (3-10).
Water circulation not reliable on density differences because circulation pump is taking care
of the circulation whenever the boiler is operated.
Forced circulation boilers have the following disadvantages compared to other circulation types:
•
•
•
•
•
•
•
•
•
•
FC boilers have restrictions regarding the placement of the circulation pump, since it has to
be placed vertically below the steam drum. Otherwise the saturated water could boil
(cavitate) in the circulation pump.
FC boilers have a higher internal electrical consumption. The circulation pump consumes
typically about 0.1-1.0 % of the electricity produced by the controlled circulation unit in
question.
FC boilers need a higher level of water quality than boilers based on natural circulation.
FC boilers require a mass flow rate of 1000-2000 kg/(m2s) for maximum pressure levels.
FC boilers are only suitable for subcritical pressure levels (practically for operation
pressures under 190-200 bar). This is due to the lack of density difference in supercritical
steam, which is the principle for the operation of the steam/water seperation in the steam
drum.
FC boilers require a circulation pump and flow limiting orifices, which increase the capital
cost of the boiler.
FC boilers are sensitive to pressure variations. Sudden pressure drops or build-ups causes
increased rate of evaporation and thus the steam drum water level will also rise. This can
lead to water passing into the superheater tubes and water circulation problems that lead to
tube damages.
FC boilers require control and regulation of the co-operation between the feed water pump
and circulation pump, which is difficult in controlled circulation units.
A steam drum is required, which is a very expensive part of the boiler.
Reliability of FC boilers is lower than that of natural circulation boilers, due to possible
clogging of orifices and failures in circulation pump operation.
Once-through boilers
A once-through (or universal pressure) boiler can be simplified as a long, externally heated tube
(Figure 22). There is no internal circulation in the boiler, thus the circulation ratio for once-through
boilers is 1.
64
In contrast to other water tube boiler types
(natural and controlled circulation), oncethrough boilers do not have a steam drum.
Thus, the length of the evaporator part (where
saturated water boils into steam) is not fixed
for once through boilers.
Once-through boilers are also called universal
pressure boilers because they are applicable for
all pressures and temperatures. However, oncethrough boilers are usually large sized boilers
with high subcritical or supercritical steam
pressure. A large modern power plant unit
(about 900 MWth) based on the once-through
design can be over 160 m high with a furnace
height of 100 m.
Q
Figure 22: Simplified once-through boiler
principle
The once through boiler type is the only boiler
type suited for supercritical pressures (nowadays they can reach 250-300 bars). The available
temperature range for once through type is currently 560-600 °C. Pressure losses can be as high as
40-50 bar.
Once-through boilers need advanced automation and control systems because of their relatively
small water/steam volume. They do not either have a buffer for capacity changes as other water
tube boiler types do.
Once-through boiler types
There are three main types of once through
boilers: Benson, Sulzer and Ramzin design.
Benson design
The simplest and most common design is the
Benson design (UK, 1922). In Benson boilers,
the point of complete evaporation (where all
the water has turned into steam) varies with the
capacity load of the boiler (Figure 23). The
temperature of the superheated steam is
regulated by the mass flow ratio of fuel and
water. The Benson-design is used in the
biggest power plants in Finland, e.g. Meri-Pori,
Haapavesi and IVO Inkoo.
Figure 23: Benson design once-through boiler.
Sulzer design
The Sulzer monotube boiler was invented in Switzerland by Gebrüder Sulzer Gmbh. The Sulzer
boiler uses a special pressure vessel, called Sulzer bottle, for separating water from steam (Figure
24). The steam is free from water after the bottle. Therefore the point of evaporation in a Sulzer
boiler is always at the bottle, and thus constant. Originally the bottle was used for separating
impurities (concentrated salts etc.) from the steam. Another typical feature for Sulzer type boilers is
the controlling the water flow of each tube outgoing from a certain header with separate orifices for
each tube.
65
Ramzin design
The Ramzin boiler is a Russian design, which
is known for the coil-like formation of the
evaporator tubes surrounding the furnace
(Figure 25). Due to the tilted and bended water
tubes the construction of Ramzin boilers is
complicated and thus expensive.
The tilted design of the furnace is nowadays
also used occasionally in Sulzer and Benson
design.
Spiral wall tubes
Once-through boilers use a special design on
water tubes. These are called spiral or rifled
wall tubes (Figure 26). The rifles in the tube Figure 24: Sulzer design once-through boiler.
increase the wall wetting, i.e. improve the The separation bottle is marked with an arrow.
contact between the tube wall and steam/water
mixture and thus improves the internal heat
transfer coefficient. The rifled wall tube is also
more resistant against dryouts. Due to the more
complex manufacture process of spiral tubes,
the spiral wall tube is more expensive than
regular smooth wall tubes.
Smooth wall tubes are used in tilted wall tube
design (like in Ramzin boilers).
Multiple pass design
In order to obtain the high mass flux necessary
for efficient tube cooling, the lower part of the
furnace can be divided into two sequential
water flow paths. These two parallel paths are
formed by altering first and second pass tubes
around the furnace.
Figure 25: Ramzin once-through boiler.
As illustrated in the picture (Figure 27), the
water from the economizer flows up the first
pass tubes to the outlet headers, where the
water is mixed and led to downcomers. From
the downcomers the water/steam mixture is led
to the second pass tubes, from where it is
collected and mixed in the second pass header.
The water/steam mixture then flows to the
headers for the 3rd pass tubes, which the rest of
the evaporator consists of.
Using two passes, the lower part of the furnace
has effectively twice the water mass flow of
the upper part. Thanks to the headers, the
Figure 26: Sketch of a spiral wall tube. [1]
66
temperature differences between individual
tubes are decreased.
Once-through (OT) boilers have the following
advantages compared to other circulation
types:
•
•
•
•
•
•
OT boilers can use tubes with smaller
diameter than boilers based on a steam
drum due to their lack of internal
circulation.
OT boilers have a secure external water
circulation (relies on process feed water
pump)
Spiral (rifled) water wall tubes are more
resistant against dryouts than smooth
evaporator tubes.
OT boilers have a no internal
circulation (circulation ratio = 1) and Figure 27: Multiple pass furnace design. [7]
thus there are no regulation or design
needed for the internal circulation.
The OT boiler is the only boiler able to operate at supercritical pressures, since there is no
density dependant steam separation needed (the Sulzer-bottle is not used for supercritical
steam values).
OT boilers do not use a steam drum, which decreases boiler expenses.
Once-through (OT) boilers have the following disadvantages compared to other circulation types:
•
•
•
•
•
OT boilers require high level of water control, since the steam/water goes directly through
the boiler and into the turbine.
OT boilers require complicated regulation control, due to small water/steam volume (no
buffer for capacity changes), lack of steam drum, and the fact that the fuel,air and water
mass flows are directly proportional to the power output of the boiler.
OT boilers require a large mass flow rate of 2000-3000 kg/(m2s) in furnace wall tubes.
Spiral wall tubes are more expensive than smooth wall tubes due to a more complicated
manufacture process.
OT boilers have no capacity buffer, due to the lack of a steam drum and their once-through
nature.
Operation
The basic difference between once through boiler types has traditionally been the point of total
evaporation in tubing. However, supercritical pressure range operation removes this clear difference
between water and steam states, and thus both Sulzer and Benson boilers are similarly operated in
supercritical pressures.
However, the development has led to constant point of evaporation also for Benson boilers (thanks
to improved process control) and nowadays the operational behaviour of once through boiler is very
67
similar. Today the biggest operational differences between Benson and Sulzer types are the control
system and heat-up procedures.
Overall, all once through boilers need certain special arrangements for heat-up procedure and low
capacity operation.
Manufacture and use of once-though boilers
Benson boilers are nowadays mostly manufactured by companies that belong to the Babcock group
(Deutsche Babcock, etc.). Sulzer boilers are mostly manufactured (by license) by ABB Combustion
Engineering, Mitsubishi, EVT, Andritz, etc. Ramzin boilers can be found in Russia.
Most of the new capacity of conventional steam power plants is based on once through principle,
because it allows higher steam pressures and thus higher electricity efficiency.
A Sulzer boiler can be found e.g. at Naantali power plant in southwestern Finland (also at Mussalo
power plant). The boiler of the Meri-Pori power plant, situated in western Finland, is based on a
Benson type. Also Inkoo and Haapavesi power plants use Benson design boilers.
Combined circulation boilers
This boiler type is a combination of controlled
circulation boilers and once-through boilers.
Combined circulation (once-through with
superimposed recirculation) boilers can be
used for both subcritical and supercritical
steam pressure operation. Figure 28 shows a
simplified principle of the combined
circulation.
When the firing rate is between 60 and 100 %,
the boiler operates as a once-through boiler. At
lower than 60 % capacity load, combined
circulation boilers operate as forced circulation
boilers in idea to maintain adequate
water/steam flow in wall tubes.
The biggest advantage of combined circulation
type boilers is reduced demand of pump energy
Figure 28: Simplified principle of combined
because the operation mode changes depending
circulation.
on the capacity load. Main disadvantages are
the troublesome co-operation between feed
water pump and circulation pump and also the high level needed for water treatment (as needed for
once through boilers).
The main manufacturer of this type of boilers is ABB Combustion Engineering and other
companies with a license from ABB CE. However, Mitsubishi is practically the only license user
company outside USA.
68
References
1.
Vakkilainen E. Lecture slides and material on steam boiler technology. 2001.
2.
Höyrytys Oy. Web page, read September 2003. http://www.hoyrytys.fi/
3.
Ahonen V. Höyrytekniikka II. Otakustantamo, Espoo. 1978
4.
Andritz. Recovery Boiler Operation Manual, Ahlstrom Machinery Corporation 1999.
5.
Huhtinen M., Kettunen A., Nurmiainen P., Pakkanen H. Höyrykattilatekniikka.
Painatuskeskus, Helsinki. 1994.
6.
Pictures supplied by Andritz. http://www.andritz.com/
7.
Babcock & Wilcox. Supercritical (Once Through) Boiler Technology. PDF-file, read
October 2001. http://www.babcock.com/pgg/tt/pdf/BR-1658.pdf
69
Feedwater and Steam System Components
STEAM BOILER TECHNOLOGY – Feedwater and Steam System Components
Table of contents
Overview............................................................................................................................................73
Steam drum ........................................................................................................................................73
Steam drum principle .....................................................................................................................74
Steam separation ............................................................................................................................75
Steam purity and quality ................................................................................................................75
Steam quality..............................................................................................................................76
Steam purity ...............................................................................................................................76
Continuous blowdown ...................................................................................................................76
Steam drum placement...................................................................................................................76
Other aspects of steam drum design ..............................................................................................77
Feedwater system...............................................................................................................................77
Feedwater tank ...............................................................................................................................78
Feedwater pump.............................................................................................................................78
Feedwater heaters...........................................................................................................................79
Steam temperature control .................................................................................................................80
Dolezahl attemperator ....................................................................................................................80
Spray water group ..........................................................................................................................81
Water atomizer types .....................................................................................................................81
References..........................................................................................................................................82
72
Overview
A steam boiler plant consists of a number of miscellaneous machinery in addition to the
constructions, pressurized steam system and electrical equipment. These machinery parts are called
auxiliary equipment, because they aid the operation of the main equipment.
The feedwater and steam system components are responsible for the steam/water flow through the
boiler. The heat exchanger surfaces (waterwalls in the furnace, superheater and economizers) are
explained in the chapter about heat exchanger surfaces, while this chapter concentrates on the
auxiliary equipment for the feedwater and steam system. This chapter uses graphics and photos of
an Andritz recovery boiler (manufactured by Foster Wheeler), which is the same boiler that was
presented in the chapters on modern boiler types and natural circulation design (Figure 1). Although
this particular boiler is based on natural circulation, the components presented here are similar in
most boiler designs. [1]
Figure 1: The feedwater circulation components of the recovery boiler using natural circulation.
[2]
Steam drum
The steam drum is a key component in natural, forced and combined circulation boilers. The
functions of a steam drum in a subcritical boiler are:
•
•
•
•
Mix fresh feedwater with the circulating boiler water.
Supply circulating water to the evaporator through the downcomers.
Receive water/steam mixture from risers.
Separate water and steam.
73
•
•
•
•
•
Remove impurities.
Control water chemical balance by chemical feed and continuous blowdown.
Supply saturated steam
Store water for load changes (usually not a significant water storage)
Act as a reference point for feedwater control
Once-through boilers do not use a steam drum. [2] [3]
Steam drum principle
The steam drum principle is visualized in Figure 2. Feedwater from the economizer enters the steam
drum. The water is routed through the steam drum sparger nozzles, directed towards the bottom of
the drum and then through the downcomers to the supply headers.
This recovery boiler operates by natural circulation. This means that the difference in specific
gravity between the downcoming water and uprising water / vapor mixture in the furnace tubes
induces the water circulation. Drum internals help to separate the steam from the water. The larger
the drum diameter, the more efficient is the separation. The dimensioning of a steam drum is mostly
based on previous experiences. A drawing of a steam drum cross-section is shown in Figure 3.
Figure 2: Steam drum in the natural
circulation process. [2]
Figure 3: The steam drum cross-section. [2]
Water and steam in a steam drum travel in opposite directions. The water leaves the bottom of the
drum to the downcomers and the steam exits the top of the drum to the superheaters.
Normal water level is below the centerline of the steam drum and the residence time is normally
between 5 and 20 seconds.
A basic feature for steam drum design is the load rate, which is based on previous experiences. It is
normally defined as the produced amount of steam (m3/h) divided by the volume of the steam drum
74
(m3). Calculated from the residence time in the steam drum, the volumetric load rate can be about
200 for a residence time of almost 20 seconds in the pressure of about 80 bar. The volumetric load
rate increases when the pressure decreases having its maximum value of about 800. As can be
thought from the units, the size of the steam drum can be calculated based on these values.
Steam separation
The steam/water separation in the steam drum
is also based on the density difference of water
and steam. It is important to have a steady and
even flow of water/steam mixture to the steam
drum. This is often realized with a manifold
(header) designed for partitioning of the flow.
There are different kinds of devices for water
separation such as plate baffles for changing
the flow direction, separators based on
centrifugal forces (cyclones) and also steam
purifiers like screen dryers (banks of screens)
and washers. . The separation is usually carried
out in several stages. Common separation
stages are primary separation, secondary
separation and drying. Figure 4 shows a
drawing of the steam drum and its steam
separators.
One typical dryer construction is a compact
package of corrugated or bent plates where the
water/steam mixture has to travel a long way
through the dryer. One other possibility is to
use wire mesh as a material for dryer. The
design of a dryer is a compromise of efficiency
and drain ability - at the same time the dryer
should survive its lifetime with no or minor
maintenance. A typical operational problem
related to steam dryers is the deposition of
impurities on the dryer material and especially
on the free area of the dryer (holes).
Figure 4: 3D-schematics of a steam drum and
separators [2].
Figure 5: Steam separators enlarged (cyclone
and demister) [2].
In this particular steam drum, the primary separators are cyclones (Figure 5). These enable the
rising steam/water mixture to swirl, which causes the heavier water to drop out of the cyclones and
thus let the lighter steam rise above and out of the cyclones. The steam, which is virtually free of
moisture at this point, continues on through the secondary separators (dryers), which are called
demisters. Demisters are bundles of screens that consist of many layers of tightly bundled wire
mesh. Demisters remove and capture any remaining droplets that may have passed through the
cyclones. The water that condenses from the demisters is re-circulated through the boiler’s
circulation process. [2] [3]
Steam purity and quality
Impurities in steam causes deposits on the inside surface of the tubes. This impurity deposit changes
the heat transfer rate of the tubes and causes the superheater to overheat (CO3 and SO4 are most
75
harmful). The turbine blades are also sensitive for impurities (Na+ and K are most harmful). The
most important properties of steam regarding impurities are:
•
•
Steam quality, Water content: percent by weight of dry steam or moisture in the mixture
Solid contents, Steam purity: parts per million of solids impurity in the steam
Steam quality
There are salts dissolved in feedwater that need to be prevented from entering the superheater and
thereby into the turbine. Depending on the amount of dissolved salt, some impurity deposition can
occur on the inner surfaces of the turbine or on the inner surface of superheater tubes as well. Steam
cannot contain solids (due to its gaseous form), and therefore the water content of steam defines the
possible level of impurities. The water content after the evaporator (before superheaters) should be
<< 0.01 %-wt (percents by weight) to avoid impurity deposition on the inner tube surfaces. If the
boiler in question is a high subcritical-pressure or supercritical boiler, the requirements of the steam
purity are higher (measured in parts per billion).
Steam purity
The solid contents are a measure of solid particles (impurities) of the steam. The boiler water
impurity concentration, solid contents after the steam drum and moisture content after the steam
drum are directly connected: e.g. If the boiler water impurity concentration is 500 ppm and the
moisture level in the steam (after the boiler) 0.1 %, the solids content in the steam (after the boiler)
is 500 ppm * 0.1 % = 0.5 ppm.
Continuous blowdown
When water is circulated within the steam
generating circuits, large amounts are recirculated, steam leaves the drum and
feedwater is added to replace the exiting steam.
This causes the concentration of solid
impurities to build up.
To continuously remove the cumulative
amounts of concentrated solids, a sparger the
length of the drum is situated below the
centerline. The continuous blowdown piping is
used to blow the accumulations out of the
drum and into the "continuous blowdown
tank".
Figure 6: Blowdown piping. [2]
Sampling is done to properly set the rate of blowdown based upon allowable amounts of identified
solids. A photograph of the blowdown piping in the recovery boiler is shown in Figure 6.
Steam drum placement
In natural circulation boilers the steam drum should be placed as high as possible in the boiler room
because the height difference between the water level in the steam drum and the point where water
begins its evaporation in the boiler tubes, defines the driving force of the circuit. The steam drum is
normally placed above the boiler. Figure 7 and Figure 8 shows photos from the installation process
of the recovery boiler steam drum.
76
For assisted/forced and controlled circulation boilers the steam drum can be placed more freely,
because their circulation is not depending on the place of the steam drum (pump-based circulation).
This is a reason why assisted/forced and controlled circulation boilers have been preferred in e.g.
boiler modernizations, when the biggest problem is usually lack of space.
Figure 7: Installation of steam drum. [2]
Figure 8: Steam drum installation. [2]
Other aspects of steam drum design
Inside the steam drum there are also different kinds of auxiliary devices for smooth operation of the
drum.
The ends of feedwater pipes are placed below the drum water level and must be arranged so that the
cold-water flow will not touch directly the shell of the drum to avoid thermal stresses.
The water quality is maintained on one hand by chemical feed lines, which bring water treatment
chemicals into the drum, and on the other hand by blowdown pipes which remove certain portion of
the drum water continuously or at regular intervals.
A dry-box can be placed before the removal pipe for steam. It consists of a holed or cone-shaped
plate construction allowing a smooth flow distribution to a steam dryer.
Feedwater system
This chapter describes the feedwater system part of the
power plant process prior the boiler, i.e. between the
condenser (after turbine) and the economizer.
The feedwater system supplies proper feedwater amount
for the boiler at all loads rates. The parameters of the
feedwater are temperature, pressure and quality. The
feedwater system supplies also spray water for spray
water groups in superheaters and reheaters.
The feedwater system consists of a feedwater tank,
feedwater pump(s) and (if needed) high-pressure water
preheaters.
Figure 9: Feedwater system. [2]
77
Feedwater tank
A boiler should have as large feedwater reserve
as is needed for safe shutdown of the boiler. The
heat absorbed by the steam boiler should be
taken into account when dimensioning the
feedwater reserve (feedwater tank). The exact
rules for the choice of feedwater reserve are
included in respective standards. The residence
time for feedwater is 20 min in most standards,
which depends on fuel and firing method. Thus
a fluidized bed boiler, which has as a large heat
storage capacity in its bed, requires a larger
feedwater tank than a gasified boiler. The
feedwater tank of the recovery boiler is shown in
Figure 9, Figure 10 and Figure 11. [4]
Figure 10: Feedwater tank drawing
Condensate (from turbine), fully demineralized
(purified) makeup water and low-pressure steam
are the normal inputs to the feedwater tank. All
the inputs are fed to the deaerator, which
handles the gas removal and chemical feeding of
the feedwater mix before it enters the feedwater
tank. The feedwater tank acts as an open-type
heat exchanger, since the fluids exchanging heat
are mixed before exiting the tank.
Figure 11: Feedwater tank transportation.
The function of the low-pressure steam (usually
3-6 bars) is to heat the feedwater and remove
gas (O2 and CO2). The steam-gas mixture continues from the deaerator to a specific condenser,
where the heat from low-pressure steam is recovered. [2] [5]
Feedwater pump
The feedwater pumps lead feedwater from the
feedwater tank to the boiler and pressurize the
water to the boiler pressure level. Regulations
allow using only one feedwater pump for (very)
small boilers, whereas for bigger units at least
two feedwater pumps are needed.
Usually there are two similar and parallelconnected feedwater pumps with enough
individual power to singularly supply the
feedwater needs of the boiler, in case one was
damaged. A photo of a feedwater pump being
manufactured is shown in Figure 12.
Figure 12: Feedwater pump manufacture. [7]
Feedwater pumps are usually over dimensioned in relation to mass flow rate of steam in order to
have enough reserve capacity for blowdown water and soot blowing steam etc.
78
Smaller feedwater pumps are always electric powered, while feedwater pumps for bigger capacity
may be steam powered.
Normally the feedwater tank is placed above
the feedwater pumps in the boiler room. The
difference in altitudes between feedwater
pumps and feedwater tank is defined by a
parameter called NPSH (net positive suction
head). It is related to the cavitation of
feedwater pumps and it defines the minimum
altitude difference between feedwater pump
and feedwater tank.
The feedwater pump head [N/m2] can be
calculated according to the following equation:
Steam drum
pp
Hgeod
Feedwater tank
Boiler
Back-pass
superheater
Hs
∆p pump = p p + ∆p flow + ρgH geod
(1)
Feedwater
pump
where pp is the maximum operating pressure at
the steam drum, ∆pflow is the loss in the
feedwater piping and economizer, and ρgHgeod
is the pressure required to overcome the height Figure 13: Feedwater pump head calculation.
difference between feedwater tank lower level
and drum level (visualized in Figure 13). [6]
Feedwater heaters
Feedwater heaters heat the feedwater up before
entering the economizer of the boiler, using
low-pressure turbine exhaust steam. There are
two types of feedwater heaters in power plant
processes: high-pressure (HP) and lowpressure (LP) feedwater heaters. Of these, the
HP feedwater heaters are situated after the
feedwater pump (before the economizer) in the
power plant process. LP feedwater heaters are
situated between condenser and feedwater tank
(deaerator), before the feedwater pump in the
process. High-pressure feedwater heaters are
also called closed-type feedwater heaters since
fluids are not mixed in this type of heat
exchanger. Normal construction of HP and LP
feedwater heaters is a shell-and-tube heat
exchanger - feedwater flows inside the tubes
and steam outside the tubes (on shell side). A
photo of high pressure feedwater heaters is
shown in Figure 14. In a large conventional
power plant the typical arrangement of
feedwater heaters is a block of closed-type
(LP) feedwater heaters and a block of HP feed-
Figure 14: HP feedwater heaters installed at
Alholmens Kraft.[8]
79
water heaters after the feedwater pump in the process. The typical number of LP feedwater heaters
in a large power plant is 3-4 and the number of HP feedwater heaters 3-5, respectively.
The procedure for optimal placement of HP feedwater heaters begins by defining the enthalpy
difference between feedwater pump outlet and economizer inlet. This enthalpy difference is then
divided by the amount of HP feedwater heaters and the result is the enthalpy rise in every HP
feedwater heater stage.
Steam temperature control
Steam consumers (e.g. turbine, industrial
process) require relatively constant steam
temperatures (±5°C); therefore means of boiler
steam temperature control is required.
Steam temperature control system helps
maintaining high turbine efficiency, and turbine
material temperatures at a reasonable level at
boiler load changes. An uncontrolled convective
superheater would cause a rise in steam
temperature as the steam output increases.
Methods for steam temperature control are:
•
•
•
•
•
•
Figure 15: Attemperator on recovery boiler. [2]
Water spraying superheated steam
Steam bypass (superheater bypass)
Flue gas bypass
Flue gas re-circulation
Heat exchanger system
Firing system adjustment
Dolezahl attemperator
The Dolezahl attemperator (or simply attemperator or de-superheater) is a steam temperature
control system that uses condensate as spray water. The location of the attemperator on the recovery
boiler is shown in Figure 1 and Figure 15.
In a Dolezahl attemperator system saturated
steam from steam drum is lead to a condenser
that is cooled by feedwater (Figure 16).
Condensate (saturated water) continues from
condenser to spray water groups (injectors). The
injectors spray water into the steam and thus
reduce the temperature of the superheated steam.
Injectors are usually located between
superheater stages.
The main advantage of Dolezahl attemperators
is the high quality of spray water since the
impurities do not follow with the steam flow
from the steam drum. Complexity (condenser
Figure 16: Dolezahl condenser on the recovery
boiler. [2]
80
and tubing) and thus expensiveness is the biggest disadvantage of Dolezahl attemperator systems.
Nowadays Dolezahl attemperators are mostly used in special boiler applications.
Spray water group
Water spraying the steam flow is the most common method for live steam temperature control.
Main advantages of water spraying-based temperature control are the speed and effectivity of the
regulation. This makes their use possible in large-scale boilers. It can be used for reheat steam
temperature control as well, but usually reheat steam temperature control is performed by
combining water spraying with some other method (e.g. flue gas bypass).
The main function of spray water group is to reduce steam temperature by injecting water into
steam flow when needed. It is also used to prevent superheater tubes against excessive temperature
rise (too much superheating), which could lead to superheater tube damage. The sprayed water can
be feedwater (normally) or condensate (condensate steam from boiler process). The system using
condensate is called an attemperator.
Water atomizer types
The two existing types of steam coolers are categorized by their way of cooling water atomization:
•
•
Atomizer based on pressurized water flow
Atomization by steam flow
The atomizer principle based on pressurized water has many possibilities of water spraying
directions and nozzle types. This type of system is applicable when variations in steam flow are not
large and the temperature difference between incoming steam to be cooled and outgoing already
cooled steam is big enough.
Steam based atomizer uses steam as medium for atomization. Medium and low-pressure steam is
also used as sprayed matter in order to get more effective cooling. The atomization steam flow is
normally constant, being about 20 % of the cooling water flow.
The choice of spray water atomizer type is based on needed operation range (here needed minimum
operational load) and is usually very much case-specific.
81
References
1.
Vakkilainen E. Lecture slides and material on steam boiler technology, 2001
2.
Andritz. Recovery Boiler Operation Manual, Ahlstrom Machinery Corporation 1999.
3.
Alvarez H. Energiteknik del 1 and Energiteknik del 2. Studentlitteratur, Lund. 1990.
4.
Combustion Engineering. Combustion: Fossil power systems. 3rd ed. Windsor. 1981.
5.
El-Wakil M. M. Powerplant technology. McGraw Hill, New York. 1984.
6.
Huhtinen M., Kettunen A., Nurmiainen P., Pakkanen H. ”Höyrykattilatekniikka”.
Painatuskeskus. Helsinki, 1994.
7.
Sulzer. Printed brochure.
8.
Photograph by Rintala T., Alholmens Kraft.
82
Combustion Process Equipment
Esa Vakkilainen, Lasse Harja, Sebastian Teir
STEAM BOILER TECHNOLOGY – Combustion Process Equipment
Table of contents
Introduction........................................................................................................................................85
Combustion system ............................................................................................................................85
Burners ...........................................................................................................................................86
Burner arrangement....................................................................................................................86
Single wall firing....................................................................................................................86
Front and back wall firing......................................................................................................86
Corner or tangential firing......................................................................................................87
Roof firing..............................................................................................................................87
Burner design .............................................................................................................................88
Combustion of solids .....................................................................................................................88
Pulverized Coal Firing (PCF) ....................................................................................................89
Grate firing.................................................................................................................................89
Stationary grates.....................................................................................................................90
Traveling grate .......................................................................................................................90
Mechanical grates ..................................................................................................................90
Spreader design ......................................................................................................................91
Mechanical grate for biofuels ................................................................................................91
Roll grate................................................................................................................................92
Fans and blowers................................................................................................................................92
Fan categories ................................................................................................................................92
Fan selection ..................................................................................................................................93
Fuel handling equipment....................................................................................................................94
Coal feeders....................................................................................................................................94
Crushers .........................................................................................................................................94
Pulverizers......................................................................................................................................94
Ash handling equipment ....................................................................................................................95
Ash collection points......................................................................................................................95
Ash conveyors................................................................................................................................96
Electrostatic precipitator ................................................................................................................96
Soot blowing ..................................................................................................................................97
References..........................................................................................................................................99
84
Introduction
A steam boiler plant consists of a number of miscellaneous machinery in addition to the
constructions, pressurized steam system and electrical equipment. These machinery parts are called
auxiliary equipment, because they aid the operation of the main equipment. This chapter focuses on
the auxiliary equipments that manage the combustion process.
Auxiliary equipments dealing with the combustion process in a boiler plant are:
•
•
•
•
•
Hoppers, silos, crushers
(Figure 1)
Burners (Figure 2)
Fans (Figure 3), ducts,
dampers
Air heaters
Sootblowers, conveyors
To be able to design and operate
a steam boiler one needs to
understand the functions of the
various pieces of equipment. For
steam boiler design it is more
important to understand the
purpose and limitations of each Figure 1: Simplified drawing of the fuel feeding system of a PCF
piece of equipment than to be
boiler. [1]
able to design this equipment.
Therefore the design of e.g. pumps, blowers, fans and various flue gas cleaning devices is only
briefly presented. Air preheaters are discussed in the chapters about heat exchanger surfaces.
Figure 2: Gas burner. [2]
Figure 3: Air fan. [2]
Combustion system
The choice of combustion system in a boiler depends on economical factors and required emissions.
