The History of Steam
Geography of a process plant
is the study of matter and the changes that take place inside that
matter. Our matter here is steam and the boiler. Wet steam, steam
and air, feed water and air, combustion - these are some of the
Quality of steam
and air don't mix
......Clean, clean steam
Feed water quality
dosing of feedwater
- TDS control
salt truck story
......Water softening and
......High TDS, big
need for Automatic Blowdown Control (ABCO)
11 Steam Table
may be at the correct pressure and temperature, but the quality of
steam is very important as well. Good quality steam must be dry.
Dry steam is steam which has a very high dryness fraction, ie
almost no moisture. Unfortunately, in most steam systems we are
faced with wet steam. Wet steam is steam containing a degree of
water. It can reduce plant productivity and product quality, and
can cause damage to most items of plant and equipment. It can
cause erosion and affect heat transfer processes.
is the ideal steam quality?
must not be wet, but with as high a dryness fraction as
should be no air present in steam.
should not contain any dirt.
then do we deliver it to our process.
fraction achieved from a typical shell boiler where the heat is
supplied only to the water and where the steam remains in contact
with the water surface, typically contains around 5% water by
mass. If the water content of the steam is 5% by mass, then the
steam is said to be 95% dry and has a dryness fraction of 0.95.
This is because bubbles of steam break through the water surface
and they cause turbulence and splashing. Therefore the steam space
contains a mixture of water droplets and steam. This kind of steam
is called wet steam.
The actual enthalpy of evaporation of
wet steam therefore is only 95% of the one in the steam table. So,
wet steam has lower usable heat energy than dry saturated steam.
Also, the specific volume of water is much lower than steam.
Therefore, the total specific volume of steam will also reduce by
the same factor.
of wet steam
boiler itself generates saturated steam which is inherently wet.
Most shell type steam boilers produce steam with a dryness
fraction of between 95 and 98%.
Priming and carryover
beacause of foaming and scale within the boiler shell increase
wetness still further.
Steam condenses on the way from the
boiler to the process as there is always a certain degree of heat
loss from the distribution pipe. The condensed water molecules
will eventually gravitate towards the bottom of the pipe forming a
film of water. Steam flowing over this water can raise ripples
that can build up into waves. The tips of the waves tend to break
off, throwing droplets of condensate into the steam
caused by wet steam
– a heat barrier. Water doesnt allow the heat in the steam
to cross over to the process, ie the medium to be heated. You can
see the temperature drop because of the layer of moisture in the
steam pipe. This hampers not just plant productivity by increasing
the cost of fuel, but also product quality.
Failure of valves and flowmeters due to rapid wear or
Corrosion and Wiredrawing. Water droplets
increase the amount of corrosion. Water droplets travelling at
high steam velocities will erode valve seats and fittings, a
condition known as wiredrawing.
Erratic operation of
control valves and flowmeters beacause of the above.
Pure steam cannot carry any impurities, but water can. These
impurities only increase scaling of pipework and heating surfaces.
a lot of steam systems, one can hear a thudding sound and feel the
pipes vibrating intermittently. This phenomenon is called water
hammer and is caused by water lying in the bottom of steam lines,
trapped in the steam system. Water is formed by steam condensing.
Steam traveling at up to 100 Kms per hour makes “waves”
as it passes over this condensate. (see fig.)
condensate forms, high-speed steam pushes it along, creating a
dangerous slug that grows larger and larger as it picks up liquid
in front of it. Anything that changes the direction - pipe
fittings, regulating valves, tees, elbows, blind flanges - can be
destroyed. In addition to damage from this “battering ram”,
high velocity water may erode fittings by chipping away at metal
Condensate allowed to collect in pipes isblown into waves by steam
passing over it and blocks flow at point A. Condensate in B causes
a pressure differential that allows steam pressure to push the
slug of condensate along like a battering ram.
back to basics, Momentum = mass X velocity
As water is 1000
times denser than steam, its mass and therefore momentum is very
large. At the high speed inside a steam pipe, it doesnt turn at
the bends, but crashes into them impacting the steam system. (
Practical: When you walk into factory where the pipes are old, but
the bends are new, you know they have problems with moisture and
water in their system).
If its not removed by moisture
separators or drained by traps, it can cause a lot of damage to
the steam system.
How do you know a plant
needs a moisture separator? When a plant experiences reduced heat
exchanger efficiency, erosion at pipe directional changes, erosion
to in-line equipment and water hammer, the installation of a
separator is a must. All are possible indicators that the presence
of entrained condensate particles and the accumulation of
condensate exists in the flow of steam.
remove the moisture that remains suspended in the steam flow,
which cannot be removed by either drainage or steam trapping. The
separator is designed to work in-line and removes approximately 95
- 98% of the entrained condensate particles.
have more mass and therefore more inertia than steam. (Water
hammer is caused because of this same reason, as, at bends the
steam passes easily, but the water slug crahes into the bend
In the Steamline plate type moisture
separator we take advantage of this inertia difference between
water and steam. The Msep contains intercepting plates in its
body. The steam + water mix has to change direction a number of
times to go through.