There are several types of firing fuels in a boiler. These can be divided into two main methods of
combustion:
85
•
Combustion using a burner
o Single burner (shell and tube boilers, package boilers)
o Arrangements of several burners in a furnace (large oil and gas fired boilers, PCF
boilers)
o Cyclone firing
•
Burning in suspension
o Grate firing
o Fluidized bed combustion (BFB and CFB boilers)
o Chemical recovery boilers
Fluidized bed combustion, cyclone firing and recovery boilers are presented in other chapters of this
book.
Burners
Burners are devices, which combust liquids or gases by continuously feeding air and fuel to a
nozzle, where they are mixed and combusted, producing a flame. Burners can also be used to fire
solids that have been pulverized. Burners can be divided into subcategories based on e.g. fuel air
mixing:
•
•
•
Diffusion burners: Fuel and air are mixed by molecular diffusion. Thus the burning rate is
controlled by diffusion.
Premixed burners: Fuel and air are partially mixed before the burner. Typically the air to
fuel ratio is much lower than the stoichiometric ratio. The reason for premixing is to
increase combustion efficiency and decrease combustion time. Premixed burners are used
when burning low calorific fuels e.g. lignite and peat.
Kinetically controlled burners: Fuel and air mixing is controlled by aerodynamic and
turbulence forces. The combustion is controlled purely by the kinetics of the combustion
reaction.
Burner arrangement
The larger the required capacity is for a single burner, the more difficult it is to design. Instead,
when very large boilers are designed, it is more advantageous to use many small burners
simultaneously.
Single wall firing
The most typical burner arrangement for smaller boilers is the single wall arrangement, where all
burners are placed on one wall. Because of reduced layout and piping costs this arrangement is
more economical than the more complex arrangements. The most typical arrangement is front wall
arrangement, as shown in Figure 4. The flames from front wall burners can in large boilers form an
almost continuous sheet of flames. Overfire air is used in modern installations to control NOx.
Front and back wall firing
When more capacity is required, burners are placed both on the front and back wall (Figure 5 and
Figure 6). A horizontal spacing of 1.5 – 2.5 m and vertical spacing of 2 – 4 m is the common
arrangement. Cell burners are similar to wall-fired burners, except that cell burners are arranged in
closely spaced burner pairs.
86
Figure 4: Oil/gas boiler with front wall burner
arrangement. [3]
Figure 5: Front and back wall burner
arrangement with overfire air. [1]
Corner or tangential firing
Another option is to place the burners in all four walls. The disadvantage of this is that the flames
hit each other easily, leading to unstable combustion. An improved arrangement is to use corner
firing, which increases mixing and facilitates turn-down (Figure 6). Corner firing is used especially
in large coal fired utility boilers. Corner firing arrangement forms a continuous swirl of flames
which enhances the mixing of fuel and air (Figure 7). Tangentially fired boilers have a column of
alternating coal and air nozzles in each corner of the boiler with wind boxes running behind each.
Figure 6: Wall fired versus corner fired furnace. [1]
Figure 7: Combustion in a corner fired
furnace. [1]
Roof firing
Low grade fuels such as lignite and sulfite liquor require long combustion time. Their adiabatic
combustion temperature is low requiring refractory lined combustion chamber. A typical burner
application is roof or downshot firing, where separate combustion chamber is built alongside the
furnace.
87
Burner design
One of the main difficulties in burner design is choosing a proper swirl of the flames. Controlling
the rotational speed of the gas mixture from the burner affects upon:
•
•
•
•
•
the form of flame
the flame stability
the temperature
emissions (NOx)
the formation of soot
The main goal in oil and gas burner design has in the recent years been to design a burner that
operates stably with a low formation level of NOx. This is normally achieved using air staging.
Reported NOx emission levels are 80 - 120 ppm for oil and 20 - 40 ppm for natural gas.
The main parts of burners, designed to minimize the formation of NOx, can be seen in Figure 8 and
Figure 9. Ignition is achieved with a centrally fitted oil burner. Flame condition can be overlooked
using a flame monitor on a side mounted tube. Primary air is inserted from the centre with the fuel
(coal dust, oil or gas). Secondary air is drawn from an air duct that surrounds the fuel channel. Axial
air flow speeds in the burners are typically in the range of 30 – 50 m/s. The burner is mounted
inside the boiler wall. Wall tubes are bent to form an opening of suitable size (Figure 2).
Figure 8: Schematics of a Low-NOx burner.
[1]
Figure 9: Schematics of an advanced Low-NOx
burner. [1]
Combustion of solids
Solid fuels fired in industrial and utility boilers include coal (bituminous, anthracite, and lignite or
brown coal), paper sludge, biomass (e.g. bagasse, bark, wood), peat, RDF (Refuse Derived Fuel),
and municipal waste.
One of the key issues in fuel quality is the heating value. The heating value depends on the fixed
carbon content of the fuels.
Solid fuels can be divided into high grade fuel (e.g. bituminous coal) and low grade fuel (e.g. peat
and bark). The most typical firing methods of solid fuels are grate firing, cyclone firing, pulverized
88
firing, and fluidized bed firing. Cyclone firing is not common anymore in new boilers due to their
high level of NOx formation.
Coal is most widely used fuel in utility boilers. Earlier coal was burned as lumps, but most widely
coal is burned as about 0,1 mm particle. Coal quality (LHV) is decreasing as better coal reserves are
exhausted. This means that sulfur and ash contents in coal are increasing. With lower grade coals
the boiler fouling is becoming more problematic.
Pulverized Coal Firing (PCF)
Coal is mostly burned in pulverized coal
firing (PCF), where coal is grinded into a fine
particle size and fired in burners, similar to oil
and gas burners. Pulverized coal burns like
gas and, therefore, fires are easily lighted and
controlled. The main advantage of pulverized
firing is the high heat release rates and high
temperatures that can be achieved. Pulverized
firing can be used with very large unit sizes
(up to 1000 MWth). The main disadvantage
in PCF is that additional units for SOx and
NOx control are usually required. Reported
NOx emission levels are 100 - 200 ppm for
bituminous coal. [4]
Corner PFC burners have rather complicated
construction (Figure 6 and Figure 10). Air is
inserted through a windbox and the airflow is
controlled with dampers. Coal particles are
introduced through nozzles with primary air.
Air and pulverized coal ports placed Figure 10: Variations of the arrangement of corner
fired PCF burners. [1]
sequentially. Typically, oil is used only for
the startup.
Wall firing of coal is similar to oil and gas firing. Tertiary or over-fire air (Figure 5) is used in the
modern burners to control combustion and lower NOx,
Grate firing
Grate firing is the oldest type of firing and was the main combustion technique up till 1930’s when
PFC started to gain hold. In grate or stoker fired boilers, the combustion of solid fuel occurs in a
bed at the bottom of the furnace. Primary air is forced through grate and burning bed. Bed burning
rate controls combustion process. The benefit of grate firing is that all forms of solid fuel can be
fired including crushed coal. Even low grade fuels such as peat and bark can be fired. The main
disadvantage of grate firing is the slow change in firing rate. This is because there is relatively large
amount of unburned fuel all times at the grate.
Numerous different applications of grate or stoker firing systems exist for burning of different solid
fuels. In all cases, the fuel burns on a grate through which some or all the air for combustion passes.
The main constructional difference that grates can be divided into is stationary grates and moving
(traveling or mechanical) grates.
89
Stationary grates
Stationary grates, such as inclined grates
(Figure 11), are more common in small
boilers. This was the first grate type.
Stationary grates make use of gravity to
move the fuel. This requires 30–50° of
horizontal
inclination
[5].
The
inclination of the grate depends on the
fuel and its ability to flow during
combustion. The inclination can change
at different locations of the grate. It is
typically higher at the upper end of the
grate. To complete the burning of fuel,
many inclined grates have a small
horizontal grate after the inclined
section. This section is called the dump
grate.
Traveling grate
Instead of gravitation, fuel can be
transported by moving belt. This type of
grate is called a traveling grate. The
traveling grate has solid elements joined
to a chain, which moves horizontally
and transports fuel. Fuel is commonly
fed with a spreader onto the grate.
Changing the rate of fuel addition
changes the fuel layer thickness. For
coal, a suitable thickness is 10–20 cm,
and for wood it is 30–90 cm [5]. The
speed of the grate is chosen such that the
combustion can be completed within the
grate. The combustion is often
intensified by placing refractory to the
walls. The grate is cooled by the
primary air. Secondary and tertiary air
jets are often employed to control
burning.
Figure 11: Stationary, inclined grate.
Mechanical grates
Figure 12: Mechanical grate. [3]
Larger grates (Figure 12) contain
moving parts and are equipped with
automatic fuel feed and ash removal.
Mechanical grates are almost always inclined. Grate pieces can be mechanically moved horizontally
back and forward to facilitate bed movement. A mechanical inclined grate therefore does not have
as deep an inclining angle as the stationary grate. A suitable angle is 15° [5]. Regulating the
moving speed of fuel on the grate is possible by changing the speed of the grate. The speed can be
different at different sections of the grate. A large industrial mechanical grate is seen in Figure 12.
The fuel is fed from the right, and the moving grate transports the fuel to the left. The ash ends at a
dump grate.
90
A mechanical grate is one of the most typical grates for incinerating municipal waste. Mechanical
grates were also used for biomass firing, before fluidized bed boilers became common.
In a step grate, the step construction is made of cast iron grate bars. Air is horizontally introduced
between the grate plates. The most famous ‘brand’ of mechanical inclined step grates has been the
Kablitz grate.
Spreader design
Spreader firing used to be the most widely
used coal burning method. The spreader
(Figure 13) consists of a silo from which
the fuel is mechanically removed and
thrown into the ignited furnace by a
mechanical spreader. The spreader stoker
has the following parts that regulate the
fuel feed (Figure 13):
1. Rotating element for fuel rate
setting.
2. Spreader element, which throws the
fuel horizontally and with high
velocity into the furnace.
3. After being devolatilized and
partially combusted, fuel particles
land on the surface of the grate,
typically a traveling grate.
Figure 13: Spreader design.
Mechanical grate for biofuels
Wärtsilä has a special grate design,
patented as the BioGrateTM, which can be
described as a rotating conical grate. This
grate designed for optimal combustion of
biomass fuel with a moisture content as
high as 65%. The BioGrate is ideal for
burning wet wood residue from sawmills
and other wood processing plants. This
combustion technology is already in use in
70 plants and saw mills over the world.
The output of the BioGrate boiler plants
can be designed from 1 MW up to 10 MW
In the BioGrate system, the fuel is fed onto
the centre of a circular, conical shaped Figure 14: BioGrateTM - a rotating conical grate. [6]
grate from below (Figure 14). The grate is
divided into concentric rings with alternate
rings rotating and the rings in between remaining stationary. Alternate rotating rings are pushed
hydraulically clockwise or anti-clockwise respectively. This design distributes the fuel evenly over
the entire grate with the burning fuel forming an even layer of the required thickness.
91
The water content of the wet fuel in the centre of the grate evaporates rapidly due to the heat of the
surrounding burning fuel and thermal radiation from the specially formed brick walls. Gasification
and visible combustion of the gases and solid carbon take place as the fuel moves to the periphery
of the circular grate. At the edge of the grate ash falls into a water-filled ash basin underneath the
grate.
A key issue in highly efficient, low-emission
combustion of biofuels is combustion air
management. The primary air for combustion
and the recirculation flue gas where
applicable, are fed from underneath the grate
and penetrate the fuel through slots in the
concentric rings. Secondary air, and tertiary
air if used, is fed above the grate directly into
the flame. Air distribution is controlled by
dampers and speed-controlled fans to ensure
low emissions of NOx and CO with a wide
range of different fuels. [6]
Roll grate
Another type of grate is the roll grate (Figure
15). Instead of a stationary surface, the grate
consists of large rolls. These mix bed
efficiently. Even though roll grates are
usually built inclined, they can be built
horizontally. Roll grates are used especially
in municipal waste incineration.
Figure 15: Roll grate. [3]
Fans and blowers
In steam boiler plants, fans supply primary and secondary air to the furnace. The air is primarily
used for combustion of fuels, but can also be utilized in pneumatic transport of fuels and other solid
materials to the furnace. The air fans regulate the oxygen content in the combustion.
Fan categories
The four fan categories for a boiler are forced draft, primary air, induced draft and gas-recirculation
fans.
Forced-draft (FD) fans supply the air necessary (stoichiometric plus excess air) for fuel combustion
in a boiler. In addition, they provide air to make up for air preheater leakage and sealing-air
requirements. Forced-draft fans supply the total airflow, except when an atmospheric-suction
primary-air fan is used.
Large high pressure primary air fans supply the air needed to dry and transport coal, either directly
from the pulverizing equipment to the furnace, or to an intermediate storage bunker. Primary air
fans may be located before or after the milling equipment.
The induced draft (ID) fans exhaust combustion gases from the boiler by creating a sufficient
negative pressure to establish a slight suction in the furnace. The ID fans are now typically located
downstream of (after) any particulate removal system.
92
Gas recirculation fans draw gas from a point between the economizer outlet and the air-preheater
inlet, and discharge it for steam-temperature control into the bottom of the furnace. Gas
recirculation fans are under the highest wear and tear requirements of all air fans, due to heavy dust
loads and rapid temperature changes. Fluidized bed boilers can also be equipped with a flue gas
recirculation fan for bed temperature control.
Fan selection
Most fans are radial fans (Figure 16).
Sometimes fans with a two sided air inlet are
preferred. Axial fans are rarely used, since
they are more expensive.
The selection of fans is made using
performance curves provided by the fan
manufacturer. The curves are based on
experimental data from tests made by the
manufacturer. The curve illustrates the
change in the total pressure created by a
certain fan as a function of volume flow and
speed of rotation. When choosing a fan, the
required volume flow and pressure difference
must be known. Other factors influencing the
choice are the following:
•
•
•
Figure 16: Radial air fan.
Efficiency
Required space
Shape of the characteristic curve for
the fan.
To minimize the pressure losses in ducts
sudden changes in direction, narrow passages,
and enlargements must be avoided. Figure 17
shows a typical pressure profile in a fluidized
bed boiler. Primary air flow through the
fluidized bed causes the largest pressure loss.
The second largest pressure drops are due to
flue gas and air flow through the dense tube
bundles in heat exchangers.
Air and flue gas channels must be gas tight
and be able to endure over and under pressure.
This tightness depends on the pressures in the
channel (at least +5 kPa. Sometimes +20 kPa).
The flue gas channels must be well isolated to
avoid cold spots, so that the sulfur in the flue
gases can not cause damage to the structures.
Figure 17: Pressure profile in a fluidized bed
boiler.
Flue gas velocity must be at least 8–10 m/s even with minimum load to prevent accumulation of fly
ash in the ducts. To reduce pressure losses and fan power consumption, the flue gas velocities at full
load must not exceed 30–35 m/s.
93
Fuel handling equipment
Fuel needs to be stored in safe manner, transported to the furnace and often modified for better
burning properties. All equipment that participates in this work is called fuel handling equipment. A
typical fuel feeding system of a PCF steam boiler is visualized in Figure 1.
Coal feeders
A coal feeder is a device that supplies the pulverizer with an uninterrupted flow of raw coal. This is
important, especially in direct-fired systems. There are several types, including the belt feeder and
the overshot roll feeder.
The belt feeder uses a looped belt running on two separated rollers receiving coal from above at one
end and discharging it at the other end. Varying the speed of the belt controls the feed rate, while a
levelling plate fixes the depth of the coal bed on the belt.
The overshot roll feeder has a multi-bladed rotor, which turns about a fixed, hollow, cylindrical
core. The core has an opening to the feeder discharged, and is provided with heated air to minimize
the accumulation of wet coal, to aid in coal drying. A spring-loaded levelling gate mounted over the
rotor limits the discharge from the rotor pockets.
Crushers
There are numerous types of crushers
commercially available. The most generally
used coal crusher for smaller capacities is the
swing-hammer type. The swing-hammer crusher
consists of a casing enclosing a rotor to which
pivoted hammer ore rings are attached. Solid
fuel (coal) is fed through an opening in the top
of the casing and the revolving hammers or rings
crush the coal by direct impact or by throwing
the coal against liners or spaced grate bars in the
bottom of the casing.
Pulverizers
To reduce the particle size of coal to the size
needed for successful pulverized coal
combustion (particle size < 0.1 mm), pulverizers
or mills are used to grind or comminute the fuel
(Figure 18). Grinding mills use either one, two
or all three of the basic principles of particle size
reduction: impact, attrition, and crushing. The
four most commonly used pulverizers are the
ball tube, the ring-roll or ball-race, the impact or
hammer mill (see crushers), and the attrition
type.
Figure 18: Coal pulverizer with associated feed
and distribution piping. [1]
A ball-tube mill is basically a hollow horizontal cylinder, rotated on its axis. The cylinder is filled
with forged steel or cast alloy balls, varying from 2-10 cm in diameters. Coal is fed to the cylinder,
which rotates slowly. The coal is accumulated and slowly pulverized by the rolling and falling balls
94
in the cylinder. Due to its large size, the ball-tube mill functions also as a storage reservoir of
pulverized coal, but its power consumption and space requirement are high.
An impact mill consists primarily of a series of hinged or fixed hammers revolving in an enclosed
chamber. Grinding results from a combination of hammer impact on the larger particles, and
attrition of the smaller particles on each other. This type of mill is simple and compact, and its
ability to handle high inlet-air temperatures makes it an excellent dryer. However, its high-speed
design results in higher maintenance costs and power consumption the finer the grinding is.
Attrition mills make also use of impact grinding, and are classified as high-speed mills. The
grinding elements consist of pegs and lugs mounted on a disc, which is rotating in a chamber. This
mill type has similar characteristics as an impact mill.
Ring-roll and ball-race mills comprise the largest number of pulverizers used for coal grinding.
They are of medium speed and utilize primarily crushing and attrition of particles to obtain the size
reduction. Grinding takes place between two surfaces, one (ball or roll) rolling over the other (race
or ring). The sizes can be up to 2.5 m for the race or ring, with the ball or roll diameter being
approximately a third of the race or ring. This type of mill can handle very wet coal, and its hightemperature inlet air makes it a very efficient dryer. These mills require less power than other mill
types. [1]
Ash handling equipment
There are essentially two types of ash produced in a furnace: Bottom ash and fly ash. Bottom ash is
slag, which builds up on the heat-absorbing surfaces of the furnace, superheater, reheater and
economizer that eventually falls off either by its own weight, as a result of load changes, or by soot
blowing. With low ash-fusion temperatures, a large amount of molten slag can stick to the furnace
walls and subsequently fall through the furnace bottom. Other ash becomes mixed with, and carried
away by, the flue gas stream. This ash, which can be collected from the economizer or dustcollection equipment hoppers, is called fly ash. The amount of ash that becomes fly ash depends on
the dust-bearing capacity of the combustion gases, on the size and shape of the particles, and on the
density of the ash relative to that of the upward flowing gas.
Many factors determine the method of handling and storing coal-fired power-plant ash:
•
•
•
•
•
•
•
Fuel source and content of ash forming elements
Plant site (land availability, presence of aquifiers, adjacent residential areas)
Environmental requlations
Steam-generator size
Cost of auxiliary power
Local market for ash
Cementitious character of the ash
Ash collection points
After the combustion process in solid fuel burning furnaces, the ash collects or is collected in
several areas, which are visualized in Figure 19.
95
Flue
gas
Coal
Pulverizer
Pyrites
Bottom ash
Economizer
hopper fly ash
Air preheater
hopper fly ash
ESP, baghouse filter, or
dry scrubber fly ash
Figure 19: Ash is transported from the five points shown in the picture.
Hoppers and conveyors under the furnace bottom collect material falling from the heat absorbing
surfaces of the furnace. . Furnace ash hoppers are constructed of carbon steel plate with structural
framing similar to that of the furnace walls, in order to allow cooling water to cool the ashes.
Hoppers are also used under the reject discharge spouts of the pulverizer to collect pyrites and
tramp iron, which have been separated during the pulverization process. Coarser particles from
economizers and air preheaters, as well as finer particles separated by particle separators, are also
collected into hoppers.
Ash conveyors
In PFC boilers ash is taken out continuously from the bottom of the furnace. Conveyors submerged
under water are frequently used. The water is used to cool ashes. Cooled ash is dragged to a chute
by a bottom scraper conveyor.
In pneumatic ash conveying pressurized air is used to blow ash from one place to another. One
typical example is conveying ESP ash to a silo. Pneumatic ash conveying requires pressurized air
flow. Pneumatic ash conveying is used when ash flow is moderate e.g. peat boilers. Ash must also
preferably be uniform in size and of small diameter.
Electrostatic precipitator
The most common method of particulate emission control in steam boilers is the use of an
electrostatic precipitator (ESP). The ESP is unique among air pollution control devices, because the
forces of collection act only on the particles instead of the entire gas flow. ESP operation depends
on the charging of the particles. Corona particle charging employs ions that are generated at the
discharge electrodes, which together with the collector plates, produce an electric field. This is
accomplished by putting direct current high voltages of the order of 30-75 kV on the discharge
electrodes and earthing the collector plates. The plates attract the charged particles, which can thus
be collected and discharged into a hopper.
96
Electrostatic precipitators (Figure 20)
have
several
advantages
and
disadvantages in comparison with
other particulate control devices.
Advantages are: very high efficiencies
even for very small particles; ability to
handle large gas volumes with low
pressure drops; dry collection of
valuable materials, or wet collection
of fumes and mists; possibility be
designed for a wide range of gas
temperatures and relatively low
operating costs.
Disadvantages of the ESP are:
relatively high capital costs; inability
to control gaseous emissions (when a
Figure 20: ESP during installation.
dry precipitator is of concern);
inflexibility to changes in operating
conditions once installed; it takes up a lot of space and it might not work on particulates with very
high electrical resistivity. [8]
Other methods of particulate emission control are presented in Zevenhoven & Kilpinen: Control of
pollutants in flue gases and fuel gases (http://eny.hut.fi/library/e-books.htm).
Soot blowing
Sootblowers are generally used to keep the flue gas passages open and the tube surfaces clean from
ash. Sootblowers use high-pressure steam to remove the ash layers from the heat exchanging
surfaces.
In a stationary sootblower a lance is placed inside boiler. Steam is injected at sonic speed from
holes at lance. The stationary sootblower is mounted permanently in the duct. Stationary
sootblowers are used in oil and gas boilers. Because the stationary sootblower does not move there
must be a number of sootblowers. The construction must be able to withstand heating and cooling
cycles.
A retractable sootblower consists of a rotating lance. Steam at sonic speed is injected from the tip
along wall. When it is not in use, it is pulled out from the furnace. This type is used in PCF boilers,
especially when low calorific and high ash coals are burned, and in chemical recovery boilers.
A retractable sootblower consists of a lance tube, 7.5-15 cm in diameter and 4-6 m long, which is
usually about half of the furnace width. Sootblowers are placed on opposite walls to provide full
width coverage between heat exchanger banks. The lance tubes are inserted into and rotated in the
spacing between tube banks. At its working end, the lance tube has two opposing nozzles with a
throat diameter varying from 2.5 cm to 3.8 cm. Tube surfaces are usually limited to vertical
orientation for more effective cleaning. Vertical spacing of the sootblowers is generally about 2.7
m, with bank depths of 0.9-1.2 m. A sootblower is visualized in Figure 21.
The lance tubes remain outside the boiler when not in service and are automatically inserted and
traversed across the boiler while being rotated. The rate of traverse speed is generally between 1
97
and 3 m/min and, thus, the travel time of a single sootblower is 3-5 min. High pressure steam from
a poppet valve flows through the lance tube at mass flow rates varying from 4 500 to 9 000 kg/hr,
depending on the nozzle throat diameter and the steam pressure in the lance tube.
Sootblowers consume typically 4-12 % of the total steam produced by the boiler. Sootblower pairs
may be blown simultaneously or sequentially. In sequential mode the blowing time required to blow
the sootblower pair is twice as long as in simultaneous mode.
Figure 21: Retractable sootblower for Kraft recovery boilers. [8]
Optimizing soot blowing operation will maximize both deposit removal efficiency and steam
savings. In addition to peak impact pressure, PIP, which is related to the nozzle design and lance
pressure, the ability of a sootblower to remove the deposit depends on many other factors, including
soot blowing sequence and frequency, traverse speed, distance from the nozzle to the deposit,
deposit thickness, mechanical strength, and deposit-tube adhesion strength.
The principal rules for the soot blowing strategy can be stated as follows. Soot blowing is usually
not needed for screen tubes and lower superheater where the flue gas temperature is over 850 °C,
because deposits are too hard to remove, and they will not grow further after reaching an
equilibrium thickness. In the higher superheater massive deposit accumulation can typically occur
and soot blowing should be performed frequently to lower the flue gas temperature.
In the boiler bank inlet, deposits are hard to remove. Maximum soot blowing energy should
therefore be employed in that area by increasing soot blowing capacity and frequency, and by
placing sootblowers close to the plugging zone.
In the economizer, low-energy and less frequent soot blowing is usually more than enough because
deposits are easy to remove. However, dust sintering is possible to occur at these temperatures,
which complicates the soot blowing optimization. [8]
98
References
1.
Clean Coal Technology Compendium. Demonstration of Coal Reburning for Cyclone
Boiler NOx Control. Los Alamos National Laboratory. Web Page, read September 2003
http://www.lanl.gov/projects/cctc/index.html
2.
Andritz. Recovery boiler operation manual. Ahlstrom Machinery Corporation © 1999.
3.
Pictures supplied by Babcock & Wilcox. http://www.babcock.com/
4.
Combustion Engineering. Combustion: Fossil power systems. 3rd ed. Windsor. 1981.
5.
Huhtinen and Hotta. Combustion of fossil fuels. 2000
6.
Wärtsilä. Bio-energy solutions from Wärtsilä. PDF brochure, viewed September 2003.
http://www.wartsila.com/english/index.jsp
7.
Tekes. BioGrate boiler plant at sawmill – the Humppila heating plant. Web page, read
September.2003. http://www.tekes.fi/opet/biograte.htm#Boiler
8.
Harja L. Evaluation of Commercial Use of the RBD-analyser in Kraft Recovery Units.
Master Thesis. Helsinki University of Technology, 2002.
99
Heat Exchangers in Steam Boilers
Sebastian Teir, Anne Jokivuori
STEAM BOILER TECHNOLOGY – Heat Exchangers in Steam Boilers
Table of contents
Table of contents..............................................................................................................................102
Heat transfer surfaces.......................................................................................................................103
Arrangement of heat transfer surfaces (furnace-equipped boiler) ...................................................104
Furnace.............................................................................................................................................105
Membrane wall ............................................................................................................................106
Convection evaporators................................................................................................................106
Boiler bank...............................................................................................................................106
Economizer ......................................................................................................................................107
Superheater.......................................................................................................................................107
Types of superheater surfaces ......................................................................................................108
Radiation superheaters .............................................................................................................108
Convection superheaters ..........................................................................................................108
Panel superheater .....................................................................................................................108
Wing wall superheater .............................................................................................................109
Back-pass superheater set ........................................................................................................109
Reheater .......................................................................................................................................109
Connections of superheater elements...........................................................................................110
Air preheater ....................................................................................................................................111
Regenerative air preheaters..........................................................................................................111
Recuperative air preheaters..........................................................................................................112
Tubular recuperative air preheater ...........................................................................................112
Plate recuperative air preheater................................................................................................113
References........................................................................................................................................114
102
Heat transfer surfaces
The primary elements of a boiler are the heat transfer surfaces, which transfer the heat from the flue
gases to the water/steam circulation. The objective of the boiler designer is to optimize thermal
efficiency and economic investment by arranging the heat transfer surfaces and the fuel-burning
equipment.
Heat transfer surfaces in modern boilers are furnaces, evaporators, superheaters, economizers and
air preheaters. The surfaces cover the interior of the boiler from the furnace (or inlet in a HRSG) to
the boiler exhaust.
The main means of heat transfer in a furnace is radiation. Superheaters and reheaters are exposed to
convection and radiant heat, whereas convectional heat transfer predominates in air heaters and
economizers.
Flue gases exiting the boiler can be cooled down close to the dew point (t=150-200°C). Air
preheaters and economizers recover heat from the furnace exit gases in order to reduce flue gas
outlet temperature, preheat combustion air (thus increasing efficiency) and use the heat to increase
the temperature of the incoming feed water to the boiler.
Every heating surface cannot be found in every boiler. In industrial systems where saturated steam
is needed, there are no superheaters. Superheaters are built when superheated steam is needed
(mainly at electricity generation in order to reach high efficiency and avoid droplets in the steam
turbine). Figure 1 gives and example of the physical arrangement of heat transfer surfaces in a
boiler with two-pass layout.
Superheater
(steam)
Economizer
(water)
Evaporator
(water/steammixture)
Air preheater
(air)
Figure 1: Physical locations of heat transfer surfaces in a boiler with two-pass layout.
103
Arrangement of heat transfer surfaces (furnace-equipped
boiler)
According to the second law of
thermodynamic heat transfer
cannot occur from a lower
temperature level to a higher
one. That's why the flue gas
temperature has to be higher
than the temperature of the
heat absorption fluid (working
fluid). The temperature of flue
gas leaving the furnace is 8001400°C and it cools down to
150-200°C in the air preheater
(Figure
2).
The
right
arrangement of heat transfer
surfaces have an effect on
durability of material, fouling
of material, temperature of
steam and final temperature of
flue gas.
HP Steam
OUT
Flue Gas
OUT
Superheater
Blower
Economizer
Feedwater
IN
Coal
IN
Air preheater
Furnace
Air
IN
Burner
Ash
OUT
Figure 2: Process drawing of the arrangement of heat transfer
surfaces in a furnace equipped boiler
The evaporator is generally built into the furnace. Moving through the flue gas path in a boiler the
heating surfaces are found in the sequence shown in Figure 1: furnace, superheaters (and reheaters),
economizer and air preheater.
Table 1 presents and example of changes of stream temperatures in heat exchanger surfaces of a
boiler, where the steam pressure is about 80-90 bar.
Table 1: Typical stream temperature changes in heat exchanger surfaces of a boiler.
Boiler surface
Working fluid temperature [°C] Flue gas temperature drop [°C]
Furnace
290->300
1400->1000
Superheaters
300->600
1000->600
Economizer
105->290
600->300
Air preheater
20->200
300->150
The heat transfer in the furnace results in a phase change of the working fluid (water to steam or
fluid to gas). The small water/steam temperature rise is due to the fact that the water enters the
furnace slightly sub-cooled (not saturated). These temperatures are only examples. They can be at
various levels at different types of boiler, but the heat load graph look practically the same. The heat
load graph, constructed from the table above, can be found in Figure 3. [1]
104
1600
Flue gas stream
Water/steam stream
1400
Air stream
1200
Temperature [°C]
1000
800
600
Air preheater
400
200
Furnace
Superheater
Economizer
0
0%
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %
100 %
Share of heat load [%]
Figure 3: Example of a heat load graph for a furnace equipped boiler.
Furnace
The furnace is the part of the boiler where the
combustion of the fuel takes place. The main
role of the boiler furnace is to burn the fuel as
completely and stably as possible. Leaving
unburned material will decrease the heat
efficiency and increase the emissions.
Combustion must be performed in an
environmentally sustainable way. The emissions
from the furnace must be as low as possible.
The furnace walls of a modern boiler consist of
vertical tubes that function as the evaporator part
of the steam/water cycle in the boiler. The boiler Figure 4: Inside a recovery boiler furnace. [2]
roof is usually also part of the evaporator as well
as the flue gas channel walls in the economizer
and the air preheater parts of the boiler. Figure 4 shows a photograph from the inside of a recovery
boiler furnace.
Adequate furnace cooling is vital for the boiler. However, when burning very wet fuels as wood
chips, some parts of the furnace should not be cooled in order not to remove too much heat from
furnace. Thus a part of the furnace of boilers using such fuels consists of a refractory material,
which reflects the heat of combustion to the incoming wet fuel.
105
If the flue gas temperature after furnace is
too high, the smelting of ash can occur such
problems as ash deposition on superheater
tubes. High temperature corrosion of
superheater tubes can appear as well. Figure
5 presents an example of a temperature
distribution in a two-pass boiler.
Membrane wall
Nowadays, the furnace is generally
constructed as a gas-tight membrane wall.
The membrane wall construction consists of
tubes, which have been welded together
separated by a flat iron strip, called the
membranes. The membranes act as fins to
increase the heat transfer. They also form a
continuous rigid and pressure tight
construction for the furnace. The most
common furnace tube used is a finned
carbon steel tube that forms the membrane
wall. A drawing visualizing a typical
membrane tube wall can be found in Figure
6.
Convection evaporators
In boilers with low steam pressure, the share
of the heat needed for evaporation is bigger
than when considering a high-pressure
boiler. Thus the furnace-wall evaporator
cannot provide enough heat for evaporation
process in low-pressure boilers. Convection
evaporators supply the supplementary heat
needed for complete evaporation. They are
normally placed after the superheater stage
in boiler process. Convection evaporators
can cause local tube overheat problems with
partial loads.
Boiler bank
A boiler bank is a convection evaporator
that uses two drums: one on the top of the
evaporator tubes, and another in the bottom.
A boiler bank is usually used in parallel
with the natural circulation based
evaporator/furnace, as in Figure 7. Boiler
banks are less common nowadays and are
nowadays typically used in low pressure
and small boilers.
Figure 5: Furnace temperature distribution.
Gas tight modern tube wall
Insulation wool
Outer wall
Figure 6: Modern gas-tight membrane tube wall
construction. Unfinned wall tubes are welded
together with metal strips.
Figure 7: Boiler generating bank (marked with
green colour).
106
Economizer
After the feedwater pump, the water has the
required pressure and temperature to enter the
boiler. The pressurized water is introduced
into the boiler through the economizers. The
economizers are heat exchangers, usually in
the form of tube packages.
The purpose of economizers is to cool down
the flue gases leaving the superheater zone,
thus increasing the boiler efficiency. The
limiting factor for cooling is the risk of low
temperature corrosion, i.e. dew point of water.
Economizers are placed after the superheater
zone in the flue gas channel. They are usually
constructed as a package of tubes fastened on
the walls of the flue gas channel.
Figure 8: Economizer tube from a recovery boiler.
[2]
Flue gases are cooled down with feedwater, which gets preheated up to its saturation temperature.
In order to prevent the feedwater from boiling before it has entered the furnace/evaporator, the
temperature of the feedwater exiting the economizer is usually regulated with a safety margin below
its saturation temperature (about 10°C). The heated water is then led to the steam drum.
The economizer shown in Figure 8 consists of two long-flow, vertical sections. Each economizer
section is comprised of straight vertical finned tubes, which are connected in parallel to one another.
The tubes are connected at the top and bottom to larger headers. This kind of vertical tube packages
is typical for chemical recovery boilers. Other boilers use packages of horizontal tubes. The bundles
are placed in the second pass of the boiler, behind the superheaters. Here, the water is utilizing the
heat of the flue gases that is left from the superheaters, before the flue gases leave the boiler. The
flue gas temperature should always stay above the dew point of the gases to prevent corrosion of the
precipitators and ducts.
Superheater
The superheater is a heat exchanger that overheats (superheats) the saturated steam. By
superheating saturated steam, the temperature of the steam is increased beyond the temperature of
the saturated steam, and thus the efficiency of the energy production process can be raised.
Superheated steam is also used in facilities that don't produce electricity.
The benefits of using superheated steam are:
•
•
•
Zero moisture content
No condensate in steam pipes
Higher energy production efficiency
The superheater normally consists of tubes conducting steam, which are heated by flue gases
passing outside the tubes. The tubes are usually connected in parallel using headers, with steam
entering from one header and exiting in another header. There can be several superheater units in
107
the same boiler, as well as reheaters, which is a superheater for heating external steam (steam
already used in a process outside the boiler). [2]
Types of superheater surfaces
Superheaters can be divided into convection
based and radiation based superheaters.
Radiation superheaters
Radiation based superheaters are used to gain
higher steam temperatures and the heat is mainly
transferred by radiation. These superheaters
have to be placed within reach of the flame
radiation. Thus radiant superheaters are usually
integrated as tubes in the boiler-walls or built as
panels hanging from the boiler roof. The
radiation superheater is located in the top of the
furnace, where the main means of heat transfer
is radiation.
Convection superheaters
Convection superheaters are the most common
superheaters in steam boilers. Convection based
superheaters are used with relatively low steam
temperature, and the heat from the flue gases is
mainly transferred by convection. They are Figure 9: Panel superheaters in production. [2]
placed after the furnace protected from the
corrosive radiation of the flames. This type of superheater can also be protected from radiation by a
couple of rows of evaporator tubes. Convection based superheaters can hang from the boiler roof or
they can be placed in the second pass of the boiler (in a two-pass design), and are called back-pass
superheaters.
Panel superheater
The panel superheater (shown in Figure 9 and
Figure 10) functions on both radiation and
convention heat transfer, depending on its
location in the boiler. It consists of tubes that are
tightly bundled in thin panel walls, which hang
from the roof in the exhaust of the furnace. The
distance between the panels is usually about
300-500 mm. The tubes are laid out according to
the inline arrangement. This kind of superheater
can be located e.g. first in the flue gas stream
after furnace in which coal with low heating
value is burned (brown coal). The panel
superheater is resistant to fouling and can
withstand high heat flux.
Figure 10: Panel superheaters installed. [2]
108
Wing wall superheater
The wing wall superheater is a kind of panel superheater that extends from a furnace (Figure 11).
The bank of tubes, which are welded together, is usually built in the front wall of boiler. It has
become popular especially in CFB applications. The tube is often made of carbon steel. The wing
wall superheater receives heat mainly through radiation.
Radiation
superheaters
Panel
superheater
Back-pass
superheater
Wing wall
superheater
Convection
superheater
Figure 11: Arrangement of various types of superheater units.
Back-pass superheater set
Convection superheaters, located in the flue gas
channel (Figure 11 and Figure 12) where the
flue gas starts flowing downwards, are called
back-pass superheaters. In large CFB, coal and
oil boilers horizontal tube arrangements are
commonly used. Back-pass superheater tubes
hang from the back-pass roof.
Reheater
A reheater is basically a superheater that
superheats steam exiting the high-pressure stage
of a turbine. The reheated steam is then sent to
the low-pressure stage of the turbine. By
reheating steam between high-pressure and lowpressure turbine it is possible to increase the
electrical efficiency of the power plant cycle
beyond 40%. The reheat cycle is used in large
Figure 12: Back-pass superheater. [1]
109
power boilers since it is feasible economically only
in larger power plants. Reheater design is very much
similar to superheater design because both operate at
high temperature conditions. The effect of the
reheater in a T-S diagram is plotted in Figure 13.
B
T
A
Connections of superheater elements
Considering the steam flow, superheater elements
are usually connected in series, e.g. first convection
stage and then radiant stage. When looking in the
direction of the flue gas flow, the radiant stage is
placed before the convectional stage of the
superheaters. The steam temperature that can be
reached with convection type superheaters is
significantly lower than that reached with radiant
type superheaters. Thus, boilers having high live
steam temperature use radiant type superheaters as
final superheater.
D
C
S
Figure 13: The reheater (line C-D) in a
power plant cycle, plotted in a T-S diagram
for steam/water.
The small amount of saturated water still remaining in steam evaporates in the first superheater
section. This makes solid impurities of boiler water stick on inner surface superheater tubes and
thus decreases the heat transfer coefficient of the tubes. Superheater stages are therefore placed in
counter-current order, i.e. the first superheater stage is situated at the lowest flue gas temperature.
Superheated
Steam OUT
Reheated
Steam OUT
Feedwater
IN
Reheater
IN
Saturated
Steam IN
Reheater I
Superheater I
Reheater II
Superheater III
Superheater II
Figure 14: Connection of superheater and reheater stages.
110
However, the superheater situated at the hottest
spot within the boiler (normally convective
superheater) is not usually the final superheater
because of the possible overheating problems.
Thus, the convective superheater is connected in
forward-current order in relation to flue gas flow
to provide enough cooling for superheater tubing
(Figure 14)
The superheater banks are connected to
proceeding banks by interconnecting piping, i.e.
pipes connect each ends of an outlet header to
the opposite ends of the next superheater's inlet
Figure 15: Cross-connections of superheater
headers, as shown in Figure 15. This cross-over
headers. [2]
of steam flow assures even distribution of steam
circulation through the entire superheater system
and minimized temperature variations from one side of the boiler to the other.
Air preheater
Air preheaters have two important functions in a
steam boiler: they cool the gases before they
pass to the atmosphere (thereby increasing the
efficiency), and they raise the temperature of the
incoming combustion air (thereby drying solid
fuel faster). The heated air from air preheaters is
also used for transporting the fuel in PCF boilers
and fluidized bed boilers. Air preheaters can be
of a regenerative or recuperative type. [3]
Figure 16: Heat transfer surfaces of the rotor.
[4]
Regenerative air preheaters
In regenerative air preheaters no media for heat
transfer is used - they use the heat accumulation
capacity of a slowly rotating rotor for
transferring the heat. The rotor is alternately
heated in the flue gas stream and cooled in the
air stream, heat-storage being provided by the
mass of the packs consisting of closely spaced
metal sheets (Figure 16), 0.5-0.75 mm thick,
which absorb and give off heat on both sides.
The rotor is divided into pie-shaped 'baskets' of
theses metal sheets, which in turn pick up heat
from flue gases and release it into the
combustion air, as shown in the drawing in
Figure 17.
Figure 17: The heat-transfer principle of a
regenerative air preheater. [4]
Regenerative air preheaters occupy little space; about 1/4 or 1/6 of the space required by
recuperative air preheaters and can be produced cheaply. Without exaggeration it can be claimed
that they have rendered possible the low flue-gas exit temperatures achieved today. Their reduced
tendency to dew point corrosion should also be stressed, in particular where sulphur-containing
fuels are used. Moreover, any sheet metal packs that have become corroded can be replaced easily
111
and quickly. They can also be cleaned easily by
playing a jet of steam over the gaps in the packs
of sheet metal.
The Ljungstrom air preheater (Figure 18) has
acquired exceptional importance; since the last
war it has found wide acceptance in Europe. The
Rothmühle air preheater (Figure 19) is another
type of regenerative air preheater, where the
duct rotates around the battery of plates, which
is fixed.
The problem of regenerative air preheaters is the
gas leakage from one side to another. This can
cause fires due to air leakage if flue gases
contain high amount of combustibles (due to
poor combustion).
Figure 18: A photograph of a Ljungstrom air
preheater. [4]
Recuperative air preheaters
In a recuperative air heater the heat from a hightemperature flowing fluid (flue gas) passes
through a heat transfer surface to cooler air. The
heating medium is completely separated at all
times from the air being heated. The
recuperative principle implies the transfer of
heat through the separation partition, with the
cool side continuously recuperating the heat
conducted from the hot side. Thus, the
advantage of recuperative air preheaters in
general is the lack of leakage because the sealing
is easier to implement here than in the
Figure 19: Rotmühle air preheater. [1]
regenerative type. The separating surface may be
composed of tubes or plates. The rate of flow is
determined by temperature differential, metal
conductivity, gas film conductivity, conductivity of soot, and ash and corrosion deposits. The
cumulative effect of these factors may be large. There are two types of recuperative heat
exchangers: tubular and plate preheaters.
Tubular recuperative air preheater
Tubular air preheater is comprised of a nest of long, straight steel or cast-iron tubes expanded into
tube sheets at both ends, and an enclosing casing provided with inlet and outlet openings. If the
tubes are placed vertically, the flue gases pass through or around them (Figure 20). If the tubes are
placed horizontally, the flue gases only pass around them (Figure 21). The design, which usually
provides a counter-flow arrangement, may consist of a single pass or multiple passes with either
splitter (parallel to tubes) or deflecting (cross-tube) baffling. Traditionally the tubes were made of
cast iron for good corrosion resistance. Thus the whole preheater was heavy and needed massive
foundations.
112
Flue gas
Air
Flue gas
Air
Figure 21: Two-pass (horizontal) air preheater
design.
Figure 20: Straight (vertical) air preheater
design.
Plate recuperative air preheater
A newer, alternative design is the plate-frame type recuperative air preheater. It offers the same heat
transfer capacity with reduced unit weight and size. Plate air preheater consists of a series of thin,
flat, parallel plates assembled into a series of thin, narrow compartments or passages, all suitably
cased. Flue gas and air pass through alternate spaces in counter-flow directions. The plate air
preheater may be arranged more compactly than the tubular type. Because of cleaning difficulties,
however, its use is diminishing.
113
References
1. Vakkilainen E. Lecture slides and material on steam boiler technology, 2001
2. Andritz. Recovery Boiler Operation Manual, Ahlstrom Machinery Corporation 1999. CDrom. http://www.andritz.com/
3. Combustion Engineering. Combustion: Fossil power systems. 3rd ed. Windsor. 1981.
4. Alstom. Air preheater company web page, read September 2003.
http://www.airpreheatercompany.com/airpreheaters.asp
114
Boiler Calculations
STEAM BOILER TECHNOLOGY – Boiler Calculations
Table of contents
Steam/water diagrams used in boiler calculations ...........................................................................117
Temperature-heat (T-Q) diagram.................................................................................................117
Temperature-entropy (T-s) diagram.............................................................................................118
Application of the T-s diagram ................................................................................................119
Pressure-enthalpy (p-h) diagram..................................................................................................120
Enthalpy-entropy (Mollier, h-s) diagram .....................................................................................121
Determination of steam/water parameters .......................................................................................122
Given parameters .........................................................................................................................122
Pressure losses..............................................................................................................................122
Procedure for determination of specific enthalpies and mass flow rates.....................................122
Superheaters and reheaters...........................................................................................................123
Spray water group mass flow.......................................................................................................124
Calculations of heat load..............................................................................................................125
Evaporator................................................................................................................................125
Superheater...............................................................................................................................125
Reheater ...................................................................................................................................125
Economizer ..............................................................................................................................126
Air preheater ............................................................................................................................126
Determination of boiler efficiency...................................................................................................126
Standards......................................................................................................................................126
Major heat losses..........................................................................................................................126
Heat loss with unburned combustible gases ............................................................................126
Heat loss due to unburned solid fuel........................................................................................127
Heat loss due to wasted heat in flue gases ...............................................................................127
Heat loss due to wasted heat in ashes ......................................................................................127
Losses due to heat transfer (radiation) to the environment......................................................128
Losses of blowdown, sootblowing and atomizing steam.........................................................128
Internal power consumption.........................................................................................................128
Calculating boiler efficiency........................................................................................................129
Direct method...........................................................................................................................129
Indirect method ........................................................................................................................129
References........................................................................................................................................130
116
Steam/water diagrams used in boiler calculations
Temperature-heat (T-Q) diagram
The T-Q diagram is a useful tool for designing heat exchangers. It can also be used to present the
heat transfer characteristics of an existing heat exchanger or heat exchanger network. The T-Q
diagram consists of two axes: The current stream temperature on the y-axis and the amount of heat
transferred on the x-axis. Sometimes the streams are marked with arrowheads to clarify the
direction of the streams, but these are not necessary: since heat cannot move from the colder stream
to the hotter stream according to the second law of thermodynamics, the directions of the streams
are explicitly determined: The hot stream transfers its heat to the cold stream, thus the flow
direction of the hot stream is towards lower temperature and the flow direction of the cold stream is
towards higher temperatures. For the same reason, the hot stream is always above the cold stream in
the T-Q diagram (Figure 1).
Figure 1: Examples of T-Q diagrams for a parallel flow heat exchanger (left), and a counter (or
cross) flow heat exchanger (middle). The hot stream is marked with red color and the cold with
blue color.
1600
Flue gas stream
Water/steam stream
1400
Air stream
1200
1000
Temperature [°C]
When designing or
reviewing
heat
exchanger networks, the
T-Q diagram gets useful.
The T-Q diagram is
therefore applied when
designing
boilers;
especially
the
heat
exchanger
surface
arrangement can be
clearly visualized with a
T-Q diagram (Figure 2).
800
600
Air preheater
400
200
Furnace
Superheater
Economizer
0
0%
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %
100 %
Figure 2: Example of a T-Q diagram representing the heat surfaces in a
furnace equipped boiler.
117
tant
p = cons
v = constan
Temperature
nt
sta
n
co
v=
p = constant
Liquid-vapour region
X = 0,2
X = 0,9
va
po
ur
d
Sa
t
ur
a
ted
liq
uid
p = constant
e
at
The enclosed region in the middle is
the region where water is a mixture
of vapor and liquid. Steam that
contains water in any form, either as
Critical point
tur
Sa
The left border, up to the critical
point, is the border where the liquid
is saturated (Figure 3). That is, the
water is still liquid and contains no
steam. But if we go further right
(increase the entropy), steam bubbles
starts to form in the water. In other
words, saturated water starts to boil
when heat is added and entropy is
increased.
t
The T-s diagram represents the
various phases of steam/water with
temperature as a function of the
specific entropy. It is often used to
visualize steam power processes. The
T-s diagram is also commonly used
for displaying reversible processes
(or real processes simplified as
reversible processes), which in the Ts diagram appear as closed curves
(loop).
p = cons
tant
Temperature-entropy (T-s) diagram
Entropy
Figure 3: Simplified T-s diagram of steam/water.
minute droplets, mist or fog, is called wet steam. The quantity called ‘x’ in the diagram represents
the amount (percentage by weight) of dry vapor in the wet steam mixture. This quantity is called the
quality of steam. For instance, if there is 10% moisture in the steam, the quality of the steam is 90%
or 0.9. The temperature of wet steam is the same as dry saturated steam at the same pressure.
The right border, down from the critical point, is the line where steam is saturated. When steam is
heated beyond that border, steam is called superheated.
Water boils under constant temperature and pressure, so a horizontal line inside the enclosed region
represents a vaporization process in the T-s diagram. The steam/water heating process in the boiler
represented by the diagram in figure 2 can also be drawn in a T-s diagram (Figure 4), if the boiler
pressure is assumed to be e.g. 10 MPa.
118
Figure 4: Detailed T-s diagram of the PCF boiler steam/water heating process from figure 2 (note:
color of the steam/water process line is changed from blue to red).
Application of the T-s diagram
Consider the simple steam power plant
based on the Rankine cycle, as
visualized in (Figure 5). The plant
consists of a steam boiler (superheater,
evaporator and economizer), turbine
with generator, condenser and a feed
pump. The Rankine cycle consists of
the following processes:
Sup erheate r
1
Turbine & Generator
G
6
Evapo rator/
Furn ace
2
Econo mizer
5
Pump
1-2:
Expansion of high-pressure
steam
in
the
turbine
4
(isentropic)
2-3: Condensation of low- pressure
Figure 5: Rankine cycle
steam in the condenser (isobaric and
isothermal)
3-4: Compression of water in the feed pump (isentropic)
4-5: Heating of water in the economizer at a high pressure (isobaric)
5-6: Evaporation of water in the evaporator at a high pressure (isobaric)
6-1: Heating of steam in the superheater at a high pressure (isobaric)
3
Con denser
119
Pressure-enthalpy (p-h) diagram
1
q
Temperature
The process can be visualized by drawing the
process into a T-s diagram (
Figure 6). Since the process is assumed to be
isentropic, the expansion and compression
lines are strictly vertical. If the losses in the
turbine and pump were considered, the
vertical lines would be slightly tilted so that
entropy increases. [1]
w
w
6
5
4
3
q
2
x=1
x=0
Another tool used in boiler calculation is the
pressure-enthalpy diagram for steam/water
Entropy
(Figure 7). With the p-h diagram it is easy to
visualize the partial shares of the total heat
Figure 6: T-s diagram of the Rankine cycle in
load on different heat exchanger surfaces in
Figure 5.
the boiler: drawing the steam heating process
in the boiler onto the p-h diagram will give a
horizontal line (if we simplify the process and set pressure losses to zero). Figure 7 shows the same
boiler steam/water process from Figure 4, drawn in the steam/water p-h diagram.
Figure 7: Detailed p-h diagram of the PCF boiler steam/water heating process (red line) from
Figure 4.
120
ant
p = const
p = cons
T = constant
va p
ou
r
T = constant
Sat
u ra
ted
The most frequently used tool for determining
steam properties is probably the enthalpyentropy (h-s) diagram, also called Mollier
diagram (Figure 8). If two properties of the
steam state are known (like pressure and
temperature), the rest of the properties for
steam (enthalpy, entropy, specific volume and
moisture content) can be read from the
diagram. A more detailed h-s diagram can be
found in Figure 9. Since the diagram is very
large, the diagram is usually found as two
versions, consisting of zoomed portions of the
original: one for steam properties (Figure 8)
and another for water properties.
tant
Enthalpy-entropy (Mollier, h-s) diagram
Critical point
X = 0,9
X=0
6
,90
Liquid-vapour region
Figure 8: Mollier (h-s) diagram, simplified
version.
Figure 9: Large-scale Mollier h-s diagram for steam.
121
Determination of steam/water parameters
Given parameters
Normally in a steam boiler design assignment the parameters describing the live (output) steam, e.g.
mass flow, pressure and temperature are given. If the steam boiler to be designed has a reheat cycle,
also reheat pressure and temperature are given. Reheat steam mass flow can be given as well. These
parameters are used to determine the rest of the steam/water parameters. [2]
Pressure losses
The pressure losses in the heat exchanger units of the boiler are estimated according to the
following approximations:
•
•
•
•
Economizer: the pressure loss is 5-10% of the pressure of the feedwater entering the
economizer.
Evaporator:
Once through boilers: in once-through boilers the pressure loss of the evaporator is between
5 and 30%.
Forced and natural circulation boilers: the pressure drop in the evaporator part of drumbased boilers does not affect the pressure loss of the main steam/water flow through the
boiler. This means that saturated steam leaving the steam drum has the same pressure as the
feedwater entering the steam drum. The pressure loss of the evaporator has to be overcome
using the driving force (natural circulation) or circulation pump (forced circulation).
Superheater: the total pressure drop of all superheater packages is less than 10% of the
pressure of the superheated steam.
Reheater: the pressure drop in the reheater is about 5% of the pressure of reheated steam
Pressure losses of connection tubes between different heat transfer surfaces (e.g. between
evaporator and superheater) can be neglected in these calculations.
Procedure for determination of specific enthalpies and mass flow rates
1. The specific enthalpy of the superheated steam can be determined with an h-s diagram if both
the temperature and the pressure of the steam are known. Thus, the specific enthalpies for live
(superheated) steam and reheated steam can be calculated.
2. The total pressure loss of the superheater stages should be chosen. Thus, the pressure in steam
drum (drum-type boilers) or pressure after evaporator (once-through boilers) can be calculated
by adding the pressure loss over the superheater stages to the pressure of the superheated steam.
3. Specific enthalpy of saturated water and steam (in the steam drum) can be read from an h-s
diagram or steam tables, as the pressure in the steam drum is known.
In once-through boilers the determination of specific enthalpy after the evaporator is based on
the temperature. The reason for this is the unclear state of supercritical steam after the
evaporator in once-through circulation. The temperature after the evaporator in once-through
boilers is typically between 400 and 450°C.
122
4. For removal of salts and minerals concentrated in the steam drum, a part of the water in steam
drum is removed as blowdown water from the bottom of the steam drum. Normally the mass
flow rate of blowdown is 1-3% of the mass flow rate of feedwater coming into steam drum.
5. In principle, the feedwater coming into steam drum should be saturated water. To prevent the
feedwater from boiling in the transportation pipes, the temperature of the feedwater reaching the
steam drum is 15-30°C below saturation temperature. This temperature difference is called the
approach temperature. The feedwater is then called subcooled (in contrast to supercooled).
When the temperature in the steam drum and the value of the approach temperature are known,
the temperature after the economizer can be determined. The water pressure after the
economizer can be assumed to be equal to the pressure in the steam drum and specific enthalpy
after the economizer can then be read from a h-s diagram.
In once through boilers the pressure after the economizer can be calculated by adding the
pressure loss in the evaporator to the pressure after evaporator. The temperature after the
evaporator is normally between 300 and 350°C (can be chosen as a unique value for the boiler).
Knowing the pressure and the temperature, the specific enthalpy after the evaporator can be
defined.
6. The pressure before the economizer can be calculated by adding the pressure loss in the
economizer to the feedwater pressure after economizer. The feedwater temperature might be
stated in the boiler design assignment. If it is not given, it should be chosen from the range of
200-250°C. The mass flow rate before the economizer is the blowdown mass flow rate added to
the mass flow rate from the steam drum to the superheaters.
Superheaters and reheaters
Reheating takes usually place in two stages.
The pressure before the reheater is the reheated
steam pressure added on the pressure loss in
the reheater. The steam goes through a highpressure turbine before it enters the reheater. In
the high-pressure turbine, the specific enthalpy
of steam decreases according to the isentropic
efficiency of the turbine. Isentropic efficiency
is normally between 0.85 and 0.95. A part of
the low-pressure steam coming from highpressure turbine continues to the high-pressure
feedwater heater (closed-type feedwater
heater). However, the mass flow rate of
reheated steam is still 85-90% of that of the
live steam.
t °C
535
505
475
435
410
354
I
II
III
Heat load
Superheating and reahiting is often applied in
three stages having spray water groups Figure 10: An example of the heat load share of
superheater stages.
between each other to regulate steam
temperature when necessary. Spray water
group dimensioning is usually based on a
steam temperature decrease of 15-40°C by water spraying. Spray water originates normally from
the feedwater line before the economizer. Thus the pressure difference is the pressure loss of the
123
heat transfer surfaces between the economizer inlet and the location of the spray water nozzle. An
example of a possible heat load share between the superheater stages is shown in Figure 10.
Pressure loss in superheaters can be divided into equal partial pressure losses corresponding to each
superheater stage. Pressure loss of the spray nozzles can be neglected. Temperature rise over all
superheaters can be divided into quite similar parts along the same principle.
Spray water group mass flow
Normally the mass flow rate of superheated steam (live steam) is known. Thus, mass flow rate
calculations start usually by calculating the mass flow rate of spray water to the last spray water
group (which is in this example between the second and third superheater stages). The mass flow
rates can be solved with energy and mass balance equations. With the equations below (equation 1),
the mass flow rate of steam after second superheater stage and mass flow rate of spray water to the
last spray water group can be calculated. The mass flow rate of spray water to the first spray water
group can be calculated along the same procedure:
m& SHII + m& SPRAYII = m& SHIII
m& SHII ⋅ hSHII , 2 + m& SPRAYII ⋅ hSPRAY = m& SHIII ⋅ hSHIII ,1
(1)
where m& SHII is the mass flow rate of steam after second superheater stage [kg/s], m& SPRAYII the mass
flow rate of spray water to second spray water group, m& SHIII the mass flow rate of superheated
steam (live steam), hSHII , 2 the specific enthalpy of steam after second superheater stage [kJ/kg],
hSPRAY the specific enthalpy of spray water (feedwater), and hSHIII ,1 the specific enthalpy of steam
before third superheater stage. Figure 11 shows a flow chart with the symbols visualized of the
boiler arrangement used in this calculation model.
HP Steam
OUT
HP Steam
OUT
Reheat
IN
SPRAYII
2
SHI
Coal
IN
1
2
SHIII
1
Flue Gas
OUT
SPRAYI
2
1
RH
EVAP
2
1
SHII
2
ECO
1
2
Ash
OUT
1
Air
IN
APH
Feedwater
IN
Figure 11: Flow chart of the PCF boiler arrangement used in this heat load calculation model.
124
Calculations of heat load
When the steam parameters and mass flows have been determined, the heat load of the heat
exchanger units can be calculated. The heat load is the heat transferred by a heat exchanger
(calculated in kW).
Evaporator
The heat load of the evaporator part of the boiler can be calculated as:
φ EVAP = m& SH (h′′ − hECO 2 ) + m& BD (h′ − hECO 2 )
(2)
where m& SH is the mass flow of steam before superheater [kg/s], h ′′ the specific enthalpy of saturated
steam at steam drum pressure [kJ/kg], hECO 2 the specific enthalpy after economizer m& BD the mass
flow of blowdown water from steam drum, and h ′ the specific enthalpy of saturated water at steam
drum pressure [kg/s].
Superheater
Normally superheating takes place in three or four stages in a big boiler. This calculation example is
based on three stage superheating. The heat load of the first superheater stage is
φSHI = m& SH (hSHI , 2 − h′′)
(3)
where hSHI , 2 is the specific enthalpy of steam after the first superheater stage. In the second
superheater stage the heat load added can be calculated as:
φSHII = m& SHII (hSHII , 2 − hSHII ,1 )
(4)
where m& SHII is the mass flow of steam before the second superheater [kg/s], hSHII , 2 the specific
enthalpy of steam after the second superheater stage [kJ/kg], and hSHII ,1 the specific enthalpy of
steam before the second superheater stage. Similarly, the heat load added in third superheater stage
can be calculated as:
φSHIII = m& SHIII (hSHIII , 2 − hSHIII ,1 )
(5)
wher m& SHIII = Mass flow of steam before third superheater [kg/s], hSHIII , 2 the specific enthalpy of
steam after third superheater stage [kJ/kg], and hSHIII ,1 the specific enthalpy of steam before third
superheater stage [kJ/kg].
Reheater
The heat load of the reheater stage can be calculated as:
φ RH = m& RH (hRH 2 − hRH 1 )
(6)
where m& RH is the mass flow rate of steam in the reheater [kg/s], hRH 2 the specific enthalpy of steam
after the reheater [kJ/kg] , and hRH 1 the specific enthalpy of steam before the reheater.
125
Economizer
The heat load of the economizer can be calculated as:
φ ECO = m& ECO (hECO 2 − hECO1 )
(7)
where m& ECO is the mass flow rate of feedwater in the economizer [kg/s], hECO 2 the specific enthalpy
of feedwater after the economizer [kJ/kg], and hECO1 the specific enthalpy of feedwater before the
economizer.
Air preheater
In order to calculate the heat load for the air preheater, we need to know the combustion air mass
flow, the temperature of the flue gases and the incoming air. The combustion air fed into air
preheater, is taken from upper part of the boiler room. The temperature of the combustion air before
the air preheater is therefore between 25 and 40°C (in Finnish conditions). The flue gases exiting
the boiler are usually kept above 130-150°C in order to prevent corrosion. The enthalpies can be
taken from tables:
φ APH = m& FUEL ⋅
m& AIR
⋅ (hAPH 2 − hAPH 1 )
m& FUEL
where m& FUEL is the mass flow rate of fuel fed into the boiler [kg/s],
(8)
m& AIR
the mass flow rate of
m& FUEL
combustion air divided by the mass flow rate of fuel fed into the boiler, h APH 1 the specific enthalpy
of combustion air before the air preheater [kJ/kg], and h APH 2 the specific enthalpy of combustion air
after the air preheater.
Determination of boiler efficiency
Standards
There are two main standards used for definition of boiler efficiency. Of those, the German DIN
1942 standard employs the lower heating value (LHV) of a fuel and is widely used in Europe. The
American ASME standard is based on higher heating value (HHV). However, this chapter
calculates the efficiency according to the DIN 1942 standard. [2]
It should be marked that with the DIN standard it is possible to reach boiler efficiencies over 100%,
if the condensation heat of the flue gases is recovered.
Major heat losses
Heat loss with unburned combustible gases
The typical unburned combustible gases are carbon monoxide (CO) and hydrogen (H2). In large
boilers usually only carbon monoxide can be found in significant amounts in flue gases. Assuming
that flue gases contain only these two gases, the losses [kW] can be calculated as:
φ L1 = m& CO ⋅ H l ,CO + m& H ⋅ H l , H
2
2
(9)
126
where m& CO is the mass flow of carbon monoxide [kg/s], m& H 2 the mass flow of hydrogen, H l ,CO the
lower heating value (LHV) of carbon monoxide (10.12 MJ/kg), and H l ,H 2 the lower heating value
(LHV) of hydrogen (119.5 MJ/kg). If a relevant amount of some other flue gas compound can be
found in the flue gases, it should be added to the equation.
Heat loss due to unburned solid fuel
Unburned fuel can exit the furnace as well as bottom ash or fly ash. The heating value of ashes can
be measured in a specific laboratory test. The losses [kW] of unburned solid fuels can be calculated
as:
φ L 2 = m& ubs ⋅ H l ,ubs
(10)
where m& ubs is the total mass flow of unburned solid fuel (bottom ash and fly ash in total) [kg/s], and
H l ,ubs the lower heating value (LHV) of unburned solid fuel (fly ash and bottom ash in total)
[kJ/kg]. Some estimates of the losses with unburned solid fuels are presented in Table 1:
Table 1: Estimates of losses with unburned solid fuel. [2]
Boiler type
Heat loss per heat input of fuel
Oil fired boiler
0,2 - 0,5 %
Coal fired boiler, dry ash removal
3%
Coal fired boiler, molten ash removal
about 2 %
Grate boiler
4-6 %
Heat loss due to wasted heat in flue gases
Flue gases leave the furnace in high temperature and thus they carry significant amount of energy
away from boiler process. The heat loss due to wasted heat in flue gases is much larger than any
other loss; therefore this is the most dominating factor affecting the boiler efficiency. To decrease
flue gas losses, flue gas exit temperature should be decreased. However, the acid dew point of flue
gases restricts the flue gas temperature to about 130-150°C for sulfur containing fuels. The losses
caused by the sensible heat of flue gases can be calculated as:
φ L 3 = m& fuel ⋅ ∑
i
m& i
⋅ hi
m& fuel
(11)
where m& fuel is the fuel mass flow [kg/s], m& i the mass flow of a flue gas component, and hi the
specific enthalpy of a flue gas component (e.g. CO2) [kJ/kg].
Heat loss due to wasted heat in ashes
Ash can exit the furnace either as bottom ash from bottom of the furnace or as fly ash with flue
gases. The losses related to the sensible heat of ash can be calculated as:
φ L 4 = m& ba ⋅ c p ,ba ⋅ ∆Tba + m& fa ⋅ c p , fa ⋅ ∆T fa
(12)
127
where m& ba is the mass flow of the bottom ash [kg/s], c p ,ba the specific heat of the bottom ash
[kJ/(kgK)], ∆Tba the temperature difference between the bottom ash temperature and the reference
temperature [°C], m& fa the mass flow of fly ash, c p , fa the specific heat of fly ash, ∆T fa the
temperature difference between the fly ash temperature and the reference temperature [°C]. Usually
the reference temperature is 25°C.
In recovery boilers the bottom ash is removed as molten ash in temperature of about 700-800°C. In
addition, the amount of bottom ash divided by the amount of fuel is about 40%. The loss of sensible
heat of ash is therefore of great importance in recovery boilers.
Losses due to heat transfer (radiation) to the environment
The main form of heat transfer from boiler to boiler room is radiation. It is proportional to the outer
surface area of the boiler and is usually 200-300 W/(m2K) for a well-insulated boiler having its
outer surface temperature below 55°C. Another possibility to determine the heat transfer losses to
the environment is to use a table from the DIN 1942 standard, presented in Table 2.
Table 2: Estimations of heat transfer losses by radiation. [2]
Mass flow rate of steam [t/h]
Combustion method
10
20
40
60
80
100
200
400
600
800
-
1,3
1,0
0,9
0,75
0,7
0,55
0,4
0,35
0,3
Grate
1,5
1,1
0,9
0,7
-
-
-
-
-
-
Oil/gas fired boiler
1,3
0,9
0,7
0,6
0,55
0,4
0,3
0,25
0,2
0,2
Pulverized firing
Loss [%]
Losses of blowdown, sootblowing and atomizing steam
Blowdown water from the steam drum and sootblowing steam (used to remove soot from heat
exchanger surfaces within the boiler) use a part of the steam produced by the boiler. This lowers the
boiler efficiency. In addition, steam is sometimes also used to atomize fuel in the burners. The
losses can be calculated as:
φ L 6 = m& bd ⋅ h′ + m& sb ⋅ hsb + m& atomizing ⋅ hatomizing
(13)
m& bd is the mass flow of blowdown water [kg/s], h ′ is the specific enthalpy of saturated water
(blowdown water from steam drum) [kJ/kg], m& sb is the mass flow of sootblowing steam, hsb is the
specific enthalpy of steam used for sootblowing (when leaving the boiler), m& atomizing is the mass flow
of atomizing steam, and hatomizing the specific enthalpy of steam used for atomizing the fuel (when
leaving the boiler) [kJ/kg].
Internal power consumption
The power plant itself consumes a part of the electricity produced. This is due to the various
auxilary equipments required, like feedwater pumps, circulation pumps and air/flue gas blowers. In
forced circulation boilers the share of electricity consumed by the circulation pump is about 0.5% of
the electricity produced by the plant. The power consumption of the flue gas fan and the air blower
are 0.75 – 1% each.. The largest power consumer is the feed water pump (about 2%).
128
Normally the internal power consumption is about 5% of the electricity produced by the power
plant. Since the power used is electrical (and taken from the grid), the internal power consumption
share is reduced from the final boiler efficiency in boiler calculations.
Calculating boiler efficiency
There are two different means of calculating the boiler efficiency: The direct method and the
indirect method.
Direct method
In the direct method, the boiler efficiency is directly defined by the exploitable heat output from the
boiler and by the fuel power of the boiler:
η=
φoutput
φinput
(14)
where φ output is the exploitable heat output from boiler, and φ input the fuel power of the boiler.
The direct method can be used for steam boilers where it is possible to measure the fuel heat input
accurately.
Indirect method
Indirect method determines the efficiency of a boiler by the sum of the major losses and by the fuel
power of the boiler:
η =1−
φlosses
φinput
(15)
where φ losses is the sum of the major losses within the boiler, and φ input is the fuel power of the
boiler.
The indirect method provides a better understanding of the effect of individual losses on the boiler
efficiency and is used for boilers where the fuel heat flow is difficult to measure (eg. Biomass and
peat fired steam boilers).
129
References
1.
Khartchenko N. V. Advanced energy systems. Taylor & Francis 1998, U.S.
ISBN 1-56032-611-5
2.
DIN 1942 standard. "Abnahmeversuche an Dampferzeugern".
130
Thermal Design of Heat Exchangers
Sebastian Teir, Anne Jokivuori
STEAM BOILER TECHNOLOGY – Thermal Design of Heat Exchangers
Table of contents
General design issues .......................................................................................................................133
Heat transfer modes .....................................................................................................................133
Conduction ...............................................................................................................................133
Convection ...............................................................................................................................133
Radiation ..................................................................................................................................134
Pressure losses..............................................................................................................................134
Definition .................................................................................................................................134
Gas side pressure drop for inline tube arrangement.................................................................135
Gas side pressure drop for staggered tube arrangement ..........................................................135
Choice of tube surface..................................................................................................................136
Sizing of heat transfer surfaces ....................................................................................................136
Furnace design .................................................................................................................................137
Furnace strain level ......................................................................................................................138
Tube wall design ..........................................................................................................................139
Load characteristics......................................................................................................................140
Fuel type effect on furnace size ...................................................................................................140
Typical furnace outlet temperatures.............................................................................................140
Furnace air levels .........................................................................................................................141
CFB furnace design......................................................................................................................142
BFB furnace design......................................................................................................................143
Heat recovery steam generator (HRSG) design...........................................................................144
Furnace dimensioning, stirred reactor..........................................................................................146
Superheater design ...........................................................................................................................146
Design velocity ............................................................................................................................147
Design spacing .............................................................................................................................147
Tube arrangement ........................................................................................................................147
Economizer design...........................................................................................................................149
Design method .............................................................................................................................149
Air preheater design .........................................................................................................................151
References........................................................................................................................................152
132
General design issues
Heat transfer modes
Conduction
Conduction is the transfer of heat from one part of a body at a higher temperature to another part of
the same body at a lower temperature, or from one body at a higher temperature to another body in
physical contact with it at a lower temperature. The conduction process takes place at the molecular
level and involves the transfer of energy from the more energetic molecules to those with a lower
energy level.
Heat power [W] by conduction is:
Φ = λA
t1 − t 2
s
(1)
Heat power depends on the heat transfer area (A), temperature difference (t1-t2), thermal
conductivity of material (λ) and the thickness of separating wall (s). The thermal conductivity is a
property of the material; metals conduct well heat whereas gases not. An example of thermal
conductivities in various materials is shown in Table 1. [1]
Table 1: Thermal conductivities for various materials.
Material
Thermal conductivity [W/(m*K)]
Copper
370
Aluminium
210
Steel
45
Stainless steel
20
Insulations
0,03-0,1
Convection
Convection is heat transfer between a moving fluid or gas and a fixed solid. Convection can be
natural or forced: if a pump, a blower, a fan, or some similar device induces the fluid motion, the
process is called forced convection. If the fluid motion occurs as a result of the density difference
produced by the temperature difference, the process is called free or natural convection.
Heat power by convection can be calculated as:
Φ = α c A(t1 − t 2 )
(2)
The heat transfer coefficient αc varies much depending on e.g. flow velocity, type of fluid motion
and pressure. Heat transfer coefficients of liquids are much higher than those of gases, as can be
seen in the comparison presented in Table 2.
133
Table 2: Convection heat transfer coefficients for various fluids.
Fluid
Heat transfer coefficient [W/(m2K)]
Steady water
100-500
Water flow
500-10000
Water boiling
1000-60000
Steady air
3-15
Air flow
10-100
Radiation
Radiation, or more correctly thermal radiation, is electromagnetic radiation emitted by a body by
virtue of its temperature and at the expense of its internal energy. All heated solids and liquids, as
well as some gases, emit thermal radiation.
The importance of radiation heat transfer will increase, when the temperature becomes higher.
Radiation heat transfer is the main heat transfer mode for the furnace and radiation superheaters.
Emitted heat by radiation can be calculated as:
Φ r = ε fwσA(T f4 − Tw4 )
(3)
where εfw is the view factor between the flame and the water walls:
ε fw =
1
εf
+
1
1
εw
(4)
−1
where εf is the emissivity of the flame (typically 0.35-0.85), εw the emissivity of the water walls
(typically 0.6), σ the Stefan-Boltzmann constant (5.6787*10-8 W/m2K4), A the effective water wall
surface (m2), Tf the average gas temperature in the furnace and Tw the average water wall surface
temperature surrounding the flame.
Radiation heat can also be expressed as
Φ = α rad A(t1 − t 2 )
(5)
where αrad is the radiation heat transfer coefficient.
Pressure losses
Definition
The difference between pressure gage readings in parts of a system operating with a positive
pressure relative to that of the atmosphere is generally called pressure drop. The pressure drop on
the gas side is equal to the friction losses, according to VDI Wärmeatlas [1]:
∆p gs = ∆p f
(6)
134
Gas side pressure drop for inline tube arrangement
For inline tube arrangement the pressure drop coefficient for heat transfer surface with horizontal
tubes is:
∆p = n rζ r ∆p d
(7)
where nr is the number of tube rows in the heat transfer unit, ∆pd dynamic pressure calculated at
the gas side using the mean temperature and the smallest area. The single row pressure drop ξr for
inline tube arrangement is calculated as
ζ r = ζ l + ζ t (1 − e
−
Re−1000
2000
)
(8)
where
0.5
ζl =
280π (( s l − 0.6) 2 + 0.75)
1 .6
(4 s t s l − π ) s t Re
0.94 0.6 ⎤
⎡
(1 ) ⎥
⎢
sl
0.47(s t /s l -1.5)
⎢(0.22 + 1.2
⎥ + 0.03( s t − 1)( sl − 1)
ζ t = 10
(s t - 0.85) 1.3 ⎥
⎢
⎢⎣
⎥⎦
(9)
(10)
where ζ l is the laminar part of the pressure drop coefficient, ζ t is the turbulent part of the pressure
drop coefficient, s t is the dimensionless transverse pitch (s t = S t / d o ), s l is the dimensionless
longitudinal pitch ( s l = S l / d o ) and Re is the Reynolds number, calculated at the gas side mean
temperature and smallest area.
Gas side pressure drop for staggered tube arrangement
The single row pressure drop ζ r for staggered tubes is calculated similarly to inline tube
arrangement, with the following exceptions:
Re − 200
−
⎞
⎛
⎜
ζ r = ζ l + ζ t ⎜1 − e 1000 ⎟⎟
⎠
⎝
(
)
2
0.5
280π ⎛⎜ s l − 0.6 + 0.75 ⎞⎟
⎠
⎝
ζl =
1.6
(4st sl − π )c Re
where
c = st
; s l ≥ 2s t - 1/2
2
s
c = ( t ) 2 + s l ; sl < 2st − 1 / 2
2
(11)
(12)
(13)
135
3
⎞
⎛
⎛s
⎞
⎛s
⎞
1 .2
⎟ + 0.4⎜ l − 1⎟ − 0.01⎜ t − 1⎟
ζ t = 2.5 + ⎜⎜
1.08 ⎟
⎜
⎟
⎜
⎟
⎝ st
⎠
⎝ sl
⎠
⎝ (s t − 0.85 ) ⎠
3
(14)
Choice of tube surface
Surfaces used in tubular heat transfer units can be finned or unfinned (smooth surface). Heat
transfer properties can be improved using finned tubes, because the fins enlarge the tubular heat
transfer area.
The tubes in the economizer are usually finned,
because the heat transfer properties of the flue
gas side are not as good as on the water side.
Economizers are made of cast iron or steel
tubes. Cast iron tubes are easily equipped with
fins, but also steel tubes can be equipped with
fins. Finned tubes are more difficult to clean
than unfinned tubes, thus economizers with
unfinned steel tubes are used in boilers burning
fuels with a high ash content.
Figure 1, Figure 2, and Figure 3 provide some
examples on finned steel tubes. Spiral finned
tubes are often used in heat recovery steam
generators. By bending fins heat transfer
properties can also be improved. Steel tube with
aluminium fins endures better in corrosive
conditions. Compound composition conists of a
cast iron tube equipped with fins and steel tube
inside. A compound composistion endures
higher pressure.
Figure 1: Spiral finned tubes.
In air preheaters finned steel tubes are not used,
since the heat transfer properties are practically
the same on both air and flue gas sides. When
cast iron tubes are used, heat transfer surfaces
are usually finned on both sides to improve the
heat transfer.
Superheaters and furnaces use unfinned tubes.
Sizing of heat transfer surfaces
Figure 2: Finned tubes.
When sizing the heat transfer surface of a heat
exchanger the heat power to be transferred and
stream temperatures of inlets and outlets have to be known. The heat power is proportional to the
area of the heat exchanger, heat transfer coefficient and temperature difference (between the
streams):
Φ = kA∆Tlm
(15)
136
The mean logarithmic temperature difference in equation 15 can be calculated as:
∆Tlm =
∆Tmax − ∆Tmin
∆T
ln max
∆Tmin
(16)
where ∆Tmax is the largest temperature difference and ∆Tmin the smallest temperature difference:
∆Tmax = th1-tc2
∆Tmin = th2-tc1
(17)
where the inlet and outlet temperatures are
explained in Figure 4.
The heat surface area can be calculated from
equation 15, when temperatures and the heat
transfer coefficient have been determined, which
is the capability of the heat exchanger to transfer
heat between two fluids.
Figure 3: Parallel finned tube.
Figure 4: Heat exchanger stream descriptions
(for a cross-flow heat exchanger), used in
equation 17.
Furnace design
The main parameters for the furnace sizing are furnace dimensions (height, depth, width and
configuration), furnace wall construction and desired furnace outlet temperature.
The heat transfer surface area of furnace consists of sides, base and beak, which is an "L"-formed
bending of the evaporator tubes that protect the superheaters from radiation. Most of utility and
industrial boiler furnaces have a rectangular shape. A large number of package boilers have a
cylindrical furnace. Furnace bottom for typical PCF boiler is double inclined or v-form, as shown in
Figure 5. Flat bottom is more typical for grate and fluidized bed boilers.
The ratio of height and width varies 1-5 for boilers with two-pass layout. The larger the boiler is,
the larger is also the ratio. The largest boilers have a width of 20 m and a height of 100 m. The fuel
and vaporization efficiency determines the size of the furnace. To be able to dimension furnaces the
overall mass balance, heat balance and heat transfer must be specified.
137
The overall furnace (gas side) mass balance is
m& fg = m& air + ∑ m& fi − m& ash + m& sootb
(18)
where the streams are described in Figure 6.
∑ m& fi is the sum of all the fuel streams into the
h
boiler and m& sootb is the sootblowing steam. The
furnace heat balance can be specified similarly:
Φ fur = Φ net − Φ loss − Φ exit
εw
α dg + ε w − α dg ε w
− α dg Tw ) + α c ⋅ Aeff ⋅ (Tg − Tw )
V
(19)
where the heat fluxes are shown in Figure 7. If
the gas side temperatures and emissivities are
known, the furnace heat flux absorbed by the
furnace walls can be expressed as
Φ fur = Aeff ⋅ σ ⋅
A
4
⋅ (ε dg Tg
b1
b2
Figure 5: Furnace dimensions. The painted
areas are the total effective furnace heat
transfer area.
(20)
4
m& fg
where Aeff is the effective heat transfer surface,
σ the Stefan-Boltzmann constant, ε w and ε dg
the emissivity of the wall and the (dusty) gas
respectively, α dg the absorbability of the (dusty)
gas, α c the convective heat transfer coefficient,
and Tg and Tw the temperature of the gas and
wall respectively. The effect of convective term
is usually fairly small, often less than 10%.
Furnace strain level
The furnace is preliminarily dimensioned with a
suitable strain level. The volume (marked with a
“V” in Figure 5) strain level is calculated as the
following:
qV =
Φ fuel
b1b2 h
m& air
∑ m&
m& sootb
fi
m& ash
Figure 6: Fuel/flue gas side mass balance.
(21)
where Φ pa is the heat released from the fuel in the furnace and other variables furnace dimensions
according to Figure 5. The strain level depends largely on different fuels. Reference values on strain
levels from different fuels are presented in Table 3.
The area strain level is calculated as the heat power in the furnace per base area of the furnace
(marked with an “A” in Figure 5):
138
loss
Φ fuel
qF =
exit
(22)
b1b2
Table 3: Strain level effects of various fuels.
Fuel
Strain
[kW/m3]
Coal
145-185
Peat
~175
Oil, natural gas
290-690
fur
net
level
Figure 7: Furnace heat balance.
If the electric power of power plant is known, strain levels for the volume and base area can be
chosen from the graphs in Figure 8, and thereby the physical dimensions of the furnace can be
determined.
6
0,25
[MW/m3]
[MW/m2]
5
0,20
4
0,15
3
0,10
2
0,05
0
200
400
600 MWe
0
200
400
600
MWe
Figure 8: Charts for selecting strain levels of the furnace.
The effective heat transfer surface area of the furnace, consisting of sides, base and beak, can be
calculated as following (assuming the beak adds 0.4*base area):
EPRS ≈ 2lb1 + 2lb2
(23)
The first two terms forms the effective projected radiant surface (EPRS), which is a widely used
concept.
Tube wall design
When the size of the furnace has been dimensioned, the tube size and material can be chosen and
the wall thickness can be calculated according to the SFS 3273, DIN or another applicable standard.
Then input velocity of water to furnace is chosen and number of necessary tubes is calculated.
The diameter of an evaporator tube is usually 30-80 mm and the wall thickness can be calculated
from the following equation:
139
s=
du ⋅ p
+ C1 + C 2
⎞
⎛ σl
− p ⎟ ⋅ν + 2 ⋅ p
⎜2⋅
n
⎠
⎝
(24)
where du is the outside diameter of tube, p the design pressure, σ l the design strength, n a safety
factor (usually 1.5), ν the strength factor (usually 1.0), C1 an additional thickness, (normally 10%
of the wall thickness) and C2 an additional thickness considering corrosion.
Load characteristics
When designing a steam-generating unit it is necessary to determine the following load
characteristics:
1. Minimum, normal and maximum load
2. Time duration of each load rate
3. Load factor
4. Nature of the load (constant or fluctuating)
The load factor is the actual energy produced by a power plant during a given period, given as a
percentage (share) of the maximum energy that could have been produced at full capacity during
the same period.
The design will determine the boiler's ability to carry a normal load at a high efficiency as well as to
meet maximum demand and rapid load changes. It will also determine the standby losses and the
rapidity with which the unit can be brought up to full steaming capacity. In smaller boiler sizes it is
possible to select a standardized unit that will meet the requirements; larger units are almost always
custom designed.
Fuel type effect on furnace size
The most important item to consider when designing a utility or large industrial steam generator is
the fuel the unit will burn. The furnace size, the equipment to prepare and burn the fuel, the amount
of heating surface and its placement, the type and size of heat recovery equipment, and the flue gas
treatment devices are all fuel dependent. The major differences among boilers that burn coal,
biomass, oil or natural gas result from the ash in combustion products.
Firing oil in the furnace produces relatively small amounts of ash. Natural gas produces no ash. For
the same power output, due to larger volumetric flue gas flow, coal-burning boilers must have
larger furnaces. The velocities of the combustion gases in the convection-based heat exchangers
must be lower, due to the high ash content of coal. Figure 9 presents an example of the relative sizes
of furnaces using three different fuels: natural gas, oil and coal. The power of the boiler is the same
in all three cases. Peat, biomass and recovery boilers are even bigger than coal fired boilers.
Typical furnace outlet temperatures
Furnace outlet temperature is the flue gas temperature after the radiation-based heat transfer
surfaces before entering the convection-based heat transfer surfaces. The outlet temperature
depends on the characteristics of the combusted fuel. If the temperature is too high, ash layers build
up on the surface of the superheater tubes. This leads to poorer heat transfer, increased corrosion
and it can even block flow paths.
140
Coal
Natural gas
Oil
1,5*h
1,2*h
h
b1
b2
1,05*b1
1,06*b2
1,1*b1
1,12*b2
Figure 9: Boiler fuel type effect on furnace size.
The following factors affect the choice of furnace outlet temperature:
•
•
•
•
Ash characteristics; the control of ash behaviour at superheaters is a key design parameter
Fuel (gas and oil have low ash content and can have higher outlet temperatures)
Choice of superheater material
Desired superheating temperature
Table 4 presents some typical furnace outlet temperatures.
Table 4: Typical furnace outlet temperatures on various boiler types.
Fuel type
Furnace outlet temperature [°C]
Biomass, circulating fluidized bed
900 - 1000
Peat, pulverized firing
950 - 1000
Coal, high volatiles
950 - 1000
Recovery boiler
900- 1050
Biomass, fluidized bed
1050 - 1150
Natural gas
900- 1200
Oil
900- 1200
Furnace air levels
The type of fuel determines the quantity of air required for combustion. It is necessary to provide air
in excess of this quantity to assure complete combustion. The amount of this excess air is
determined by the following factors:
1. Composition, properties, and condition of fuel when fired
2. Method of burning the combustible
141
3. Arrangement and proportions of the grate or furnace
4. Allowable furnace temperature
5. Turbulence and thoroughness of the mixing of combustion air and volatile gases
Excess air reduces efficiency by lowering the furnace temperature and by absorbing heat that would
otherwise be available for steam production.
NOx is formed when nitrogen of air reacts with oxygen of air in high temperature, over 1400°C.
NOx can be reduced decreasing temperature, decreasing air excess, or using low-NOx-burners. In
using low-NOx-burner air will be fed into flame in two or three phases.
CFB furnace design
When dimensioning a circulating fluidized bed (CFB) furnace the high content of sand has to be
taken into consideration. This means that the temperature profile and thus the heat transfer near to
the furnace wall differs from other types of furnaces.
The furnace of a CFB (circulating fluidized bed) boiler contains a layer of granular solids, which
have a diameter in the range of 0.1-0.3 mm. It includes sand or gravel, fresh or spent limestone and
ash. The operating velocity of the flue gas stream in a CFB boiler is 3-10 m/s. The solids move
through the furnace at much lower velocity than the gas; solids residence times in the order of
minutes are obtained. The long residence times coupled with the small particle size produce high
combustion efficiency and high SO2 removal with much lower limestone feed than in conventional
furnaces. Figure 10 shows a flow chart of a typical CFB boiler.
After the furnace flue gas moves through a cyclone (named compact separator in Figure 10), where
solids are separated from the gas and are returned to the furnace. Flue gas from the cyclone
discharge enters the convection back-pass in which the superheaters, reheaters, economizers and air
preheaters are located. A dust collector separates the fly ash before the flue gas exits the plant. The
combustion air from the fan pneumatically transports the solids for creating the circulating fluid.
The design of the furnace in a CFB boiler depends on:
•
•
•
required velocity of gas
time of complete combustion of fuel
heat required for vaporization.
The amount of cyclones also has an influence on the shape of furnace. Flue gas must flow to the
cyclone fast enough (20 m/s), and the diameter of the cyclone must be below 8 m in order to get an
efficient removal of solids.
Circulating fluidized bed boilers have a number of unique features that make them more attractive
than other solid fuel fired boilers. Fuel flexibility is one of the major attractive features of CFB
boilers. A wide range of fuels can be burned in one specific boiler without any major change in the
hardware. The combustion efficiency of a CFB boiler is high. It is generally in the range of 99,5 to
97,5 %. Sulphur capture in a CFB is very efficient, due to the possibility to inject sulphur absorbing
limestone directly into the bed. A typical CFB boiler can capture 90 % of the sulphur dioxide. The
low emission of nitrogen oxides is also a major attractive feature of CFB boilers.
CFB furnace design is explained in detail in the chapter about CFB boiler design.
142
Steam Outlet
Steam
Foster Wheeler CFB
Flow Chart
Water
Steam Drum
Downcomer
Water
Wall
Fuel
Limestone
Compact
Separator
Economizer
Air
heater
Feed Water Inlet
Dust Collector
Combustion
Chamber
Fly Ash
compact.eng/comflow.ds4/0801/tap
Bottom
Ash
Secondary Air Fan
To Ash Silos
Induced Draft
Fan
Primary Air Fan
Figure 10: Flow chart of a CFB boiler. [2]
BFB furnace design
Bubbling fluidized bed (BFB) boilers use a low
fluidizing velocity, so that the particles are held
mainly in a bed, which have a depth of about 1
m and a definable surface. Sand is often used to
improve bed stability, together with limestone
for SO2 absorption. As the coal particles are
combusted and become smaller, they are
elutriated with the gases, and subsequently
removed as fly ash. In-bed tubes are used to
control the bed temperature and generate steam.
The flue gases are normally cleaned using a
cyclone, and then pass through further heat
exchangers, raising steam temperature.
In the furnace (Figure 11 and Figure 12) of a
BFB boiler size of a grain of sand is about 1-3
mm and the operating velocity is 0.7-2 m/s. Fuel
is fed onto the bed mechanically. Thanks to the
large heat capacity of the bed, a BFB furnace is
able to burn very moist fuel. Moist fuel will dry
fast, when it is fed to the sand bed. Many
Figure 11: Inside a BFB boiler furnace. [4]
143
different kinds of fuels can be combusted in a
BFB furnace. The wall area covered by the bed
is free from water tubes, in order to protect the
tubes from excessive erosion (Figure 11). This is
called a refractory lining.
The temperature of a BFB furnace outlet is 700900°C, and the air factor is usually 1.1-1.4. Air
is fed in several phases. The temperature of air
varies from 20 to 400°C. The overall thermal
efficiency of a BFB boiler power plant is around
30%.
BFB furnaces with an atmospheric operational
pressure are mainly used for boilers up to about
25 MWe, although there are a few larger plants
where a BFB boiler has been used to retrofit an
existing unit.
Heat recovery steam generator
(HRSG) design
Heat recovery steam generators (HRSGs) are
used in power generation to recover heat from
hot flue gases (500-600 °C), usually originating
from a gas turbine or diesel engine. The HRSG
consists of the same heat transfer surfaces as
other boilers, except for the furnace. Since no
Figure 12: BFB-boiler, Härnösand
fuel is combusted in a HRSG, the HRSG have
Energi&Miljö Ab. [3]
(instead of a furnace) convention based
evaporator surfaces, where water evaporates into
steam. However, a HRSG can be equipped with a supplementary burner (as can be seen in Figure
13) for raising the flue gas temperature. A HRSG can have a horizontal or vertical layout,
depending on the available space.
When designing a HRSG, the following issues should be considered:
•
•
•
the pinch-point of the evaporator and the approach temperature of the economizer
the pressure drop of the flue gas side of the boiler
optimization of the heating surfaces
The pinch-point (the smallest temperature difference between the two streams in a system of heat
exchangers) is found in the evaporator, and is usually 6-10°C, which can be seen in Figure 14. To
maximize the steam power of the boiler, the pinch-point must be chosen as small as possible. The
approach temperature is the temperature difference of the saturation temperature in the evaporator
and the output of the economizer. This is often 0-5°C. The pressure drop (usually 25-40 mbar) of
the flue gas side has also an effect on the efficiency of power plant. The heat transfer of the HRSG
is primarily convective. The flow velocity of the flue gas has an influence on the heat transfer
coefficient.
144
The evaporator of heat recovery boiler can be of
natural or forced circulation type. The heat
exchanger type of the evaporator can be any of
parallel-flow, counter-flow or cross-flow. In
parallel-flow arrangement the hot and cold fluids
move in the same direction and in counter-flow
heat exchanger fluids move in opposite
direction.
Flue Gas
OUT
Feedwater
IN
Economizer
Evaporator
Heating surfaces of a heat recovery steam
generator are usually heat transfer packages,
which consist of spiral-finned tubes. The
thickness of the fin is 1-2 mm, the height 8-16
mm and the fin distance 3.2-8 mm. Tube sizes
vary a lot.
Superheater
HP Steam
OUT
Fuel
IN
Supplementary burner
Flue Gas
IN
Figure 13: Process scheme of single-pressure
HRSG with a supplementary burner.
700
Flue gas stream
Water/steam stream
600
Temperature [°C]
500
400
300
200
100
Superheater
Evaporator
Economizer
0
0%
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %
100 %
Figure 14: Example of a heat load graph for a HRSG boiler.
145
Furnace dimensioning, stirred reactor
One of the most used furnace dimensioning methods is the stirred reactor model. The furnace is
approximated as being filled with a homogenous three-atom gas and a dust mixture at a uniform
temperature and pressure. At the furnace exit the temperature is decreased by a specified amount.
The stirred reactor furnace dimensioning process is as follows:
1. Guess initial furnace dimensions; shape, height, width, depth
2. Guess furnace exit temperature, Texit
3. Calculate heat transfer using flue gas temperature Tfg = Texit+∆T
4. Calculate furnace exit temperature from heat balance with calculated heat transfer
5. If the mode does not converge, then return to step 2
6. If the calculated furnace exit temperature differs from the desired one, return to step 1
The typical values of ∆T to use for the different types of furnaces can be seen in Table 5. The stirred
reactor model is not optimal for designing a recovery boiler furnace.
Table 5: Typical values of ∆T for various types of furnaces.
Boiler type
∆T [°C]
PCF (molten), coal
200 (100-300)
PCF (dry), coal
180 (100-250)
Grate firing, coal
130 (100-180)
PCF, lignite
120 (100-150)
Oil and gas
150 (100-200)
BFB
130 (100-150)
CFB
0
Superheater design
The production of steam at higher temperature than the saturation temperature is called
superheating. The temperature added to the saturation temperature is called the degree of superheat.
Superheated steam has no moisture; hence it is less erosive and corrosive than wet saturated steam
carrying droplets. In order to have a sustainable turbine operation, the steam cannot contain any
moist at all.
The design procedure for a superheater can be divided into the following steps:
•
•
•
•
•
•
•
•
Tube size and material are chosen. Wall thickness is calculated.
Flow velocity in tube is chosen, number of tubes is calculated, tube construction and width
of heat exchanger are chosen.
Height of heat exchanger is calculated according to the chosen flue gas velocity.
Internal heat transfer coefficient (for the inside, water side of the tube) is calculated.
External heat transfer coefficient (for the outside, gas side of the tube) is calculated.
Thermal resistance of dirt layer is calculated.
Thermal resistance/tube length is calculated.
Conductance is calculated
146
•
•
•
•
•
•
Necessary tube length is calculated.
Necessary number of passages is calculated.
Assumed values are iterated.
Main dimensions are calculated.
Inside and outside pressure losses are calculated.
Heat exchangers are drawn to the technical drawing of boiler.
Design velocity
Superheaters transfer heat from flue gas to steam (gas phase of water). Heat transfer between two
gases is not very effective compared to heat transfer from gas to fluid. For that reason, steam must
flow fast enough (10-20 m/s) in order to give the superheater tubes enough cooling. Lower steam
pressure weakens the heat transfer rate, so with lower pressures, steam must have a greater velocity
(15-40 m/s).
When flue gas is cooled, its volume decreases. In order to keep a constant flow rate of the flue gas,
the cross-sectional flow area decreases as well. In the radiant superheater, the velocity of gas is very
small (< 5 m/s). In the convection superheater, the velocity can be quite large (15-30 m/s). The
maximum velocity depends on the fuel used. To limit pressure-part erosion from fly ash, the flue
gas velocity must not exceed certain limits. Depending upon the ash quantity and abrasiveness, the
design velocity is generally 16-18 m/s. A furnace that burns coals yielding a heavy loading of
erosive ash (usually indicated by a high silica/aluminium content) may have a design velocity of
approximately 15 m/s. Such velocities are based on the predicted average gas temperature entering
the tube section, at the maximum continuous rating of the steam generator fired at normal excess-air
percentage.
Design spacing
Superheater of boiler consists of banks of tubes. A system of tubes is located in the path of the
furnace gases in the top of furnace. Heat transfer in superheaters is based mainly on radiation, but in
the primary superheaters convection often plays a major role.
A superheater must be built so that it superheats approximately the same amount of steam from low
to high loads. This can be achieved by a proper choice of radiative and convective superheating
surfaces. Changing tube lengths between passes can control temperature differences. The outermost
tube that receives the most radiative flux should be shorter than the rest of the tubes. Proper
superheater arrangement also eliminates much of the problems with uneven or biased flue gas flow.
Figure 15 and Figure 16 shows examples of the arrangement of superheater and reheater surfaces in
the form of a process scheme.
Tube arrangement
Tubes in superheaters can be arranged according to inline or staggered arrangement (Figure 17).
Inline tube arrangement is preferred for fouling, PCF, bark and recovery boilers. Staggered
arrangement is preferred for oil, gas and heat recovery steam generator. As free space with
staggered arrangement is much smaller than with inline arrangement the reason for decreased
fouling with inline is evident. The heat transfer for a staggered arrangement is better than for an
inline arrangement.
The superheater tube diameter is usually 30-50 mm. For convection heat surfaces the dimension ‘a’
(Figure 17) is 80-200 mm and ‘b’ is 60-150 mm. For radiation heat surfaces ‘a’ is over 500 mm
and ‘b’ is approximately the same as the external tube diameter.
147
Superheated
Steam OUT
Feedwater
IN
Saturated
Steam IN
Superheater II
Superheater III
Superheater I
Figure 15: An example of superheater block arrangements.
Superhe ated
Steam OUT
Reheated
Steam OUT
Feedwater
IN
Reheater
IN
Saturated
Steam IN
Reheater I
Superheater I
Reheater II
Superheater III
Superheater II
Figure 16: An example of superheater and reheater block arrangements.
The number of tubes in the superheater is calculated according to the average flow velocity and
volume flow. In the convection superheater the width of the superheater is the same as the width of
the furnace. When the number of tubes is known, all tubes are preliminarily placed next to each
other in the flue gas channel. If the cross-sectional area of the flue gas pass between two tubes
(dimension ‘a’ in Figure 17) becomes too small, the tubes have to be placed in two or more rows.
148
Inline
Clear lane
b
a
Direction of gas flow
b
Staggered
Figure 17: Inline and staggered tube arrangement.
Economizer design
An economizer consists of an arrangement of tubes through which the feed water is passed
immediately before entering the boiler. The combustion gases leaving the boiler convection
surfaces pass over these tubes. As the entering feed water has a lower temperature than that of the
boiler steam, the heat transfer is more effective at this point than in the convection surfaces of the
boiler. This fact has prompted the present trend in boiler design to increase the economizer surface
and proportionally decrease the evaporator heating surface. Economizers can be made of cast iron
or steel tube. Finned tubes are used, unless the flue gases origins from fuels with high ash content.
Design method
The following variables will be chosen
•
Inside and outside tube diameters di and do, from which we can calculate the wall thickness:
d − di
(25)
δ = o
2
• Distance of tubes in direction of flow and in side direction: s1 and s2 (named ‘a’ and ‘b’ in
Figure 17)
• The size of flue gas channel: b1 and b2
The number of tubes in one row (counter-flow) can then be calculated as:
M =
b2
s2
(26)
The cross-sectional area of the flue gas channel can then be calculated from equation 27.
Afg = b1b2 – Mdob1
(27)
149
Holes of flow-through area combined circle are:
U = (M+1)*(2* b1-2*(s1- do))
(28)
The hydraulic diameter can then be calculated as:
dh =
4 ⋅ A fg
(29)
U
Then s1/do, s2/do, C and m can be read from charts. [5]
The average flue gas temperature of the economizer is:
Tf =
T fg sup + T fgeco
(30)
2
The outside convection heat transfer coefficient is calculated from the following equation (turbulent
gas flow):
Nu =
α oc d h
= C ⋅ Re m ⋅ Pr 0,31
λ fg
-> α oc =
λ fg
dh
⋅ C ⋅ Re m ⋅ Pr 0,31
(31)
where λfg is the thermal conductivity of the flue gas, Pr is Prandtl number, of flue gas, αo the
outside convectional heat transfer coefficient and Re Reynolds number, which can be calculated as:
Re =
d h ⋅ w fg
(32)
ν
where wfg is the flue gas velocity in the flue gas channel, dh the hydraulic diameter of the channel
(Equation 30) and ν the cinematic viscosity of flue gas.
The needed tube surface area in the economizer can then be calculated as:
A=
G
k
(33)
where G is the conductance (kW/K) and k the heat transfer coefficient, which can be calculated
according to equation 35:
d
1
1
δ
= o +
+
k d iα i α o ⎛
δ
⎜⎜1 −
⎝ do
⎞
⎟⎟ ⋅ λ
⎠
+ mdirt
(34)
150
where di and do are the inside and the outside tube diameter [m] respectively, αi and αo the inside
and outside heat transfer coefficient respectively, δ the tube wall thickness, λ the thermal
conductivity and mdirt the heat transfer resistance of a tube with a dirt layer on its surface. The
outside heat transfer coefficient is the sum of the outside radiative and convective heat transfer
coefficients:
αo = αoc + αrad
(35)
The surface area of one tube is:
At = π* do*b1
(36)
The number of tube rows in depth direction is:
N=
A
At ⋅ M
(37)
And the depth of the economizer is:
he = N* s1
(38)
Air preheater design
Recuperative air preheater design is similar to other convective heat transfer surfaces. The tubes of
air preheaters are larger than the tubes of superheaters and economizers: the diameter is about 50-80
mm.
Wall thickness is sized according to the strength of the construction, because the pressure difference
between air and flue gases is small. The flue gas velocity in the air preheater is 10-14 m/s in the
tubular heat exchanger type, 9-13 m/s in the plate heat exchanger type, 10-11 m/s in a finned tube
heat exchanger, and 13-15 m/s if both sides of the heat exchanger are finned.
In a vertical tube heat exchanger flue gas flows inside tubes and number of tubes can be chosen
according to the flue gas velocity and volume flow. By choosing suitable tube divisions, dimensions
of horizontal cross section of heat exchanger can be calculated. Air is flowing horizontally outside
tubes. By choosing air velocity height of heat exchanger can be calculated. According thermal
sizing length of heat exchanger can be found. In horizontal tube heat exchanger air flows inside
tubes and number of tubes can be chosen according to the air velocity and volume flow.
Regenerative air preheaters are usually made of enamel coated ceramic elements. This is popular,
because ceramics are non-combustibles and have a low low-temperature corrosion rate. Another
option is metallic dimple elements. Metallic elements have higher efficiency, require lower height
and have lower pressure drop. Problems are a possible high corrosion rate of metallic elements.
151
References
1. VDI Wärmeatlas.
2. Pictures and schematics supplied by Foster Wheeler. http://www.fwc.com/
3. Picture supplied by Härnösand Energi&Miljö Ab, Fortum. http://www.fortum.com
4. Photograph by Rintala T., Fortum. http://www.fortum.com
5. Alvarez H. Energiteknik del 1 and Energiteknik del 2. Studentlitteratur, Lund. 1990. p. 368
6. M. Huhtinen, A. Kettunen, P. Nurminen, H. Pakkanen, Höyrykattilatekniikka, Oy Edita Ab,
Helsinki 1994, ISBN 951-37-1327-X
7. Opetusmoniste kevät 2000: Ene-47.110 Yleinen energiatekniikka, erä 1, HUT
8. Opetusmoniste kevät 2000: Ene-47.124 Höyrykattilatekniikka, erä 1, HUT
9. Opetusmoniste kevät 2000: Ene-47.124 Höyrykattilatekniikka, erä 2, HUT
10. V. Meuronen, 4115 Höyrykattiloiden suunnittelu, Opetusmoniste 1999, LTKK, ISBN 951764-382-9
11. Combustion Engineering. Combustion: Fossil power systems. 3rd ed. Windsor. 1981.
12. Vakkilainen E. Lecture slides and material on steam boiler technology. 2001.
152
Circulating Fluidized Bed Boilers
Dianjun Zhang, Sebastian Teir
STEAM BOILER TECHNOLOGY – Circulating Fluidized Bed Boilers
Table of contents
Introduction to fluidized bed boilers................................................................................................155
Fluidized bed principles ...............................................................................................................155
Basic principles of CFB boilers ...................................................................................................157
Characteristics of CFB systems ...................................................................................................159
The advantages of CFB boilers....................................................................................................160
Combustion in CFB boilers .............................................................................................................161
Fuel flexibility..............................................................................................................................162
Combustion zones in a CFB boiler ..............................................................................................162
Heat transfer in a CFB boiler ...........................................................................................................163
Bed to wall heat transfer ..............................................................................................................163
Bubbling bed to external heat surfaces ........................................................................................164
Heat transfer and part-load operation...........................................................................................164
Load control in CFB boiler ..........................................................................................................165
Emissions .........................................................................................................................................165
SO2 Emissions..............................................................................................................................165
NOx - emissions...........................................................................................................................166
Particulate matter (PM) emission.................................................................................................168
Carbon monoxide and hydrocarbons ...........................................................................................168
References........................................................................................................................................169
154
Introduction to fluidized bed boilers
In order to control emission levels from coal combustion, advanced combustion technologies and
pollutant capture technologies are utilized. Pulverized coal (PC) combustion with flue gas cleaning
using a desulfurization plant, including bag-house filters for desulfurization and electrostatic
precipitators for fly ash, is the commonly used technology. But one of the shortages of PC boilers is
that high combustion temperature in the furnace causes high NOx formation. During the recent
decades, fluidized bed combustion (FBC) has been developed and put into use rapidly due to its
good features, such as SO2 removal during combustion, low NOx emissions and multi-fuel
flexibility.
The fluidization process was invented by Fritz Winkler in 1921. The process used for coal burning
was developed and promoted by Douglas Elliott in 1960s. After that Lurgi of Germany and
Alhlström Group in Finland developed FBC further. Foster Wheeler, Babcock & Wilcox, and Lurgi
are currently the largest FBC boilers manufacturers.
Fluidized bed boilers can be categorized into three main types, bubbling fluidized bed (BFB),
atmospheric circulating fluidized bed (ACFB, commonly referred to as CFB), and pressurized
circulating fluidized bed (PCFB). This chapter will focus on CFB boilers.
Fluidized bed principles
Fluidization is a phenomenon where fine solids are transformed into a fluid-like state through
contact with a fluid, either gas or liquid. Under the fluidized condition, gravitational forces on
granular, solid particles are offset by the fluid drag on them. Thus, the particles remain in a semisuspended condition and take on many of the physical characteristics of a fluid.
As the gas velocity increases through a bed of particles many changes occur in the gas/solid contact
mode. At low velocities the gas is essentially flowing through a fixed bed of particles, while at high
velocities the solids are entirely entrained in the gas stream. When comparing various combustion
technologies, stoker-fired boilers operate with a fixed bed, while pulverized boilers operate with
solids completely entrained. The furnace of a CFB boiler operates in a regime somewhere between
these two extremes.
The principle of fluid bed systems can also be explained by examining the relationship between
differential gas pressure across a bed of particles and the superficial gas velocity through that bed
(Figure 1).
For a fixed bed, the log of differential pressure is proportional to the log of gas velocity and
represents the frictional pressure drop of the gas through the bed.
As the gas velocity increases beyond the minimum fluidization velocity, the bed begins to expand
and the particles become fluidized. A distinct bed level is visible in the fluid bed. As the gas flow
rate through the fixed bed increases, the pressure drop continues to rise until the superficial gas
velocity reaches the critical minimum fluidization velocity, Umf.. At that point the gravitational
forces are overcome by the buoyant drag forces on the particles and they become suspended (i.e.,
fluidized). The minimum fluidizing velocity depends on many factors including particle diameter,
gas and particle density, particle shape, gas viscosity, and bed void fraction. The following formula
calculates the minimum fluidizing velocity:
155
U mf =
µs
d p ρs
⎡
⎤
d p ρs (ρ g − ρ s )g
− 33.7 ⎥
⎢ 33.7 2 + 0.0408
2
µg
⎢⎣
⎥⎦
(1)
where
µg
dp
ρg
ρp
g
is dynamic viscosity
is particle diameter
is gas density
is particle density
is acceleration of gravity
FIXED BED
BUBBLING
MIN FLUID
VELOCITY
TURBULENT
ENTRAINMENT
VELOCITY
CIRCULATING
PARTICLE
MASS FLOW
∆p
(LOG)
VELOCITY (LOG)
Figure 1: Regimes of fluidized bed systems. [1]
At velocities above Umf, the pressure drop through the bed remains constant and equals the weight of
solids per unit area as the drag forces on the particles barely overcome gravitational forces. The
following equation shows the pressure drop:
∆p = ( ρ g − ρ s )(1 − ε ) gH
(2)
where
ρg
ρp
ε
g
is gas density
is particle density
is ratio of empty volume in bed
is acceleration of gravity.
156
As gas velocity is further increased above the minimum fluidization velocity, the differential
pressure remains almost constant until the bed material begins to elutriate at the entrainment
velocity of the so-called bubbling bed. The degree of turbulent mixing of the solids continues to
increase between the minimum fluidization and the entrainment velocity.
Beyond the entrainment velocity or the terminal velocity, the particles are carried out of the vessel
and an inventory of particles can only be maintained by collecting and recirculating the entrained
particles back to the vessel or by adding additional solid particles. The entrainment velocity marks
the transition from a bubbling bed to a circulating bed. Beyond this velocity, the differential
pressure becomes a function of velocity and solid recirculation rate. The terminal velocity for a
fluidized bed can be calculated as
Ut =
4 d p (ρ p − ρ g )
g
ρ g Cd
3
(3)
where Cd is the drag coefficient.
In the context of its use in power generation, the circulating fluidized bed may be defined as a high
velocity gas-solid suspension where particles are elutriated by the fluidizing gas. The particles are
recovered and returned to the base of the furnace at a rate high enough to cause a degree of solid
refluxing that will insure a uniform temperature level in the furnace.
The CFB mode of fluidization is characterized by a high slip velocity between the gas and solids
and by intensive solids mixing. High slip velocity between the gas and solids, encourages high
mass transfer rates, that enhance the rates of the oxidation (combustion) and desulfurization
reactions, critical to the application of CFBs to power generation. The intensive mixing of solids
insures adequate mixing of fuel and combustion products with combustion air and flue gas
emissions reduction reagents. [1]
Basic principles of CFB boilers
A Circulating Fluidized Bed (CFB) operates under a special fluid dynamic condition, in which the
fine solids particles are transported and mixed through the furnace at a gas velocity exceeding the
average terminal velocity of the particles. The major fraction of solids leaving the furnace is
captured by a solids separator and recirculated back to the lower part of the furnace. The high
recycle rate intensifies solids mixing and evens out combustion temperatures in the furnace.
Figure 2 and Figure 3 shows a schematic diagram of a CFB boiler. The boiler can be divided into
two sections. The first section consists of the furnace, solid separator, recycle device, and possible
external heat exchanger surfaces. The second section of the boiler is called back-pass where the heat
of the high temperature flue gas is absorbed by the reheater, superheater, economizer, and airpreheater, which are installed one after one in downstream order.
Coal and limestone (sorbent for SO2 capture) is injected from the lower part of the furnace into the
sand bed. The injected coal and limestone is fluidized by primary air (less than stoichiometrical
amount) entering the furnace through an air distributor or grate in the furnace floor. Coal is heated
by hot segregated particles in the bed above its ignition temperature so that it can be burnt. The
sulfur in the coal reacts with limestone, thus lowering the possibility of SO2 formation and
157
emissions from the furnace. Secondary air is injected at some height above the grate to complete the
combustion.
Bed solids are well mixed throughout the height of the furnace to ensure the uniform bed
temperature in the range of 800-900°C. Some particles segregate and return to the bed before
leaving the furnace, while some particles are captured in a gas-solid separator (e.g. cyclone) and are
recycled back to the furnace (Figure 4). The separator is designed for a very high solid collection
efficiency with nearly 100% efficiency for particles greater than 60 microns in diameter.
Furnace and
cyclone
Backpass
Cyclone
Superheaters
and reheaters
Furnace
Economizer
Secondary
air supply
Air
preheater
Recycling of
solids
Primary air
supply
INTREX
Superheater
MÄLARENERGI AB
VÄSTERÅS, SWEDEN
Figure 2: Shematics of a CFB boiler (157 MWth, 55.5/48 kg/s, 170/37 bar, 540/540 °C). [1]
Finer dust that escapes from the separator is collected by bag-house filters or electrostatic
precipitators (Figure 3), which are installed downstream after the boiler.
The collected solids are returned to the combustion chamber via the loop seal, which provides a
pressure seal between the positive pressure in the lower furnace and the negative draft in the solids
separator. This prevents the furnace flue gas from short circuiting up the separator dipleg and
collapsing the separator collection efficiency. The recirculation system has no moving parts and its
operation has proven to be simple and reliable. By injecting small amounts of high pressure
fluidizing air into the loop seal, the solids movement back to the lower furnace is maintained.
Typically gravity / mechanical feeding of fuel directly into the combustor have proven satisfactory
for meeting the desired level of efficient mixing.
158
Superheaters
and reheaters
Furnace
(water walls)
External heat
transfer surfaces
Economizer
Air
preheater
Electrostatic
precipitator
Figure 3: CFB boiler in Rovaniemi, Finland (95.8 MWth, 38 kg/s, 115 bar, 535°C). [1]
Characteristics of CFB systems
CFB systems operate in a fluid dynamic region
between that of a Bubbling Fluidized Bed (BFB)
and a transport reactor (pulverized combustion).
This fluidization regime is characterized by high
turbulence, solid mixing and the absence of a
defined bed level. Instead of a well defined
solids bed depth, the solids are distributed
throughout the furnace with a steadily
decreasing density from the bottom to the top of
the furnace.
CFB is characterized by:
•
•
•
•
High fluidizing velocity of 4.0-6.0 m/s.
Dense bed region in lower furnace
without a distinct bed level
Water-cooled
membrane
walls
(evaporator).
Optional in-furnace heat transfer surfaces
located above the dense lower bed
Figure 4: Cutaway of a CFB furnace and
cyclone. [3]
159
•
•
Solids separator to separate entrained particles from the flue gas stream and recycle them to
the lower furnace.
Aerated sealing device, loop seal, which permits return of collected solids back to the
furnace
The advantages of CFB boilers
Compared with PC boilers, CFB boilers have a number of unique features that make them more
attractive in energy production. Table 1 compares different types of boilers with CFB boilers.
Extensive fuel flexibility: In the furnace bed, fuel particles constitute less than 1-3% by weight of all
bed solids. The rest are non-combustibles, such as sorbents, flue ash and sand. This feature makes
CFB boilers flexible enough to use a wide range of fuels, coal (with ash content up to 40-60%),
peat, bark, wood waste, and straw.
High combustion efficiency: Normally the combustion efficiency of CFB boilers is 97.5-99.5%. The
good result is due to the following factors:
•
•
•
•
Good gas-solid mixing.
High burning rate.
Long combustion zone (40m).
The majority of unburned fuel particles are recycled back to the furnace and combusted.
Efficient sulfur removal: The long combustion zone in the furnace gives a long reaction time for the
sorbents to react with SO2. The average residence time of gas in the combustion zone is 3-4
seconds. The furnace temperature of CFB boilers is also ideal for the capture of sulfur (850°C
optimal). SO2 reacts with CaO in calcined sorbents and forms calcium sulfate. SO2 removal during
combustion is much cheaper and simpler than flue gas desulfurization.
Table 1: Comparison of boiler types.
1)
Items
Height of bed of fuel burning
zone (m)
Superficial velocity m/s
Excess air %
Grate heat release rate MW/m2
Coal size mm
Turndown ratio
Combustion efficiency %
NOx emission ppm
SO2 capture in furnace %
Stoker boilers
0,2
BFB boilers
1-2
CFB boilers
15-40
PC boilers
27-45
1,2
20-30
0,5-1,5
32-6
4:1
85-90
400-600
None
1,5-2,5
20-25
0,5-1,5
6-0
3:1
90-96
300-400
80-90
4-8
10-20
3-5
6-0
3-4:1
95-99
50-200
80-90
4-6
15-30
4-6
<0,001
2:1 1)
99
400-600
small
Turndown ratio can be bigger using supporting oil firing.
Low NOx emission: Low emission of NOx is a major attractive feature of CFB boilers. Combustion
air in stages (primary and secondary air) and low combustion temperature in the limits the
formation of NOx. This is a major advantage of CFB boilers compared to PC boilers.
160
Compact structure: Due to the high combustion efficiency and high heat release rate at 3.54.5MW/m2, the cross section area of furnace is quite small compared to the furnaces of bubble
fluidized bed boilers, and is close to the area of PC boiler furnaces. Therefore, fewer coal-feeding
points are needed. Normally a 100MWth CFB needs only one feeding point, while BFB boiler
needs 20 to 30 points for the same capacity. This makes retrofitting of existing PC boilers or oil
fired boilers into CFB boilers for suitable.
Good turndown and load following capacity: One good feature of the CFB boiler is its quick
response to varying loads: approximately 4% of its capacity per minute. The output turndown ratio
can be 3-4:1. Thus CHP plants with CFB boilers can be used as base load plants or peak load plants.
Typical operating parameters for CFB boilers is shown in Table 2.
Table 2:Typical operating parameters for CFB boilers. [4]
Volume heat load
Cross section heat load
Total pressure drop
Bed material particle size
Fly ash particle size
Bottom ash particle size
Fluidizing velocity
Temperature of primary air
Temperature of secondary air
Bed temperature
Temperature after the cyclone
Excess air ratio
Density of bed
Recirculation ratio
0.1–0.3 MW/m3
0.7–5 MW/m2
10–15 kPa
0.1–0.5 mm
< 100 µm
0.5-10 mm
3–10 m/s
20–400 °C
20–400 °C
850–950 °C
850–950 °C
1.1–1.3
10–100 kg/m3
10–100
Combustion in CFB boilers
The research of combustion in CFB boilers mainly focus at receiving good combustion efficiency
since it impacts operation cost. In addition to time, temperature, and turbulence, which impacts
combustion efficiency, the excellent internal and external re-circulation of hot solids at combustion
temperature provides a longer residence time and good heat transfer to heating surfaces. Besides,
high efficiency of combustion can also ensure efficient SO2 capture during the combustion.
In typical full load operation, about 40-50% of the heat generated by combustion is absorbed by the
water-cooled membrane walls of the combustion chamber. Also, the high circulating solids and
back-mixing intensity provide the high heat transfer rate typical of circulating fluidized beds.
Typically, a CFB furnace operates at a temperature level of 800-900°C. The reasons are:
•
•
•
•
Low combustion temperature prevents sand and ashes from fusing
The temperature ensures the optimum sulfur capture reaction during combustion
Alkali metals in coal can’t be vaporized at this a low temperature. Therefore, the risk of
fouling caused by condensing of vaporized alkali metals on heating surfaces is reduced.
The formation of thermal NOx is reduced at lower temperatures
161
The amount of primary air needed for initial fluidization of the bed material has to be maintained
under all conditions. The proportion of the total air that is introduced as primary air varies from 40
to 70 % depending on the fuel. The remaining portion of the combustion air is typically divided
between upper and lower secondary air levels. The distribution of air between primary and
secondary air location is important to avoid excessively high temperatures in the lower combustion
chamber and to insure good combustion efficiency as well as low NOx production.
Fuel flexibility
Fuel flexibility is one of the major attractions of the CFB technology. Fresh fuel and combustible
matter make up less than 1 - 3% by weight of the hot solids present in the furnace. The remaining
hot solids are noncombustibles: sorbents, sand and other inerts such as fuel ash. This large source
of thermal energy, provides an extremely stable combustion environment that is insensitive to
variations in fuel quality.
The special fluid dynamic condition of the CFB provides excellent gas-solid and solid-solid mixing.
Thus fuel particles fed to the furnace are quickly dispersed into the large mass of bed solids, that
rapidly heat the fuel particles above their ignition temperature without any significant drop in the
temperature of the bed solids. This feature of a CFB furnace allows it to burn any fuel without
auxiliary fuel support, provided its heating value is enough to raise the combustion air and the fuel
itself above its ignition temperature. Thus, a wide range of fuels can be burned in one specific
boiler without any major change in the hardware. CFB boilers have been designed to burn a wide
variety of fuels and fuel qualities, including plant wastes, de-inking sludge, sewage waste, tire
derived fuel, low ash fusion coals, petroleum coke and others in combination or alone.
To maintain the combustor temperature within an optimum range, it is necessary to absorb a certain
portion of the generated heat in the combustion zone. The amount of heat that must be absorbed
varies from one fuel to another. Some CFBs accomplish this variation in furnace absorption for
different types of fuels by means of an external heat exchanger. In boilers without the external heat
exchanger the fluid dynamic condition of the furnace must be adjusted to alter the heat absorbed by
the furnace. Typical means of altering the furnace heat absorption are: changing air split and/or
excess air, flue gas recycle, and changing bed inventory.
Combustion zones in a CFB boiler
The furnace can be divided into three distinct zones, from the combustion point of view, i.e. lower
zone (below secondary air injection ports), upper zone (above secondary air injection ports), and hot
gas-solid separator. These zones are shown in Figure 5.
At the lower zone, the bed is fluidized by primary combustion air, which is about 40-80% of the
stoichiometric quantity of the air required for the coal feed. Also char particles, re-circulated by the
separator, are feed to this zone. To prevent the boiler tubes from possible corrosion and erosion, the
walls in this zone are lined by refractory material. This zone is denser than the other zones, and also
serves as an insulated storage of hot solids. The preserved solids can be used for controlling the
boiler load. When the load increase, the primary air quantity increases and more solids are
transported to the upper zone to enhance the heat transfer in the furnace. Fuel fed into the lower
combustion chamber mixes quickly and uniformly with bed materials. There is no visible bed level
in the CFB combustor. Instead the bed density decreases progressively with height.
162
The secondary air is injected at the interface
between the lower and upper zone of the
furnace, thus the upper zone is the oxygen
rich zone, where most of the combustion
occurs. Char particles are transported
upwards through the core of the furnace and
slide down the wall, mainly entrapped by
falling clusters. Thus char particles take
several turns through the furnace before they
are entirely combusted.
Upper
zone
Gas/solid
separator
Unburned char particles are captured by the
gas-solid separator and transported back to
the bed for continued combustion. Fine
particles that have entrained into larger ones
are captured, but others escape from the
cyclone.
Normally the residence time of particles is
longer than the time needed for complete
burn-out. This ensures complete combustion.
Lower
zone
Heat transfer in a CFB boiler
A boiler is a facility to convert energy,
therefore energy conversion efficiency is
Figure 5: CFB furnace sections.
bound to be the first consideration to design
and operate it. Heat transfer has to be
understood by designers.
Figure 2 and Figure 3 illustrate the heat transfer (HT) sections of a CFB boiler.
The following heat transfer processes are involved in CFB boilers.
•
•
•
•
•
•
Gas to particle
Bed to water walls
Bed to the surfaces immersed in the furnace
Bubbling bed to immersed surfaces in the external heat exchanger
Circulating particles to particle separator/cyclone
Gas to water and steam in the back pass
The most important and interesting processes are bed to water walls and the heat transfer in external
heat exchanger.
Heat transfer from gas to particles takes place in the bed. Above the bed, the heat transfer rate is
decreased due to the decreasing temperature difference between gases and particles. The main heat
transfer mechanism is convective HT.
Bed to wall heat transfer
Fine particles move upwards through the core of the bed, and then most of them flow downwards
along the wall of the bed in the form of clusters, others move down or up in dispersed phase.
163
Clusters transfer heat to the walls through conduction and radiation, dispersed particles transfer
through convection and radiation. Particle suspension density is a major factor to influence heat
transfer.
Heat transfer coefficient increases proportionally to the square root of the density. Thus HT rate at
lower part of the bed is higher than the upper part. Heat transfer coefficient isn’t affected by bed
fluidization velocity considerably, but it decreases along the height of the bed due to the
temperature difference between cluster and wall and reaches an asymptotic value after a certain
height. The coefficient increases with bed temperature, which will be attributed to the higher
radiation and thermal conductivity when high temperature. In the case of short heat transferring
surfaces finer particles result in high coefficients but the influence is less significant for longer
surfaces.
A complete analysis of bed to wall heat transfer is quite complex. Through the solving equations of
mass, momentum and energy balance on both gas and particles near the wall can help get a detailed
comprehension, but it is complex. A simplified method found by Basu (1988) based on the cluster
renewal model can explain the mechanism quite well. Since the wall is either covered by clusters or
bared to gas, the time-averaged overall heat transfer coefficient can be written as the sum of
convective and radiative HT coefficient:
h = hconv + hr = δ c (hc + hcr ) + (1 − δ c )(hd + hdr )
(4)
The key to solve the problem is to find the time averaged fraction of the wall area covered by the
clusters δc, and the convective and radiative heat transfer coefficients to the clusters and dispersed
phase. At the lower zone of the furnace, two heat transfer processes are dominant, but at the upper
part, where a majority of heat transfer surfaces are located, radiation is dominant.
Bubbling bed to external heat surfaces
The external heat exchanger helps the CFB boiler to meet a variable load and enhances fuel
flexibility. Tubes are immersed in the bed to supplement the heat transfer within the furnace itself.
Obtaining the heat transfer coefficient of bed to tubes is the key issue in HT design. It depends on a
number of factors, such as particle size, bed temperature and fluidizing velocity.
Heat transfer and part-load operation
As described above, the particle suspension density impacts heat transfer dramatically. Thus the
load control of CFB boiler can be realized by changing the density.
(
)
Q = A C * ρ b0.5 + hr (Tb − Ts )
(5)
No matter how high the load is, the bed density at the lower section of the boiler is always very
high. But as the load decrease, the density at upper section is decreased and the bed is dilute. At
70% of full load, particle concentration at upper section of the furnace where most of heat transfer
surfaces are located is weak. Therefore, convection heat transfer becomes weak, while radiation
process becomes dominant. If the load is reduced to 40%, the bed operates like a bubbling fluidized
bed boiler, and radiation can be regarded as the only process of heat transfer.
In the back-pass section, heat transfer from gas to heat exchanger occurs mainly by convection and
partly by gas radiation at temperatures above 600°C.
164
Load control in CFB boiler
The load control means a control of the heat absorption by water or steam from the furnace and
other heating surfaces of the boiler. Several ways can be used for the control purpose.
• Through control of the solids flow through the external heat exchanger surfaces
• By dividing the bubbling bed into two sections, one with heat exchanger surfaces, and one
without.
• Control bed density by adjusting solid recirculation from the bubbling bed to the furnace
• By adjusting gas velocity through the lower section of the bed to change the solid density at the
upper section of the bed
Emissions
SO2 Emissions
Circulating fluidized bed combustors in general have the advantage of removing SO2 from the flue
gas in the combustion chamber during the fuel combustion. The sulfur is captured by sorbent
particles that make up the entrained bed material. The sorbent is either limestone or dolomite and
has the ability, after being calcined in the combustor, to capture sulfur effectively. The reactions are
as follows:
for limestone
CaCO3 → CaO + CO2
(6)
Sulfur dioxide reacts with calcium oxide to calcium sulfate according to the reaction
CaO + SO2 + 1/2 O2 → CaSO4
(7)
and for dolomite
CaO + MgO + SO2 + 1 / 2 O2 → CaSO 4 + MgO
(8)
The reaction products leave the combustor along with fuel ash.
The limestone requirement needed for achieving a desired sulfur capture is a measure of the sulfur
reduction efficiency. This requirement is normally specified as Ca/S-mole ratio, which is the ratio
between the molar flow of calcium in the limestone feed and the molar flow of sulfur in the fuel.
The limestone calcining conditions effects the sulfur absorption reaction. The calcining conditions
in fluidized bed combustion are good and no inertization of limestone occurs.
Sulfur capture characteristics of different limestones vary by wide margins. Generally, younger and
more amorphous limestone has a better reactivity, i.e., ability to absorb SO2.
When limestone is crushed for CFB combustion, the surface area of the particles increase. This
improves the limestone’s ability to capture sulfur and reduces sensitivity to the reaction
temperature. On the other hand it should be remembered that retention time in the combustor is
also affected by the particle size of a sorbent. Friability of the sorbent and the collection efficiency
of the solids separator must also be considered in the efficient utilization of sorbent.
165
Limestone consumption is also affected by the fuel quality. This is a result of the capability of fuel
ash to absorb part of the sulfur. Thus, the Ca/S - ratios defined for different fuels cannot necessarily
be compared with each other. The fuel volatility also affects the distribution of sulfur in the
combustion chamber and thus affects the local concentrations of sorbent and SO2.
A high sulfur capture ratio is easy to achieve when the sulfur content of the fuel is high. If the sulfur
content in the fuel is low, the remaining SO2 content is low. This requires a greater surplus of
unreacted limestone to achieve the same sulfur reduction percentage.
From the point of view of the sulfur reduction, in the circulating fluidized bed combustion the
optimal reaction temperature is 840 – 880°C. This temperature range is also sufficient for good
combustion efficiency.
Distribution of combustion air between the primary (grid fluidizing) air and secondary air has an
effect on the intensity of turbulence in the gas-particle suspension, and therefore on the
effectiveness of the gas-solids contact. In CFB combustion the intensive fluidization (i.e. higher
ratio of primary air) leads to a high concentration of solids also in the upper part of the combustor
and also minimizes reducing atmosphere, giving an advantage in sulfur capture. The NOx
emission, however, tends to increase due to the highly oxidizing atmosphere in the lower bed.
With a suitable staging of the combustion air it is possible to reduce the NOx emissions without a
significant reduction in sulfur capture. By increasing the bed inventory it is possible to increase
solids concentration in the gas-solids suspension. Recycling of fly ash increases the solids
concentration as well as the retention time of lime particles in the CFB system.
The reaction of SO2 with calcium oxide to calcium sulfate requires oxygen as shown in Equation 4
above. In practice, noticeable reduction in sulfur capture has not been observed until the O2 content
in the flue gas has dropped below 2.5%, or when the staging of the combustion air has been very
strong.
NOx - emissions
One of the primary incentives for burning coal in the CFB is its low NOx emission level.
Compared to a pulverized coal combustor, the fluidized bed is operated at a much lower combustion
temperature (850 – 900 °C) and subsequently, NOx compounds are formed primarily from fuel
nitrogen with negligible amounts of thermal NOx (less than 5%). Figure 6 gives the temperature
effect on the various NOx formation reactions.
The formation mechanism of nitrogen oxides in combustion is very complicated. During initial fuel
pyrolysis, NH3 and HCN are the major precursors of NOx emissions. Char from the fuel tends to
reduce the nitrogen oxides forming from the volatiles, but also generates them when it combusts
itself. The nitrogen oxides are mostly nitrogen monoxide, NO, and nitrous oxide, N2O. Only a
minor part of NO is oxidized to NO2. Of these oxides, typically only NO and NO2 are under
regulation. NO forms into NO2 in the back-pass section and atmosphere.
Generally speaking, the best strategy for limiting NOx generation from fuel nitrogen in a CFB
combustor is the application of staged combustion. Then the sub-stoichiometric firing at the lower
furnace location limits the NOx formation while the injection of the secondary air at higher furnace
locations insures combustion efficiency with high carbon burnout and CO and hydrocarbon
conversion.
166
2100
NO and NO2 mg/m3
1800
Prompt
Fuel
Thermal
1500
1200
900
600
300
0
1000
1200
1400
1600
1800
2000
2200
Temperature oC
Figure 6: Temperature effect on NOx formation in various reactions.
Staged combustion is an integral part of the design of a CFB combustor. One, two or three levels of
air ports (dependant on design fuel(s)) are located above the primary air distributor plate. Multiple
levels of air staging allow for more flexibility in staging air ratios to obtain optimal NOx reduction
for various types of fuels, while still ensuring high combustion and sulfur capture efficiencies. The
high CO concentration produced in the first stage, i.e., in the lower bed section coupled with high
amounts of entrained chars are major contributors to the low NOx emissions from a CFB fluidized
bed boiler.
The use of flue gas recirculation in the CFB has been shown to help in the reduction of NOx,
especially in boilers designed for a wide variety of fuels. Flue gas recirculation helps to maintain
the gas flow throughout the combustion chamber and boiler convection section when switching
from a low grade fuel, (wood wastes and lignite) to a higher heating –value / lower moisture fuel
(bituminous coal and petroleum coke). This practice allows both combustion and steam
temperature to be effectively controlled under a wide variety of operating conditions.
Under typical operating conditions in the CFB, fuels of various ranks have been found to emit low
levels of NOx, ranging from 70 - 180 ppm. By appropriate application of the methods described
above, it is possible, in most cases, to maintain NOx emissions below 120 ppm.
By injecting ammonia or urea into the solids separator, higher NOx reduction can be achieved. This
method, patented by Foster Wheeler, is in continuous use in several Foster Wheeler CFBs
worldwide. In these boilers, the NOx emission is controlled by the ammonia injection to 40 - 65
ppm. Ammonia/urea selectively reduces NO to molecular nitrogen. The optimum temperature
range for the NOx reduction reactions is 800 – 950°C that matches the typical combustion
temperature of the CFB.
Combustion at 800-900°C creates small amounts of N2O, which is a greenhouse gas. The formation
of N2O increases with increasing combustion pressure.
167
Particulate matter (PM) emission
Current particulate matter emission control technology is readily capable of maintaining extremely
low stack PM emissions, virtually eliminating fugitive dust emissions created by materials
handling. Depending on the specific application, a reverse-air baghouse filter, a pulse-jet baghouse
filter or an electrostatic precipitator (ESP) is used. PM emissions from the entire plant are
minimized by the application of fugitive dust control to all material handling equipment. The
exhaust from these control systems, after passing through local bag-houses, can be used as
combustion air.
Carbon monoxide and hydrocarbons
Both carbon monoxide and hydrocarbon emissions are controlled by efficient gas-solids mixing,
sufficient combustion temperature and excess air. Unfortunately both of these factors contribute to
an increase in NOx formation. Thus, the emission level of both must be balanced against the NOx
emission.
168
References
1. CFB Engineering Manual, extract supplied by Foster Wheeler. http://www.fwc.com/
3. Pictures supplied by Kvaerner Power Division. http://www.kvaerner.com/powergeneration/
4. Huhtinen and Hotta. Combustion of fossil fuels. 2000
169
Circulating Fluidized Bed Boiler Design
Dianjun Zhang, Sebastian Teir
STEAM BOILER TECHNOLOGY – Circulating Fluidized Bed Boiler Design
Table of contents
Introduction......................................................................................................................................173
Combustion calculation....................................................................................................................173
Chemical reactions.......................................................................................................................174
Air required ..............................................................................................................................174
Sorbent requirement.................................................................................................................174
Solid waste produced ...............................................................................................................174
Gaseous waste products ...........................................................................................................175
Heat and mass balances....................................................................................................................175
Heat balance.................................................................................................................................175
Mass balance ................................................................................................................................177
Control of particle size in bed ......................................................................................................177
Furnace Design ................................................................................................................................178
Grate heat release rate (GHRR) ...................................................................................................178
Cross section of the furnace .........................................................................................................179
Shape of the furnace.....................................................................................................................179
Air nozzles ...................................................................................................................................180
Fuel feed ports..............................................................................................................................180
Limestone feed ports....................................................................................................................180
Secondary air injection port .........................................................................................................180
Recycled solid entry.....................................................................................................................180
Bed solid drain .............................................................................................................................181
Height of the primary zone ..........................................................................................................181
Effect of Fuel ...............................................................................................................................181
Boiler performance modeling ......................................................................................................181
Design of heating surfaces ...............................................................................................................181
Arrangement of heat exchanger surfaces .....................................................................................182
Heat distribution...........................................................................................................................184
Gas-solid separators .........................................................................................................................184
Cyclones.......................................................................................................................................184
U-Beams particle separators ........................................................................................................185
Recycling of solids.......................................................................................................................186
Bottom Ash Removal System ......................................................................................................187
References........................................................................................................................................188
172
Introduction
Figure 1 illustrates the structure of CFB boiler. This chapter focuses on the design issues of CFB
boilers. The design of CFB boilers involves the following major steps.
•
•
•
•
•
•
Combustion calculation
Heat and mass balance calculation
Furnace design
Heat absorption by medium (water and steam)
Mechanical component design
Design for combustion and emission performance
Combustion calculation
Based on the boiler design capacity and fuel proximity analysis, stoichiometric calculation is carried
out. It is the basis of boiler design. The amount of fuel, combustion air, sorbent injection, flue gas
flow, etc. for the capacity is determined. Based on these calculations, the equipment can be
dimensioned, such as coal and sorbent feeder, forced combustion air fan, induced flue gas fan, and
ash handling system.
Figure 1: Structure of a CFB boiler in Germany with flue gas treatment facilities (94 MWth, 33.4
kg/s, 89 bar, 480ºC). [2]
173
Chemical reactions
In CFB boilers, the following chemical reactions take place.
C + O2 = CO2 + 32790kJ / kg.of .carbon
m⎞
m
⎛
C n H m + ⎜ n + ⎟O2 = nCO2 + H 2 O + heat
4⎠
2
⎝
S + O2 = SO2 + 9260kJ / kg.of .sulphur
CaCO3 = CaO + CO2 − 1830kJ / kg.of .CaCO3
(1)
MgCO3 = MgO + CO2 − 1183kJ / kg.of .MgCO3
1
CaO + SO2 + O2 = CaSO4 + 15141kJ / kg.of .S
2
In addition to the calculated stoichiometric combustion air, an excess air of around 20% is
demanded for complete combustion and desulfurization.
Air required
The dry air required for complete combustion of a unit weight of coal (Mda) is determined by the
formula below.
⎡
⎤
O⎞
⎛
M da = ⎢11.53C + 34.34⎜ H − ⎟ + 4.34S + A.S ⎥ kg / kg.of .coal
(2)
8⎠
⎝
⎣
⎦
The moisture content in the air must be considered when calculating the amount of air required.
M wa = EAC * M da (1 + X m )
(3)
where
EAC = excess air coefficient, equals 1.2
Xm = the weight of moisture in the air, 0.013kg/kg of air
Sorbent requirement
If the amount of CaO in ashes can be neglected, the sorbent required for sulfur retention in one unit
weight of coal (Lq) can be calculated as
Lq =
100S
R
32 X CaCO3
(4)
where
XCaCO3 = the weight fraction of CaCO3 in the sorbent
R = the calcium to sulfur molar ratio in the feed of sorbent and coal
Solid waste produced
Waste solids (Wa) in a CFB boiler include ashes of coal, sulfur retention reaction products, and
unreacted CaO and MgO.
174
Wa = 136
⎛ Lq X CaCO3 SE sor ⎞ 40 Lq X MgCO3
S
⎟+
E sor + 56⎜⎜
−
+ Lq X inert + ASH + (1 − E c ) − X CaO
⎟
32
100
32
84
⎝
⎠
(5)
where
Esor = the fraction of sulfur captured in the bed
Xinert = weight fraction of inert in limestone
Ec = fraction efficiency of combustion
ASH = weight fraction of ash in coal
Gaseous waste products
The weight of carbon dioxide (WCO2) produced from fixed carbon in coal is 3.66 times the weight
of the coal. In addition, reaction of sulfur retention produces also CO2. Thus the total mass of CO2
produced will be
⎛
X MgCO3
WCO 2 = 3.66C + 1.375SR⎜1 + 1.19
⎜
X CaCO3
⎝
⎞
⎟
⎟
⎠
(6)
Heat and mass balances
Heat balance
Moisture loss is the heat loss to vaporize moisture in the sorbent, and can be calculated by
Qml = l q X ml H Sexit
(7)
Calcination loss takes place during the calcinations reaction of calcium carbonate and magnesium
carbonate.
feed .rate.of .CaCO3 *1830 *100
Calcination loss from CaCO3=
%
(8)
Fuel. feed .rate * HHV
feed .rate.of .MgCO3 *1183 *100
%
(9)
Calcination loss from MgCO3=
Fuel. feed .rate * HHV
Sulfate credit is the heat gain when sulfur dioxide reacts with calcined limestone due to the
exothermic reaction. The value of the heat gain can be calculated by
Percentage heat gain =
kg.of .sulfur.converted *15141*100 E sor S *15141*100
=
%
kg.of . fuel. fed * HHV
HHV
(10)
Unburned carbon loss in ash is normally in the range of 0.5-2%. Higher furnace and efficient
cyclone can ensure lower loss of combustibles. If Xc denotes the fraction carbon in solid waste, the
loss can be calculated as
Unburned carbon loss in ash =
X cWa * 33488 *100
%
HHV
(11)
175
Dry flue gas loss is due to the sensible heat carried away by the dry flue gas at the boiler exit
temperature, and can be calculated as
Dry flue gas loss =
He − Hi
*100 %
HHV
(12)
He is the sensible heat of dry flue gases at the boiler exit temperature, and Hi is the sensible heat in
fuel and air at ambient temperature. The lower the flue gas temperature is, the more efficient is the
boiler. But low flue gas temperature causes condensation of H2O and SO2 in the air preheater.
Commercial CFB boilers are designed an exit temperature of around 130°C after the air preheater.
Figure 2 shows the minimum average cold-end temperature of coal burning.
Moisture loss of fuel is caused by heating water content of fuel into steam and can be calculated by
multiplying moisture content of fuel with flue gas enthalpy Hf.
Moisture loss of fuel =
MfHf
HHV
*100 %
(13)
Moisture loss of air is due to the heating of moisture in air from ambient temperature to the flue gas
exit temperature. It can be calculated as
Moisture loss of air =
X mHe
*100 %
HHV
(14)
where
Xm = moisture content of the combustion air
Temperature oC
He = the enthalpy of steam at the exit flue gas temperature
195
190
185
180
175
170
165
160
155
150
0
1 1.5 2 2.5 3 3.5 4 4.5 5
Sulfur content of coal %
Figure 2: Minimum average cold-end temperature of coal burning.
Loss due to hydrogen burning =
9H * H f
HHV
* 100 %
(15)
176
Radiation and convection heat loss: Due to the large external surface of the furnace, external heat
exchanger and cyclone, the heat loss through radiation and convection is considerable, 0.2-0.5% of
the total heat released from the furnace.
Sensible heat in ash: The ash from the furnace or bed is collected partly as fly ash from the
baghouse filter or ESP and partly as bed drain. The bed drain (20-80% of the total ash) at furnace
temperature is cooled at an ash cooler, by heating air, so that the ash can be transported by trucks.
But the ash temperature is still 300°C. Still, the fly ash is collected at 140°C, which makes a
considerable heat loss.
FD fan credit means that part of the power to forced draft fans is converted into heat through
fractional losses as heat gain of air.
Unaccounted loss is about 1.5%.
Mass balance
The mass balance of a CFB boiler can be listed as follows:
Solid input into furnace
Solid output from the furnace
•
Fuel
•
Drain from external heat exchanger
•
Sorbent
•
Drain from back pass
•
Supplemental bed material
•
Drain from bed
•
Drain from baghouse or ESP
•
Solids leaving from stack
•
Others
Solids reinjection into the furnace is needed due to the fact that the escape of fly ash from cyclone
exceeds the feed of ash and sorbent to the furnace. This condition will lead to the depletion of
furnace inventory of bed particles. In order to keep the inventory stable, part of the fly ashes
collected at the baghouse filter or ESP has to be reinjected in to the furnace continuously. The
reinjection of fly ash into the furnace can improve combustion efficiency and sulfur capture.
For combustion of coal with very low ash or sulfur content, an inert material, such as sand, is added
into the bed to maintain the inventory.
Normally, 30-100% of solid waste passes through the baghouse filter or ESP, and the bed drain is
only as low as 3-5% of the total solid waste. For conservative design, the collection equipment for
fine dust is selected for the disposal of 100% of solid waste, and the bed drain may be designed for
50% of the total solid waste.
Control of particle size in bed
Maintaining enough bed solids in the furnace of a CFB boiler serves the following purposes:
•
•
•
Supports sulfur capture reaction
Helps producing a good axial and lateral heat transfer and maintaining uniform temperature
in the furnace
Supports heat transfer and controls heat transfer rate to the furnace wall
177
•
Transports heat to the external heat exchanger, and to some extent to the back-pass
The realization of these functions depends on the solid size that must be kept within the limits.
Coarser particles tend to congregate near the bottom of the furnace, while finer particles are
entrained out of the cyclone as fly ash. Finer bed solids result in higher bed density in the upper
regions of the furnace than from by coarser solids. The benefit is that a higher heat transfer
coefficient is gained in the most parts of the furnace. The control of the inventory of fine bed solids
is guided by the loss through entraining, bottom ash, and decrepitation of finer sizes, and the gain is
due to fresh ash feed and decrepitation of coarser sizes.
Furnace Design
The success of any CFB boiler design and operation depends on the furnace design. The most
important aspects of the furnace design are furnace temperature, solid inventory and distribution,
limestone and fuel particle size, gas residence time, furnace depth and furnace heating surfaces.
The furnace is designed on the basis of the heat and mass balances. The furnace temperature
impacts the SO2 capture, NOx emissions, combustion efficiency, and the heat transfer to the furnace
walls. The furnace temperature is set regarding fuel properties and emission control consideration,
normally 800-900°C.
The dimensions of the furnace are set by the velocity and residence time of gas-solids. The
dimension design of the furnace of a CFB boiler involves three main aspects:
• Furnace cross section
• Furnace height
• Furnace openings
The shape and size of furnace cross section comes from combustion considerations. Furnace height
is determined from heat transfer and solid residence time. Furnace openings are determined from
the feeding of air, fuel and sorbent, and affect the mechanical design of the boiler.
Ash and moisture content of coal, and its other properties such as reactivity, mechanical attrition,
ash properties, sulfur content, heating value, have important effects on the overall design and
performance of a CFB boiler. Table 1 illustrates the effect of coal properties on the design and
performance of a CFB boiler.
Grate heat release rate (GHRR)
One important criterion for the design of CFB boilers is a high grate heat release rate per unit cross
section of the furnace. This function of the mass flow rate of combustion air passing through the
furnace was derived by Waters in 1975.
GHRR =
3.3U 0
[EAC ]
MW/m2
(16)
where U0 is the superficial gas velocity through the furnace and EAC the excess air coefficient. For
large capacity CFB boilers, the depth of furnace is so large that it is not easy to have a good mixing
of coal volatiles.
178
Table 1: Effect of coal properties on CFB design.
Coal property
Design parameter
Performance
Friability
Cyclone grade-efficiency
Boiler efficiency, carbon carryover
Reactivity
Air flow distribution
Boiler efficiency, carbon carryover ,CO
emission
Inherent
vs. Ash removal, ash split, heat absorption Ash carryover, bed drain, dust collector
extraneous ash surface design
loading
Ash chemistry
Ash removal, back-pass flow area, Bed agglomeration, tube fouling
heating surface design
Moisture
Heat
absorption,
dimensional Thermal efficiency, excess air
requirements, capacity of cyclone and
downstream equipment
Heating value
Dimensional requirements
Capacity, thermal efficiency
Sulfur content
Sorbent handling equipment
Emission, bed drain requirement
Cross section of the furnace
The furnace cross section is mainly determined by the average velocity of the cross section for a
given heat output of the boiler. High velocity can bring a high grate heat release rate, but can cause
erosion of the furnace and requires a high fan power. The grate heat release rate now is taken
generally of the order 3-4MW/m2 of upper section of the bed. The fluidization velocity for
avoidance of furnace erosion shouldn’t exceed 5m/s.
Shape of the furnace
Normally CFB boiler furnace has a rectangular cross section. The combustion chamber is designed
to contain a slight negative pressure and consists of a membrane wall gas-tight enclosure. When the
cross section of furnace is determined, the width and breadth of the section have to be decided
according to the consideration below.
• Heating surface necessary in the furnace
• Secondary air penetration into the furnace
• Solids feeding/lateral dispersion
The breadth of the furnace should not be too large, so that it results in a poor penetration of the
secondary air into the furnace and non-uniform dispersal of volatile matter. A suitable breadth of
the furnace should be selected on the basis of simulation. Normally it is less than 8 meters.
The lower combustion chamber section has an air distribution grid for introducing the primary air
and a bottom ash removal system. The lower combustion chamber also has openings for the
recirculated solids, secondary air nozzles, fuel, limestone, make-up sand and recycled fly ash feed,
startup burners and bed lances as required. There are no heat transfer tubes inside the high-density
lower combustor. In this region, a rapid change of solids flow pattern occurs, thus heat transfer wall
tubing is protected by a thin layer of abrasion-resistant refractory. It is designed tapered upwards to
maintain similar superficial velocities above and below the secondary air level under all operating
179
load, and to minimize the risk of agglomeration under a low load and formation of clinker near the
grid.
Air nozzles
To distribute the air in the fluidized bed special nozzles are needed. The nozzles introduce primary
air, which is used for the combustion and fluidization of the bed particles. The nozzles must also
keep the bed material from entering the air system. Primary air is delivered through a cooled
membrane wall bottom (Figure 3). Replaceable nozzles are used because the erosion on the lower
part of the furnace is high. Most typical nozzle types are S-type and Cap-type.
Fuel feed ports
As mentioned before, CFB boilers require less
fuel feed points than PC boilers due to the
efficient combustion and compact structures.
The number of ports of feed points is a function
of the fuel characteristics and degree of lateral
mixing in the specific design of the furnace.
According to experiences, one feed point can
serve 9-27m2 of bed area. The points locate
within the refractory lined substoichimetric
lower zone of the furnace and as low as possible
below secondary air ports in order to have
longer solid residence time. In some designs,
fuel with high moisture or sticky fuel are fed
into the loop seal so that fuel can be heated and
partly devolatilized and well mixed before
entering the bed.
Limestone feed ports
Figure 3: Air distribution nozzles.
Due to the slow reaction rate, the location of the
sorbent feed point is less critical. Limestone is
finer and used in smaller quantity, and can be injected into the bed pneumatically. Sometimes it is
injected into the recycled solids in order to mix better with bed materials.
Secondary air injection port
Air staging is used to reduce the formation of NOx. Primary air enters the bed from the bottom of
the bed grid to support the bed. Secondary air, 40-60% of combustion air, is injected into the bed
from above the refractory lined section. Thus substoichiometric combustion occurs in the lower
furnace zone. Above the secondary air injection, superficial velocity increases and unburned fuel in
substoichiometric zone will be combusted continuously. The injection ports should be located along
the wider side of the furnace cross section in order for the secondary air to be able to penetrate into
the depth of the furnace within a reasonable height.
Recycled solid entry
Solids collected by the cyclone or impact separator are returned to the furnace through a solid entry
port to extend the burning and reaction of unburned carbon and unreacted sorbent. The port is
located below the secondary air level. The selection of the port is based on the principle of pressure
balance between the solid return leg and the furnace pressure above the port.
180
Bed solid drain
The purpose of bed drain is to extract bed solids from the lowest section of the bed in order to
maintain the required level of solid mass in the bed (bed inventory) and the size distribution of
solids. Figure 4 shows a size classifier drain pipe of CFB boilers. Solids drop through a vertical
tube, where air enters from the sides at such a rate that it entrains finer particles of solids into the
bed, while the heavier coarse fraction ash drops through the pipe to the silo. By hanging the
transport air velocity, the solid size distribution in the bed can be adjusted. The drain pipe should be
designed to prevent solids from blocking.
Height of the primary zone
The purpose of the primary air zone in the
furnace is to heat, gasify and pyrolyze fresh
coal. It also serves a thermal storage device. The
deeper the primary zone is, the higher the
pressure drop is, which require more fan power.
A depth of 2-3 meters is common nowadays.
Effect of Fuel
Bed
Primary air
The fuel burnt, such as coal, peat, wood barks,
has a significant effect on the design and
operation of the CFB boilers. A stoichoimetric
fuel analysis must be done. Heat value of the
fuel governs coal feeding. Sulfur content decides
the sorbent injection rate.
Transport air
Boiler performance modeling
Performance modeling is an important tool for
designers of CFB boilers. At the design stage, a
prediction of the boiler performance can help to
determine the most economic size of the boiler
for the best performance. When the boiler is
built, the simulation can be used for operation
optimization. The design can be evaluated by the
following criteria.
•
•
•
•
•
Oversize ash
Figure 4:Drain pipe of solid ash.
Unburned carbon loss
Distribution of volatile, oxygen, and carbon along the height and across the cross section of
the furnace
Flue gas composition at the exit of the cyclone, especially the emission of SO2 and NOx.
Heat release and absorption pattern in the furnace
Solid waste generated
Design of heating surfaces
The design of heating surfaces is affected by the fuel type used. For high sulfur content fuel, the
combustion temperature must be at around 850°C for optimum sulfur capture. Fuels with low sulfur
and reactivity have to be combusted at a higher temperature and EAC for good combustion
efficiency. The fuel type determines where the heating surfaces are placed. For instance, low quality
coal will carry a high percentage of the generated heat out of the furnace, and less heat will be
181
absorbed in the primary loop, therefore more heating surface should be arranged at the backpass of
the furnace (Figure 5). Conversely, if high grade fuel is used, a large part of the heat generated is
absorbed in the CFB loop, which means that a superheater or reheater should be placed in the loop
(Figure 5). According to the heat duty of each heating surface and energy balance of the process,
the heat transfer area of each surface can be determined.
Arrangement of heat exchanger surfaces
Heating surfaces in a CFB, visualized in Figure 6, include the following heat exchangers:
•
•
•
•
•
Economizer
Evaporator (consists of furnace wall tubes)
Superheater
Reheater (optional)
Air preheater
The economizer is located at the
backpass between the superheater and
air preheater. The flue gas velocity
through the economizer is in the range
of 7.6 to 10.7 m/s depending on the fuel
and ash characteristics, while the
velocity of the steam/water mixture in
the tubes is about 1 m/s. The
economizer tube spacing and inline
arrangement minimize tube erosion and
fouling potential. The economizer flue
gas outlet temperature is selected
considering the feedwater temperature
plus 42 to 56°C for the optimum heat
absorption
split
between
the
economizer and air preheater. The
economizer
feed
water
outlet
temperature is normally limited to 42°C
less than the saturation temperature in
order to avoid evaporation in the
economizer at partial loads.
Furnace and
cyclone
Backpass
Superheaters
and reheaters
Furnace
Economizer
Air
preheater
INTREX
Superheater
The evaporator consists normally of
Figure 5: Placement of heat transfer surfaces. [1]
the walls of the furnace; through which
water vaporize from water to saturated
steam. The typical overall heat transfer
coefficient of the furnace wall is in the range of 150 to 200W/m2K.
Saturated steam from the evaporator is heated in the superheater, which is located in the backpass,
to the required steam temperature, normally 540°C, before it is led to the turbine for expansion
work. The flue gas velocity through the superheater is as low as 7.6 to 8.5m/s and uniform across
the channel area in order to reduce erosion. The steam velocity in the tubes is about 20 m/s.
182
Steam that has partially expanded in a HP turbine can be led back to the boiler and reheated in a
reheater. The reheater is located in the back-pass.
The air preheater, where combustion air is heated by the flue gas, is located after the economizer in
the flue gas channel. Tubular air preheaters are used for recovering the remaining heat in the flue
gas to meet the boiler efficiency
requirement. Similarly to the economizer,
the spacing of the tubes is arranged
Superheaters
External heat
and reheaters
according to inline arrangement to
transfer surfaces
minimize fouling potential and erosion.
Flue gas flows on the outside of the tubes
with a flue gas velocity of 9 to 12 m/s. It
Furnace
(water walls)
should prevent entering air from saturation
Economizer
and cold end tube corrosion, which is true
especially for burning of fuel with high
Air
sulfur content.
preheater
A special heating surface is the external
heat exchanger, embedded in bubbling
recycled solid bed (Figure 6). Heat
absorbed in the heat exchanger is
fluctuating in order to keep bed
temperature and excess air relatively
unaffected. If the total heat duty of the
superheater and
reheater is larger than the maximum heat
that can be absorbed by these two heating
surfaces in back pass and furnace, the
external heat exchanger is needed.
Figure 6: Placement of heat transfer surfaces. [1]
The INTREX (Integral Recycling Heat
Exchanger) heat exchanger by Foster Wheeler is
a heat exchanger located in the bubbling bed
(Figure 5 and Figure 7). It contains one or more
tube bundles to cool circulating solids. Solids
enter from the furnace via slots (called internal
solids circulation) or from the separator (called
external solids circulation). Solids return to the
furnace via the solids return channels or through
slots in the common wall. The immersed tube
bundles can perform superheat or reheat duty
and have a very efficient heat transfer due to the
high temperature difference. By controlling the
rate of fluidizing airflow in the chamber and/or
the solids return channels, the heat absorbed in
the immersed tube bundles can be controlled,
which in turn can control furnace temperature or
steam temperature.
Figure 7: INTREX heat exchanger. [2]
183
Heat distribution
In general, heat duty distribution of different heat transfer components is designed as below.
•
•
•
Sub-cooled part: 20%
Evaporation: 52%
Superheat: 28%
But the actual distribution is
•
•
•
Economizer: 10%
Furnace: 60%
Superheat: 30%
The economizer and air heater heat duty split requires a careful evaluation. The heat transfer
coefficient of the economizer is 56.8 to 65.1W/m2K, around 2 to 3 times higher than that of the air
preheater.
Gas-solid separators
Two different gas-solid separators are used in CFB boilers for different reasons. Cyclone or other
impingement separators are used within the CFB boiler loop to trap hot solids and return them to
the bed. This makes the residence time of fuel in the furnace long enough for complete combustion.
This is called the primary particles collection. Electrostatic precipitators (ESP) or bag-house filters
are used at the cold end stream of the boiler process to reduce fine particle emission to the
atmosphere. This is called the secondary collection. These chapters are focused upon the primary
separators, since they are a unique feature for CFB boilers.
The solids separator is a vital part of the CFB technology. The solids separator is primarily designed
to provide an efficient separation of the entrained solids from the hot flue gas and return most of the
unburned carbon and available calcined limestone for more efficient use. Sand and inert ash
particles are also returned. These particles are needed to maintain the proper bed inventory and
quality. The separator, located at the outlet of the combustion chamber, collects particles greater
than 60 microns with 99.5% or higher efficiency. The solids captured in the separator are
recirculated through a non-mechanical sealing device back to the combustion chamber.
Cyclones
Cyclones are commonly used for the separation of hot solids. It has a simple construction, since it
has no moving parts, and a high efficiency. Cyclones are located in the hot loop of CFB boiler, and
hot particles are entrapped and recycled to the furnace bed. Flue gas flows out from the top of the
cyclones to the backpass. The efficiency of the cyclone can be improved by several factors:
•
•
•
•
•
Higher entry velocity of the mixture of gas and solids
Larger size of solid
Higher density of particles
Smaller radius of the cyclone
Lower viscosity
To evaluate the probability of particles captured, one cut-off size is defined as the size of particles
that are likely to be collected with 50% efficiency by a given cyclone.
184
d th =
9 µL
(17)
2πN cVin (ρ p − ρ g )
where, Nc is the effective number of turns made by the gas-solid stream in the separator, normally 5
is assumed.
Higher mixture inlet velocity to the cyclone helps to capture much finer particles and increase
efficiency, but the pressure drop of gas through the cyclone increases. The aim of the design is to
find the optimum velocity.
Mechanical design of the solids separator varies in both construction and shape. Based on customer
preference, fuel fired, unit size and/or cycle condition the separator walls may be steam cooled,
water cooled or of refractory construction. The conventional solids separator design is a refractory
lined, uncooled cyclone. This type of cyclone is lined with a two-layer refractory (Figure 8). The
inner refractory layer is abrasion resistant material to resist the erosive effects of high velocity ash
particles. The outer refractory layer, against the metal shell, provides insulation to minimize heat
loss and protect the carbon steel outer casing from overheating. The amount of refractory in this
type of cyclone is very large and therefore high maintenance costs and availability problems are
envisioned. Typically, a cooled separator design is preferred (Figure 8).
Solid Separator for
Foster Wheeler CFB
FEATURES
• Square
• Integrated with furnace
• No expansion joints
• Membrane walls
• Water or steam cooled
• Normal insulation
Mineral wool
Refractory ca. 50 mm
Membrane wall
Figure 8: Cyclone design from Foster Wheeler. [2]
U-Beams particle separators
Babcock & Wilcox Ltd (B & W) uses a primary particle separator that functions by impact force.
Figure 9 shows the location of the U-Beams in the CFB process. B & W's primary solids collectors
consists of 2 rows of U-Beams located within the furnace at the gas exit and 4 additional rows of UBeams located immediately downstream of the in-furnace U-Beams. Solids collected by the front
185
two rows discharge downward directly to the furnace along the rear wall, and return by gravity to
the furnace through opening distributed across the width of the unit. Solids collected by 4 additional
rows of U-Beams return to solid storage hopper. Figure 10 shows a schematic of the U-Beams.
The U-Beams are made of stainless steel. Individual U-beams are in the form of channels, 152 mm
wide by 178 mm deep. Two bolts through the water-cooled roof suspend each beam, protected by
an enclosure. Dynamics (gas and solids)
stresses, static (dead load) stresses, design
temperatures and material creep strength are
used to design the U-Beams.
A pan at the lower ends of each U-Beam in
alignment accommodates horizontal and
vertical expansion. These pans also form a gas
barrier at the bottom discharge end of the
beams to prevent gas bypassing and improve
particle collection.
The erosion is low due to the chromium oxide
layer that forms on the stainless steel at the
furnace operating temperatures. Lower gas
velocity through the U-beam and design with
all impact angles at 90 degrees is also
favorable. Figure 11 shows the gas flow
through U-Beams. [4]
Figure 9: Locations of U-Beams. [4]
Recycling of solids
In a solids return from uncooled cyclone to
combustor, a loop seal (Figure 12) is used to
provide the gas seal for pressure difference
between lower furnace and separator. Loop
seal has similar mechanical structure as the
cyclone, i.e. it is manufactured of carbon steel
plate and lined with a two-layer refractory.
This further increases the amount of
refractories. A split loop seal design is used
particularly in larger units to provide two
solids outlets from one cyclone. The bottom of
the loop seal is fluidized with high-pressure
air.
Expansion joints are provided at the inlet of
the uncooled cyclone and in loop seal to
compensate different thermal expansion of
combustor and cyclone.
Figure 10: U-Beams solid separator. [4]
With cooled separators a wall seal -design is used to provide the gas seal. The wall seal is
constructed of water cooled panel walls, which minimize the amount of refractories. The bottom of
the wall seal is fluidized with high-pressure air.
186
Using a water cooled separator no expansion
joints are required, since there is no
temperature difference between the separator
and furnace. In case of a steam cooled
separator a flexible connection is provided at
separator inlet and a small expansion joint at
the outlet to wall seal.
Bottom Ash Removal System
The bottom ash removal rate is controlled to
maintain a constant bed material inventory in
the furnace. In addition, the bottom ash
removal system performs one or more of the
following important functions:
•
Provide cooling of the bottom ash
material.
•
Classify the bottom ash material and
return light particles to help maintain
furnace bed quality.
•
Recover heat from the ash.
•
Improve carbon burn out.
•
Improve sulfur capture reactions
Figure 11: Gas flow through U-Beams. [4]
Figure 12: Loop seal. [ 5]
187
References
1. CFB Engineering Manual, extract supplied by Foster Wheeler. http://www.fwc.com/
3. Pictures supplied by Kvaerner Power Division. http://www.kvaerner.com/powergeneration/
4. Pictures supplied by Babcock & Wilcox, http://www.babcock.com
5. Vakkilainen E. Lecture slides and material on steam boiler technology. 2001.
188
Recovery Boilers
Esa Vakkilainen
STEAM BOILER TECHNOLOGY – Recovery Boilers
Table of contents
Kraft recovery principles .................................................................................................................191
Function of recovery boilers ........................................................................................................192
First recovery boilers ...................................................................................................................193
Development of recovery boiler technology................................................................................193
Improving air systems..................................................................................................................194
Multilevel air............................................................................................................................195
Vertical air................................................................................................................................195
Black liquor dry solids content ................................................................................................195
High temperature and pressure recovery boiler ...........................................................................197
Safety ...........................................................................................................................................197
Chemical processes in the furnace ...................................................................................................198
Smelt ............................................................................................................................................199
Reduction and sulfidity ................................................................................................................199
Sodium .........................................................................................................................................200
Recovery boiler design.....................................................................................................................201
Key recovery boiler design alternatives.......................................................................................201
Key design specifications.........................................................................................................201
Single drum ..............................................................................................................................202
Screen or screenless boiler.......................................................................................................202
Evolution of recovery boiler design.............................................................................................203
Two drum recovery boiler........................................................................................................204
Modern recovery boiler............................................................................................................204
Current recovery boiler ............................................................................................................206
State of the art and current trends ............................................................................................206
Steam generation......................................................................................................................207
Heat transfer surface design and material selection.........................................................................207
Furnace design and materials.......................................................................................................208
Furnace tube materials .............................................................................................................208
Membrane materials.................................................................................................................210
Refractory and studs.................................................................................................................210
Superheater design and materials.................................................................................................210
Effect of steam outlet temperature ...........................................................................................210
Typical materials......................................................................................................................211
Sealing the roof ........................................................................................................................211
Boiler bank design and materials .................................................................................................212
Economizer design and materials ................................................................................................212
References........................................................................................................................................213
190
Kraft recovery principles
In the pulping process of a paper mill, spent cooking chemicals and dissolved organics are separated
from the pulp during washing. This black, alkaline liquor was at first dumped. Chemical recovery
systems were used earlier, but it was in the 1930’s and 40’s when modern type of regeneration of
spent liquor was widely adopted. Invention of new types of equipment and an increase in mill size
led to a favorable economic situation: it was cheaper to process black liquor than to buy new
chemicals.
Recovery of black liquor has also other advantages. Concentrated black liquor can, when burnt,
produce energy for generation of steam and electricity. In the most modern pulp mills, this energy is
more than sufficient to cover all internal power use.
Sales
Black liquor
Makeup
chemicals
Recovery boiler
Electricity
Green liquor
Lime kiln
Weak liquor
Evaporator
Causticizing
Bark boiler
Bark
White liquor
Cooking
Sludges
Wood handling
Roundwood
Chips
Chemical mftg
Bleaching
chemicals
Pulp
Soap
Bleaching
Talloil prod.
Sales
Pulp
Drying
Figure 1: Kraft mill unit operations.
The principal Kraft recovery unit operations are (Figure 1), evaporation of black liquor, combustion
of black liquor in recovery boiler furnace including of formation of sodium sulfide and sodium
carbonate, causticizing of sodium carbonate to sodium hydroxide, and regeneration of lime mud in a
lime kiln.
There are other minor operations to ensure continuous operation of the recovery cycle. Soap in the
black liquor can be removed and tall oil produced. Control of sodium - sulfate balance is done by
addition of makeup chemicals such as sodium sulfate to mix tank or removal of recovery boiler
flyash. Removal of recovery boiler flyash removes mostly sodium and sulfur, but serves as purge
for chloride and potassium. Buildup of non-process elements is prevented by disposal of dregs and
grits at causticizing. Malodorous gases are processed by combustion at the recovery boiler or lime
kiln. In some modern and closed mills chloride and potassium removal processes are employed.
With additional closure new internal chemical manufacturing methods are sometimes applied.
191
Figure 2: One of the latest recovery boilers constructed, Gruvö from Kvaerner.
Function of recovery boilers
Concentrated black liquor contains organic dissolved wood residue in addition of cooking
chemicals. Combustion of the organic portion of chemicals produces heat. In the recovery boiler
heat is used to produce high pressure steam, which is used to generate electricity in a turbine. The
turbine exhaust, low pressure steam is used for process heating.
Combustion in the recovery boiler (Figure 2) furnace needs to be controlled carefully. High
concentration of sulfur requires optimum process conditions to avoid production of sulfur dioxide
and reduced sulfur gases emissions. In addition to environmentally clean combustion, reduction of
inorganic sulfur must be achieved in the char bed.
The recovery boiler process has several unit processes:
1. Combustion of organic material in black liquor to generate steam
2. Reduction of inorganic sulfur compounds to sodium sulfide
3. Production of molten inorganic flow of mainly sodium carbonate and sodium sulfide and
dissolution of said flow to weak white liquor to produce green liquor
4. Recovery of inorganic dust from flue gas to save chemicals
5. Production of sodium fume to capture combustion residue of released sulfur compounds
192
First recovery boilers
The modern recovery boiler has a few strong ideas that have remained unchanged until today. It
was the first recovery equipment type where all processes occurred in a single vessel. The drying,
combustion and subsequent reactions of black liquor all occur inside a cooled furnace. This is the
main idea in Tomlinson’s work.
Secondly the combustion is aided by spraying the black liquor into small droplets. Controlling
process by directing spray proved easy. Spraying was used in early rotary furnaces and with some
success adapted to stationary furnace by H. K. Moore. Thirdly one can control the char bed by
having primary air level at char bed surface and more levels above. Multiple level air system was
introduced by C. L. Wagner.
Recovery boilers also improved the smelt removal. It is removed directly from the furnace through
smelt spouts into a dissolving tank. Some of the first recovery units employed the use of Cottrell’s
electrostatic precipitator for dust recovery.
Babcock & Wilcox (B&W) was founded in 1867 and gained early fame with its water tube boilers.
The company built and put into service the first black liquor recovery boiler in the world in 1929
[1]. This was soon followed by a unit with completely water cooled furnace at Windsor Mills in
1934. After reverberatory and rotating furnaces the recovery boiler was on its way.
The second early pioneer, Combustion Engineering based its recovery boiler design on the
pioneering work of William M. Cary, who in 1926 designed three furnaces to operate with direct
liquor spraying and on work by Adolph W. Waern and his recovery units.
Recovery boilers were soon licensed and produced in Scandinavia and Japan. These boilers were
built by local manufacturers from drawings and with instructions of licensors. One of the early
Scandinavian Tomlinson units employed a 8.0 m high furnace that had 2.8*4.1 m furnace bottom
which expanded to 4.0*4.1 m at superheater entrance [2]. This unit stopped production for every
weekend. In the beginning economizers had to be water washed twice every day, but after
installation of shot sootblowing in the late 1940s the economizers could be cleaned at the regular
weekend stop.
The construction utilized was very successful. One of the early Scandinavian boilers (Figure 3) 160
t/day at Korsnäs, operated still almost 50 years later [3].
Development of recovery boiler technology
The use of Kraft recovery boilers spread fast as functioning chemical recovery gave Kraft pulping
an economic edge over sulfite pulping [4]. The first recovery boilers had horizontal evaporator
surfaces, followed by superheaters and more evaporation surfaces. These boilers resembled the
state-of-the-art boilers of some 30 years earlier. This trend has continued until today. Since a halt in
the production line will cost a lot of money the adopted technology in recovery boilers tends to be
conservative.
The first recovery boilers had severe problems with fouling [5]. Tube spacing wide enough for
normal operation of a coal fired boiler had to be wider for recovery boilers. This gave satisfactory
performance for a week, before a water wash was required. Mechanical sootblowers were also
quickly adopted. To control chemical losses and lower the cost of purchased chemicals electrostatic
precipitators were added. Lowering dust losses in flue gases has more than 60 years of practice.
193
One should also note square headers in the 1940
recovery boiler, Figure 3. The air levels in
recovery boilers soon standardized to two: a
primary air level at the char bed level and a
secondary above the liquor guns.
In the first tens of years the furnace lining was
of refractory brick. The flow of smelt on the
walls causes extensive replacement and soon
designs that eliminated the use of bricks were
developed.
Improving air systems
To achieve solid operation and low emissions
the recovery boiler air system needs to be
properly designed. Air system development
Figure 3: Korsnäs recovery boiler 1943. [3]
continues and has been continuing as long as
recovery boilers have existed [6]. As soon as the
target set for the air system has been met new
targets are given. Currently the new air systems have achieved low NOx, but are still working on
lowering fouling. Table 1 visualizes the development of air systems.
Table 1: Development of air systems. [6]
Air system
1st generation
2nd generation
3rd generation
Main target
Stable combustion of black
liquor
high reduction
decrease sulfur emissions
4th generation
low NOx, ...
5th generation
decrease superheater and boiler
bank fouling
But also should
Burn liquor
Burn black liquor, high
reduction
reduction and low sulfur
emission
reduction, low emissions
The first generation air system in the 1940’s and 1950’s consisted of a two level arrangement;
primary air for maintaining the reduction zone and secondary air below the liquor guns for final
oxidation [7]. The recovery boiler size was 100 – 300 tds/d and black liquor concentration 45 – 55
%. Frequently to sustain combustion auxiliary fuel needed to be fired. Primary air was 60 – 70 % of
total air with secondary the rest. In all levels openings were small and design velocities were 40 –
45 m/s. Both air levels were operated at 150oC. Liquor gun or guns were oscillating. Main problems
were high carryover, plugging and low reduction. But the function, combustion of black liquor,
could be filled.
The second generation air system targeted high reduction. In 1954 CE moved their secondary air
from about 1 m below the liquor guns to about 2 m above them [7]. The air ratios and temperatures
remained the same, but to increase mixing 50 m/s secondary air velocities were used. CE changed
their frontwall/backwall secondary to tangential firing at that time. In tangential air system the air
nozzles are in the furnace corners. The preferred method is to create a swirl of almost the total
194
furnace width. In large units the swirl caused left and right imbalances. This kind of air system with
increased dry solids managed to increase lower furnace temperatures and achieve reasonable
reduction. B&W had already adopted the three-level air feeding by then.
Third generation air system was the three level air. In Europe the use of three levels of air feeding
with primary and secondary below the liquor guns started about 1980. At the same time stationary
firing gained ground. Use of about 50 % secondary seemed to give a hot and stable lower furnace
[8]. Higher black liquor solids 65 – 70 % started to be in use. Hotter lower furnace and improved
reduction were reported. With three level air, higher dry solids and a hotter furnace the sulfur
emissions could be kept on an acceptable level.
Fourth generation air systems are the multilevel air and the vertical air. As the feed of black liquor
dry solids to the recovery boiler have increased, achieving low sulfur emissions is not anymore the
target of the air system. Instead, low NOx and low carryover are the new targets.
Multilevel air
The three-level air system was a significant improvement, but better results were required. Use of
CFD models offered a new insight of air system workings. The first to develop a new air system
was Kvaerner (Tampella) with their 1990 multilevel secondary air in Kemi, Finland, which was
later adapted to a string of large recovery boilers [9].
Kvaerner also patented the four level air system, where additional air level is added above the
tertiary air level. This enables significant NOx reduction.
Vertical air
Vertical air mixing (Figure 4) was invented by
Erik Uppstu [10]. His idea is to turn traditional
vertical mixing to horizontal mixing. Closely
spaced jets will form a flat plane. In traditional
boilers this plane has been formed by secondary
air. By placing the planes to 2/3 or 3/4
arrangement improved mixing results. Vertical
air has a potential to reduce NOx as staging air
helps in decreasing emissions [11].
In vertical air mixing, primary air supply is
arranged conventionally. Rest of the air ports are
placed on interlacing 2/3 or 3/4 arrangement.
Black liquor dry solids content
As fired black liquor is a mixture of organics,
inorganics and water. Typically the amount of
water is expressed as mass ratio of dried black
liquor to unit of black liquor before drying. This
ratio is called the black liquor dry solids content.
Figure 4: Principle of vertical air (Kaila and
Saviharju, 2003).
If the black liquor dry solids content is below 20 % or water content in black liquor is above 80 %
the net heating value of black liquor is negative (Figure 5). This means that all heat from
combustion of organics in black liquor is spent evaporating the water it contains. The higher the dry
195
solids content is, the less water the black liquor contains and the hotter the adiabatic combustion
temperature is.
The black liquor dry solids content has always been limited by the ability of available evaporation
technology to handle highly viscous liquors [12]. The virgin black liquor dry solids contents of
recovery boilers are shown in Figure 6 as a function of purchase year of the boiler.
NET HEATING VALUE, MJ/kg dry solids
15.0
10.0
5.0
0.0
0
10
20
30
40
50
60
70
80
90
-5.0
-10.0
BLACK LIQUOR DRY SOLIDS, %
Figure 5: Net heating values of typical Kraft liquors at various concentrations.
90
85
Maximum
Virgin dry solids, %
80
75
Average
70
65
60
55
50
1975
1980
1985
1990
1995
2000
2005
Delivery year
Figure 6: Virgin black liquor dry solids contents as a function of the purchase years of recovery
boilers.
According to Figure 6 the average dry solids content of virgin black liquors has increased. This is
especially true for latest very large recovery boilers. Design dry solids contents for green field mills
have been either 80 or 85 % dry solids. 80 % (or before that 75 %) dry solids has been in use in
Asia and South America. 85 % (or before that 80 %) has been in use in Scandinavia and Europe.
196
High temperature and pressure recovery boiler
600
6000
500
5000
400
4000
300
Temperature
Pressure
Capacity
3000
200
2000
100
1000
Capacity, tds/d
Steam temperature, oC, Steam
pressure, bar
Development of recovery boiler main steam pressure and temperature was rapid in the beginning,
(Figure 7). By 1955, not even 20 years from birth of recovery boiler highest steam pressures were
10.0 MPa and 480oC. The pressures and temperatures used then backed downward somewhat due to
safety [13]. By 1980 there were about 700 recovery boilers in the world [8].
0
0
1937 1942 1947 1952 1957 1962 1967 1972 1977 1982 1987 1992 1997 2002 2007
Delivery year
Figure 7: Development of recovery boiler pressure, temperature and capacity.
Safety
One of the main hazards in operation of recovery boilers is the smelt-water explosion. This can
happen if even a small amount of water is mixed with the solids in high temperature. Smelt-water
explosion is purely a physical phenomenon.
The smelt water explosion phenomena have been studied by Grace [14]. The liquid - liquid type
explosion mechanism has been established as one of the main causes of recovery boiler explosions.
In the smelt water explosion even a few liters of water, when mixed with molten smelt can violently
turn to steam in few tenths of a second. Char bed and water can coexist as steam blanketing reduces
heat transfer. Some trigger event destroys the balance and water is evaporated quickly through
direct contact with smelt. This sudden evaporation causes increase of volume and a pressure wave
of some 10 – 100000 Pa. As the surface areas are large in the boiler, the force caused by this
pressure wave is usually sufficient to cause all furnace walls to bend out of shape. Safety of
equipment and personnel requires an immediate shutdown of the recovery boiler if there is a
possibility that water has entered the furnace. All recovery boilers have to be equipped with a
special automatic shutdown sequence.
The other type of explosions is the combustible gases explosion. For this to happen the fuel and the
air have to be mixed before the ignition. Typical conditions are either a blackout (loss of flame)
without purge of furnace or continuous operation in a substoichiometric state. To detect blackout
flame monitoring devices are installed, with subsequent interlocked purge and startup. Combustible
gas explosions are connected with oil/gas firing in the boiler. As also continuous O2 monitoring is
practiced in virtually every boiler the noncombustible gas explosions have become very rare.
197
Chemical processes in the furnace
Recovery boiler processes efficiently capture inorganic and organic chemicals in the black liquor.
Efficient inorganic chemicals processing can be seen as high reduction rate. The furnace also
disposes of all organics in black liquor. This means stable and complete combustion. Reduction
(removal of oxygen) and combustion (reaction with oxygen) are opposite reactions. It is difficult to
achieve both at same unit operation, furnace.
Other furnace requirements are even more complex. A recovery boiler should have a high thermal
efficiency. It should produce low fouling ash. Processes in the recovery boiler should be
environmentally friendly and produce a low level of harmful emissions. In spite of successes,
optimizing recovery boiler chemical processes is difficult. Processes are complex and there are
several streams to and from the recovery boiler.
H2O
CO2
Na2SO4
Na2CO3
Combustion
Spraying
Droplets
SO2
Volatiles
Drying
Devolatilization
H2S
Na
NaOH
Char combustion
Reoxidation
of Na2S
Gasification
Release of Na
Carbon
Reduction
Na2S
Na2S
Na2CO3
Figure 8: Some of the reactions in the lower furnace.
There are many simultaneous reactions going on in the lower furnace, Figure 8. First there are the
black liquor combustion processes. Drying occurs when water is evaporated, Devolatilization
occurs when droplet size increases and gases generated inside the droplet are released. Finally char
combustion takes place when carbon is burned off. In the lower part of the furnace there are char
bed reactions. These consist mostly of inorganic salt, especially melt reactions. In the upper furnace
there is volatiles combustion. Almost all other combustion reactions are concluded. Sodium sulfate
and carbonate fume formation with other aerosol reactions take place. There are a multitude of
chemical reactions taking place in the recovery boiler. The best way to study them is to look at them
main component by main component.
198
Smelt
The smelt is the product of inorganic reactions in the recovery furnace. At the same time the carbon
is consumed by the residual inorganic portion melts. Inorganics flow out of the furnace through
smelt spouts (Figure 9). The amount of smelt inside recovery boiler furnace has been measured by
Kelly et al. [15]. They found the smelt content per furnace unit area to be about 250 kg/m2 for a
decanting CE unit and about 140 kg/m2 for a B&W unit. The residence times found were 44 and 25
minutes respectively.
Figure 9: Smelt flow from char bed. [16]
Smelt temperature is about 100oC higher than initial deformation temperature [3]. In older low
solids boilers the smelt temperatures are 750 – 810oC [17]. In modern boilers with a high content of
dry solids the typical smelt temperatures are 800 – 850oC. The smelt flow corresponds typically
from 0.400 to 0.480 kg per kilogram of incoming black liquor dry solids flow.
Reduction and sulfidity
The main process property of the smelt is the reduction. Reduction is the molar ratio of Na2S to
Na2SO4,
Reduction =
Na 2 S
Na 2 S + Na 2 SO 4
(1)
The higher the reduction the lower the amount of sodium that reaches the cook unusable. Reduction
rates of 95 ... 98 % are not uncommon in well operated recovery boilers. Usually the reduction
efficiency increases as the char bed temperature increases. From thermodynamical equilibrium we
can note that there should be very little of sodium oxides and thiosulfate.
Sulfidity is the molar ratio of sodium sulfide to the total alkali content.
S tot
Sulfidity =
Na 2 + K 2
(2)
199
This equation is widely in use because of ease of measuring Sulfidity depends on the liquor
circulation of the mill. Too high a sulfidity causes operating problems for the recovery boiler.
Especially increased sulfidity increases SO2 and TRS emissions [18].
100
98
Reduction, S/(S+SO4)
96
94
92
90
88
95 % reduction in WWL
90
85
80
75
70
86
84
82
80
0
5
10
15
20
25
30
35
40
45
Alkali in weak white liquor, g(NaOH)/l
Figure 10: Effect of weak white liquor composition on reduction in green liquor, reduction is smelt
95 %, sulfidity 35 %.
Often the typical mill analysis of reduction rate is done for green liquor. Alkali in the green liquor
will typically result in lower values that what is measured in smelt, Figure 10. Typically in modern
mills the reduction in green liquor is 2 – 3 percent units lower that in the smelt.
Sodium
Sodium is released during the black liquor combustion and char bed reactions through vaporization
and reduction of sodium carbonate. Sodium release increases as a function of temperature. At the
beginning of combustion a large portion of sodium is connected to the organic portion of the black
liquor. At the end of volatiles release almost all of it is inorganically bound.
40
Na-release g/kgka
35
30
25
20
15
10
5
0
0
2
4
6
8
10
12
14
16
18
CO3(ESP), w-%
Figure 11: Sodium release to ESP ash as function of carbonate in ash in industrial boilers.
200
Sodium release in Kraft recovery boilers increases with increasing lower furnace temperature
(Figure 11). It has been assumed that in industrial boilers all of the ESP dust is from reactions with
vaporized sodium. In addition the amount of sodium released as a function of carbonate in ESP dust
seems to increase. Increase in carbonate indicates increase in lower furnace temperature [19].
Sodium content in black liquors is around 20 w-%. This means that sodium release in recovery
furnace is about 10% of the sodium in black liquor.
Much studied reactions involving sodium are hydroxide formation, reduction reactions, and sulfate
formation with hydroxides, sulfate formation with chlorides, sulfate formation with carbonate and
carbonate formation.
Recovery boiler design
In a pulp mill there are three main recovery
boiler purposes. The first is to burn the
organic material in the black liquor to
generate high pressure steam. The second is
to recycle and regenerate spent chemicals in
black liquor. The third is to minimize
discharges from several waste streams in an
environmentally friendly way. In a recovery
boiler, concentrated black liquor is burned in
the furnace and at the same time reduced
inorganic chemicals emerge molten. A
modern recovery boiler, Figure 12, has
evolved a long way from the first recovery
boilers.
Figure 12: Typical recovery boiler in operation,
One noticeable trend has emerged in recent
Gruvön. [20]
years. The average size of recovery boiler has
grown significantly in each year (Figure 13).
The nominal capacity of new recovery boilers at the beginning of the 1980s was 1700 metric tons of
dry solids per day. This was regarded as the maximum at that time. By year 2000 more than ten
recovery boilers, capable of handling 2500 – 3500 metric tons of dry solids per day were built. At
2002 a recovery boiler with nominal capacity of 4450 tds/d was bought. The maximum design
capacity has increased because there is less water in black liquor, liquor spraying is now more
uniform, new computer controls mean better stability and controllability and most importantly, new
pulping lines of corresponding capacity can be built.
Key recovery boiler design alternatives
There are alternative solutions for designing recovery boilers. Major recovery boiler design options
are; screen or screenless superheater area design, single drum or two-drum, lower furnace tubing
material; furnace bottom tubing material, vertical or horizontal boiler bank and economizer
arrangement and number and type of air levels.
Key design specifications
When sizing a recovery boiler some key design specifications are usually given to the boiler vendor
to do the design. Typically given are dry solids capacity (without ash), black liquor gross heat value
(without ash), black liquor elementary analysis (without ash), black liquor dry solids content from
evaporation (without ash), desired main steam conditions, feed water inlet temperature and
201
economizer flue gas outlet temperature. Sometimes the desired superheated steam temperature
control point is also given in % of MCR (Maximum continuous rating).
4500
4000
Maximum
3500
Capacity, tds/d
3000
2500
2000
Average
1500
1000
500
0
1975
1980
1985
1990
1995
2000
2005
Delivery year
Figure 13: Size of recovery boiler versus startup year.
Black liquor dry solids flow is the key design criteria. It establishes the required size of the boiler.
With elementary analysis and dry solids one can calculate the heat released in the furnace. With
water and steam values the MCR steam flow is established. It should be noted that when black
liquor is sprayed to the furnace it contains ash collected from the electrostatic precipitator and ash
hoppers. Because ash free black liquor is the input flow to the recovery plant, it is usually chosen as
the design base.
Single drum
All modern recovery boilers are of single drum type. The single drum has replaced the two drum (or
bi-drum) construction in all but the smallest, low pressure boilers. The same trend but 20 years
earlier happened with coal fired boilers.
Screen or screenless boiler
One of the key design issues is whether or not to have a screen in the recovery boiler (Figure 14). A
screen is a low temperature heat surface that is put in front of the superheater area. Almost always
the screen is an evaporative surface. There are a few screens with saturated steam entering them, but
the experience has not been too favorable.
Benefits of the screen are
Screen stops part of the carryover from furnace
Screen blocks radiation from the furnace and reduces superheater surface temperatures. A
screen protects superheater from corrosion
Screen itself is cold surface with very minor corrosion
Screen captures unburnt liquor particles. Less unburnt reaches superheater surfaces,
especially lower bends. This decreases superheater corrosion rates.
Screen evens out the flow somewhat. This blocking effect is small if the screen is not covered
with deposits.
Screenless superheater section is higher and so has higher building volume and cost.
Negative issues with the screen are
202
-
-
There has been number of cases where
fallen deposits have caused the screen to
rupture. This has caused boiler explosions
and long shutdown times for repairs.
Superheater surfaces are more affected
with radiation behind the screen than
behind the nose
Screen captures heat. This reduces
superheating.
Fear of boiler accidents caused by fallen
deposits caused the boiler purchasers in US to
avoid buying new boilers with screen. In
Scandinavia boilers with screen have been
bought all the time. Even in US some new
boilers with screen have been bought.
NEWRCB17
EkV, 11.1993
Figure 14: Screen at left, screenless boiler at
right.
Evolution of recovery boiler design
There have been significant changes in the Kraft pulping process in recent years [21, 22, 23].
Increased use of new modified cooking methods and oxygen delignification has increased the
degree of organic residue recovery. Black liquor properties have reflected these changes (Table 2).
Table 2: Development of black liquor properties. [19]
Property
Liquor dry solids, kg dry solids/ton pulp
Sulphidity, Na2S/(Na2S+NaOH)
Black liquor HHV, MJ/kg dry solids
Liquor dry solids, %
Elemental analysis, % weight
C
H
N
Na
S
Cl
K
Cl/(Na+K), mol-%
K/(Na+K), mol-%
Net heat to furnace, kW/kg dry solids
Combustion air* required,
m3n/kg dry solids
Flue gas* produced, m3n/kg dry solids
Two drum
1982
1700
42
15.0
64
Modern
1992
1680
45
13.9
72
Current
2002
1780
41
13.0
80
36.4
3.75
0.1
18
5.4
0.2
0.75
0.70
2.39
34
3.5
0.1
18.4
5.9
0.4
1.0
1.37
3.10
31.6
3.4
0.1
19.8
6
0.8
1.8
2.49
5.07
13600
4.1
12250
3.7
11200
3.4
4.9
4.3
3.9
* At air ratio 1.2
Changes in investment costs, increases in scale, demands placed on energy efficiency and
environmental requirements are the main factors directing development of the recovery boiler [24].
Steam generation increases with increasing black liquor dry solids content. For a rise in dry solids
content from 65% to 80% the main steam flow increases by about 7%. The increase is more than
203
2% per each 5% increase in dry solids. Steam generation efficiency improves slightly more than
steam generation itself. This is mainly because the drier black liquor requires less preheating.
There are recovery boilers that burn liquor with solids concentration higher than 80%. Unreliable
liquor handling, the need for pressurized storage and high pressure steam demand in the
concentrator has frequently prevented sustained operation at very high solids. The main reason for
the handling problems is the high viscosity of black liquor associated with high solids contents.
Black liquor heat treatment (LHT) can be used to reduce viscosity at high solids [25].
For pulp mills the significance of electricity generation from the recovery boiler has been
secondary. The most important factor in the recovery boiler has been high availability. The
electricity generation in recovery boiler process and steam cycle can be increased by elevated main
steam pressure and temperature or by higher black liquor dry solids [26].
Increasing main steam outlet temperature increases the available enthalpy drop in the turbine. The
normal recovery boiler main steam temperature 480°C is lower than the typical main steam
temperature of 540°C for the coal and oil fired utility boilers. The main reason for choosing a lower
steam temperature is to control superheater corrosion. Requirement for high availability and use of
less expensive materials are often cited as other important reasons.
Two drum recovery boiler
Most of the recovery boilers operating today are of two drum design. Their main steam pressure is
typically about 8.5 MPa and temperature 480 °C. The maximum design solids handling capacity of
the two drum recovery boiler is about 1700 tds/d. Three level air and stationary firing are employed.
The two drum boiler (Figure 15) represents one successful stage in a long evolutionary path and
signified a design with which the sulfur emissions could be successfully minimized. Main steam
temperature was increased to 480 °C using this design.
Two drum recovery boilers are constructed with water screen to protect superheaters from direct
furnace radiation, lower flue gas temperatures and to decrease combustible material carry-over to
superheaters. The two drum boiler was the first type to use vertical flow economizers, which
replaced horizontal economizers because of their improved resistance to fouling.
Modern recovery boiler
The modern recovery boiler is of a single drum design, with vertical steam generating bank and
wide spaced superheaters. The most marked change around 1985 was the adoption of single drum
construction. The construction of the vertical steam generating bank is similar to the vertical
economizer. Vertical boiler bank is easy to keep clean. The spacing between superheater panels
increased and leveled off at over 300 but under 400 mm. Wide spacing in superheaters helps to
minimize fouling. This arrangement, in combination with sweetwater attemperators, ensures
maximum protection against corrosion. There have been numerous improvements in recovery boiler
materials to limit corrosion [27, 28, 29, 30].
The effect of increasing dry solids concentration has had a significant effect on the main operating
variables. The steam flow increases with increasing black liquor dry solids content. Increasing
closure of the pulp mill means that less heat per unit of black liquor dry solids will be available in
the furnace. The flue gas heat loss will decrease as the flue gas flow diminishes. Increasing black
liquor dry solids is especially helpful since the recovery boiler capacity is often limited by the flue
gas flow.
204
A modern recovery boiler (Figure 16), consists
of heat transfer surfaces made of steel tube;
furnace-1, superheaters-2, boiler generating
bank-3 and economizers-4. The steam drum-5
design is of single-drum type. The air and black
liquor are introduced through primary and
secondary air ports-6, liquor guns-7 and tertiary
air ports-8. The combustion residue, smelt exits
through smelt spouts-9 to the dissolving tank-10.
The nominal furnace loading has increased
during the last ten years and will continue to
increase [31]. Changes in air design have
increased furnace temperatures [32, 33, 34, 35].
This has enabled a significant increase in hearth
solids loading (HSL) with only a modest design
increase in hearth heat release rate (HHRR). The
average flue gas flow decreases as less water
vapor is present. So the vertical flue gas
velocities can be reduced even with increasing
temperatures in lower furnace.
The most marked change has been the adoption
of single drum construction. This change has
been partly affected by the more reliable water
quality control. The advantages of a single drum
boiler compared to a bi drum are the improved
safety and availability. Single drum boilers can
be built to higher pressures and bigger
capacities. Savings can be achieved with
decreased erection time. There is less tube joints
in the single drum construction so drums with
improved startup curves can be built.
Figure 15: Two drum recovery boiler.
The construction of the vertical steam generating
bank is similar to the vertical economizer, which
based on experience is very easy to keep clean
[36]. Vertical flue gas flow path improves the
cleanability with high dust loading [37]. To
minimize the risk for plugging and maximize the
efficiency of cleaning both the generating bank
and the economizers are arranged on generous
side spacing. Plugging of a two drum boiler
bank is often caused by the tight spacing
between the tubes.
The spacing between superheater panels has
increased. All superheaters are now wide spaced
to minimize fouling. This arrangement, in
combination with sweetwater attemperators,
Figure 16: Modern recovery boiler.
205
ensures maximum protection against corrosion. With wide spacing plugging of the superheaters
becomes less likely, the deposit cleaning is easier and the sootblowing steam consumption is lower.
Increased number of superheaters facilitates the control of superheater outlet steam temperature
especially during startups.
The lower loops of hottest superheaters can be made of austenitic material, with better corrosion
resistance. The steam velocity in the hottest superheater tubes is high, decreasing the tube surface
temperature. Low tube surface temperatures are essential to prevent superheater corrosion. A high
steam side pressure loss over the hot superheaters ensures uniform steam flow in tube elements.
Current recovery boiler
Recovery boiler evolution is continuing strongly. Maximizing electricity generation is driving
increases in main steam pressures and temperatures. If the main steam pressure is increased to 10.4
MPa and temperature 520oC, then the electricity generation from recovery boiler plant increases
about 7 %. For design dry solids load of 4000 tds/d this means an additional 7 MW of electricity.
The current recovery boiler can be much larger than the previous ones. Boilers with over 200 square
meter bottom area have been bought. Largest recovery boilers are challenging circulating fluidized
boilers for the title of largest bio-fuel fired boiler.
The superheater arrangement is designed for optimum heat transfer with extra protection to furnace
radiation. Mill closure and decreased emissions mean higher chloride and potassium contents in
black liquor. Almost all superheaters are placed behind the bullnose to minimize the direct radiative
heat transfer from the furnace. Increasing superheating demand with increasing pressure decreases
the need for boiler bank and water screen arrangement.
The higher main steam outlet temperature requires more heat to be added in the superheating
section. Therefore the furnace outlet gas temperature has increased. The alternative is to
significantly increase superheating surface and decrease boiler bank inlet flue gas. If boiler bank
inlet gas temperature is reduced the average temperature difference between flue gas and steam is
also decreased. This reduces heat transfer and substantially more superheating surface is needed.
This approach has been abandoned because of increased cost. With increasing dry solids content the
furnace exit temperature can safely increase without fear of corrosion caused by carryover.
Increasing recovery boiler main steam temperature affects the corrosion of the superheaters.
Designing for higher recovery boiler main steam pressure increases the design pressure for all boiler
parts. The recovery boiler lower furnace wall temperatures increase with higher operating pressure.
New better but more expensive lower furnace materials are used. The air flow per unit of black
liquor burned in the recovery boiler furnace decreases. Therefore the number of air ports will
decrease.
State of the art and current trends
Recovery boiler design changes slowly. There are however some features that boilers bought today
have in common. State of the art recovery boiler has the following features;
− One drum boiler with 3-part superheater and water screen (optional)
− Steam design data 9.2 MPa / 490oC
− Design black liquor dry solids 80% with pressurized heavy liquor storage tank
− Liquor temperature control with flash tank, indirect liquor heaters for backup
− DNCG combustion in the boiler
− Low emissions of TRS, SO2 and particulates
206
− Flue gas cleaning with ESP (no scrubbers)
The design changes occurring can be listed. Current trends for recovery boilers are
− Higher design pressure and temperature due to increasing demands of power generation
− Use of utility boiler methods to increase steam generation
− Superheater materials of high-grade alloys
− Further increase in black liquor solids towards 90% by concentrators using elevated steam
pressure
− Combustion of biological effluent treatment sludge and bark press filtrate effluent
− CNCG burner (LVHC gases)
− Dissolving tank vent gases returned to the boiler
− Advanced air systems for NOx control
Steam generation
Steam generation will depend on recovery boiler design parameters. A rough estimate can be seen
from Figure 17. About 3.5 kgsteam/kgBLdry solids is often used as a base value. Specific steam
production can be used to size the other components in recovery boiler plant.
Both black liquor dry solids and higher heating value affect the steam generation. Also black liquor
sulfidity and main steam values affect the steam generation efficiency. For accurate steam
generation one should always calculate the mass and energy balances.
5
4.5
Steam flow, kg/kgds
4
3.5
3
2.5
Mill operating data
2
1.5
1
0.5
0
60
65
70
75
80
85
Black liquor dry solids, %
Figure 17: Specific steam generation kgsteam/kgBLdry solids as function of black liquor dry solids.
Heat transfer surface design and material selection
When recovery boilers are designed one of the most difficult questions that arise is; what kind of
materials should one use for different parts of the boiler. Corrosion is typically divided into areas
based on location of corrosion; water side corrosion, high temperature corrosion and low
temperature corrosion
Water side corrosion occurs in the steam/water side of the boiler tubes. Most often the cause is
impurities in the feedwater. High temperature corrosion occurs typically in the superheaters. Low
207
temperature corrosion occurs in the economizers and air heaters. Low temperature corrosion is often
associated with formation of acidic deposits.
Furnace design and materials
Recovery boiler furnace walls and floors have long been under investigation for better materials.
Especially the floor construction and materials affect the recovery boiler safety [38]. Most of the
critical leaks in the furnace occur in the lowest 3 m of furnace walls. Figure 18 shows some of the
used possibilities for lower furnace construction. The lowest is studding and refractory. Corrosion
protection with studs is excellent, but this solution requires large amount of maintenance and repair
work. The middle picture shows membrane wall with welded corrosion protection of alloyed
material. Welded furnace wall is of comparable price to compound tubing, top, which is the most
used recovery boiler wall construction. All new recovery boilers are of membrane design. Tangent
tubing was phased out late 1980’s [3].
It is important to protect the floor tubes from
high temperatures. Proper design of water
circulation lowers maximum temperatures.
Sufficient water flow needs to be maintained
in the tubes to cool them and to remove
created steam bubbles. Usually the
requirement is flow velocities ≥ 0.5 m/s in all
tubes.
The floor angle in modern boilers needs to be
upwards with the flow. As bottom tubes are
supported by steel beams they hang a little.
Floor angle helps to avoid parts where steam
bubbles could get stuck. Depending on the
distance between the support tubes, the angle
needs to be from 2.5 to 4 degrees. Smelt
spouts need to be high enough so that all
floor is covered with frozen smelt layer.
Especially critical is the area farthest from
the smelt spouts and the area right in front of
the smelt spouts. In practice it seems that 200
– 300 mm is enough. Too much height will
cause problems when we try to empty the
bed for shutdown.
Furnace tube materials
Some of the most typical furnace tube
materials are listed in Table 3. Many more Figure 18: Different recovery boiler walls: lowest
have been tried and for one reason or another
refractory with studs, middle protective welded
abandoned. Carbon steel was the material of cladding, and highest finned membrane wall made
choice before the compound tubing. Upper
from composite tubes.
furnace from above the highest air level is
always made from carbon steel. Carbon steel
seems to resist most corrosive conditions at oxygen rich conditions. Carbon steel has also been
lately used as floor material, Figure 19. Floors with carbon tube are not susceptible to SCC
208
corrosion. It should be noted that bare carbon tubes can not resist firing of black liquor or contact
with the smelt. Some care should be taken when operating recovery boilers with carbon steel floors.
Table 3: Properties of typical floor tube materials.
Main elements
Thermal expansion, 10–6 /°C
Thermal cond., W/m°C
SCC resistance
Corrosion resistance
Carbon
steel
Fe
13.5
41
Excellent
Low
304L
20Cr–10Ni
17.5
19
Low
Moderate
Sanicro 38
(Alloy 825)
20Cr–40Ni
14.9
16
High
Excellent
Sanicro 65
(Alloy 625)
20Cr–60Ni
13.9
14
Excellent
High
Extensive research related to corrosion of different materials in molten polysulfides has been
carried out in Finland. This research showed that Sanicro 38-type composite material had the best
corrosion resistance among the steels studied [39]. Test panels made of Sanicro 38 installed in 1991
and 1994 have not shown any alarming corrosion. Nor have there been any reported cracking found
in recovery boiler bottoms made from Sanicro 38 since 1995. This highly alloyed material seems to
have good corrosion resistance, but it is fairly expensive.
Figure 19: Modern carbon steel furnace bottom (Andritz).
Stainless steel 304L seems to last well in the furnace walls above the char bed. It is very resistant to
sulfidation. SCC in the tubes at the furnace bottom tubes has made manufactures and recovery
boiler owners search for replacement materials in that area [40].
Suppliers’ current recommendations are to use modified alloys in the front and rear bends and close
to the side walls. To facilitate weld inspection the whole lower furnace is often made of modified
alloys up to and over the primary air ports. The present favorite is Sanicro 38 composite tube. In
addition of high content of chrome and nickel the tube has about the same thermal expansion
coefficient that the carbon steel.
209
Sanicro 65 (Alloy 625) composite tubing is another possibility. It has very favorable properties
considering thermal fatigue and stress corrosion cracking. There are some reports of failure. Thus,
the use of 625 needs more study at the moment. Another area under research is the air port cracking
[41]. Primary air ports and smelt openings seem to exhibit cracking. Thermal cycling and smelt
contact are suspected causes.
Use of compound tubing has about 30 year history in recovery boilers. Compound tubing is
expensive and the selection of materials is limited. Some competing alternatives are chromizing of
tubes [42, 43]. Another popular method is spray of plasma coating. Compound surface can also be
replaced by welded surface. Of all above methods quality control is easiest with compound tube.
Membrane materials
Membrane materials should be similar to the tube material used. Carbon steel fin is used in the case
of carbon steel tubes. Either composite membrane or totally stainless steel membrane is used in case
of composite floor tubing.
Fins receive thermal radiation and need to conduct heat to the tube proper. Fin surface is thus at
higher temperature than the tube surface. In high heat flux areas and with wide fins this can lead to
tube cracking. A composite membrane has better thermal conductivity as compared to solid
material, which is important especially in case of wide tube spacing.
Refractory and studs
Small studs can be welded to tube and then covered with refractory. Refractory is also a fair
corrosion protection. It should be remembered that both refractory and studs need regular
replacement. It is also impossible to inspect a floor for faults after it has been studded. Because of
this neither refractory nor studs is anymore widely used in recovery boilers
Superheater design and materials
Recovery boilers suffer from superheater corrosion. Corrosion is the main problem that limits the
ability of Kraft recovery boiler to produce electricity [44]. In coal fired boilers much higher
superheater temperatures are typically used. In comparison to coal fired boilers Kraft recovery
boilers have higher rates of alkali metals, chloride in gaseous form and often highly reducing
conditions caused by carryover particles On the other hand contents of some high temperature
corrosion causing substances like antimony, vanadium and zinc are typically low.
Loss of tube thickness can be caused by sulfidation, alkali or chloride corrosion. Typically
superheaters exhibit higher corrosion resistance if their tube materials have higher contents of
chromium [45].
Effect of steam outlet temperature
Main steam temperature is the main parameter that affects the choice of superheater materials. The
rule of thumb is to keep the superheater surface temperature below the first melting temperature of
deposits [46]. Corrosion rates in final superheaters are increased because superheater material
temperatures are high. As can be seen there typically is some temperature range where the corrosion
rate is acceptable. Increasing tube temperature by some tens of degrees can significantly increase
corrosion rate.
Steam side heat transfer coefficients in typical recovery boiler superheaters are low. Superheater
surface temperature can be tens of degrees higher than the bulk steam temperature. It can easily be
seen that surface temperatures and thus corrosion rates are greatly affected by superheater
210
positioning. Furnace radiation can effectively be reduced by placing a screen to block radiation heat
flux. Therefore placing the hottest superheaters behind the nose or screen will significantly decrease
corrosion.
Typical materials
Typical primary superheater materials, when they are protected from direct furnace radiation are
carbon steel. Secondary and tertiary superheater materials contain often 1 to 3% Cr. These kinds of
materials are easy to weld and have good corrosion protection. T22/10CrMo910 material can
usually be used up to 495oC steam outlet temperatures [47]. With higher temperatures and higher
chloride and potassium contents in the black liquor it is advisable to use higher chromium
containing tubes.
Figure 20: Effect of chromium content on corrosion rate in laboratory tests. [48]
Fujisaki et al. [48] found that recovery boiler
superheater corrosion is much reduced when
chrome content of the superheater tube is
increased, Figure 20. Similar trend was found
from Swedish studies in Norrsundet recovery
boiler [49]. They found that alloyed austenitic
materials 304L and Sanicro 28 had much better
corrosion resistance than high alloyed ferritic
materials SS2216 and X20. Stainless steel lower
bends in hottest superheaters have been used for
tens of years.
Sealing the roof
Superheater tubes and the furnace roof need to
for a gas tight construction. This is usually done
by box made of steel plate, Figure 21. If the
sealing is not tight or leaks corrosive salt builds
on top of the roof. Superheaters need to be
Figure 21: Superheater roof seal box
arrangement.
211
supported. Hanger rods are tied to seal box. Individual tubes hang from horizontal supports inside
the box. Thermal movement needs to be accounted for. This means that superheater tubes can not
hang from headers.
Boiler bank design and materials
Two drum boiler banks in recovery boilers suffer form mud drum corrosion [43]. This type of
corrosion is caused by steam from sootblowing wetting the salt at tube joints in lower drum. The
progress of the near drum corrosion can be monitored with ultrasonic equipment [50].One
problematic failure type is caused by vibrations from sootblowing. The longer the free tube length
the higher the resulting stress at joins. Industry practice states that maximum length of free tubes is
some 8 meters. Typically longer tubes are too flexible and will vibrate too much. This will create
cracks and faults in few years.
Finned design causes temperature differences
between fin and tube. This will create high
stresses at fin ends. To prevent these stresses cut
fins are preferred, Figure 22.
Some plugging problems have been reported on
the lower end of the boiler bank [3]. If lower
headers are located too close to each other they
trap falling material. Placing a sootblower close
to the lower end is also critical.
Economizer design and materials
Modern economizers are of vertical design.
Earliest horizontal economizers had severe
plugging problems and were replaced by cross
flow design. Cross flow economizer had lower
heat transfer coefficients and was more prone to
plugging than the modern vertical economizer.
In economizers the loss of tube thickness can be
caused by gas side corrosion; sulfidation and
acid dew point corrosion or water side erosion
corrosion.
Figure 22: Upper end of vertical flow boiler
generating bank showing left straight fin and
right cut fin, which minimizes thermal stresses
around weld. [51]
Lower ends of economizers in recovery boilers suffer from water side erosion corrosion. Typically
the symptoms are worst in the first few meters of economizer tube.
Recovery boiler economizers have hundreds of weld joints. Each weld even after inspection is
potentially problematic. Therefore the preference was to avoid unnecessary welds and use only
continuous tubes without butt welds. Largest boilers have economizer lengths of 27 meters. Carbon
steel tubes maximum length is some 23 meters. So in the newest boilers this preference can not be
adhered to. Attention should be paid to qualification of welds in economizer tube joints.
212
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215
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216

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