Inside a Moisture separator
happens? First, the separator has a larger cross-section than the
pipe. As the steam, with the entrained condensate particles,
enters the chamber of the separator it suddenly and momentarily
looses some of its velocity due to the sudden enlargement of the
separator chamber. Some drops just fall to the bottom of the
separator as condensate. The mass of most condensate particles
propels them forward into the impingement baffles. These drops
have too much inertia and mass to change direction when they hit
the plates, so they just collect on them or the outer perimeter
wall of the separator chamber and collect at a low point in the
separator. The dry steam flows around the intercepting plates and
comes out on the other side.
The MSep is fitted with a
suitable steam trap module from the bottom to ensure the efficient
removal of condensate, without the loss of live steam.
are other types of separators in use like the cyclonic and
coalescence types of separator, but the plate-type has an
acceptable efficiency for steam velocities which are typically in
the range of 10 m/s to 30 m/s.
and air don't mix
Effect of Air on
When air and other gases enter the
steam system, they consume part of the volume that steam would
otherwise occupy. The temperature of the air/steam mixture falls
below that of pure steam. There are tables available that show the
various temperature reductions caused by air at various
percentages and pressures.
of Air On Heat Transfer
The normal flow of steam
towards the heat exchanger surface carries air and other gases
with it. The steam velocity pushes the gases to the walls of the
heat exchangers, where they may block heat transfer. This
compounds the condensate drainage problem, because these gases
must be removed along with the condensate.
Since they do
not condense and drain by gravity, these non-condensible gases set
up a barrier between the steam and the heat exchanger surface. The
excellent insulating properties of air reduce heat transfer. In
fact ,under certain conditions as little as ½ of 1% by
volume of air in steam can reduce heat transfer efficiency by 50 %
as seen in the figure below.
Steam condensing in a heat transfer unit moves air to the side of
the heat transfer area. Here, the air collects or "plates
out" to form effective insulation.
non-condensible gases (primarily air) continue to accumulate and
are not removed, they may gradually fill the heat exchanger with
gases stop the flow of steam altogether. The unit is then “air
An air film 1mm thick has the same resistance
to heat transfer as water 1" thick or iron 4.3" thick..
As a film it acts as an insulator, in solution with steam it
deprives the steam of its full heating potential. In other words,
air will assume a part of the total volume or pressure that is
available. This is explained by Daltons Law of Partial
Daltons Law of Partial
In gas mixtures, each gas assumes a part
of the total volume or pressure. This is referred to as partial
pressure. The partial pressure of each gas is dependent upon its
proportion of the total mixture.
If we were to have a total
steam line pressure of 5 kg/cm2 g consisting of 80% steam and 20%
air the effective steam pressure would be:
0.80x 5 = 4.0 kg/cm2
And the effective air pressure would be:
0.20x 5 = 1.0
As a result the steam would effectively be 4 kg/cm2g
steam in a 5 kg/cm2g line. In checking a thermometer in the line
at that location we would find the temperature to be 151.2° C
for the 4 kg/cm2g steam and not 158.2° C for the 5 kg/cm2g
steam we would expect to find. That is a 7°C difference
between the two pressures. In addition there will also be a change
in kcal's.(Although the 4 kg/cm2g steam has more enthalpy of
latent heat per weight than does the 5 kg/cm2g steam it has less
by volume. Latent heat of evaporation at the 5 kg/cm2g is 498.3
kcal/kg while for 4 kg/cm2g is 509.5 kcal/kg. It shows a
difference of 11.2 kcal/kg.)
containing air and steam delivers only the heat of the
pressure of the steam, not total pressure.
effect the air has displaced a portion of the enthalpy needed, by
displacing a portion of the steam.
In order to make the
distribution system as efficient as possible it becomes necessary
to remove any air before it can effect heat transfer by filming or
becoming mixed with the steam.
boiler systems are constructed primarily of carbon steel and the
heat transfer medium is water, the potential for corrosion is
high. Iron is carried into the boiler in various forms of chemical
composition and physical state. Most of the iron found in the
boiler enters as iron oxide or hydroxide. Any soluble iron in the
feed water is converted to the insoluble hydroxide when exposed to
the high alkalinity and temperature in the boiler.
iron compounds are divided roughly into two types, red iron oxide
(Fe2O3) and black magnetic oxide (Fe3O4). The red oxide (hematite)
is formed under oxidizing conditions that exist, for example, in
the condensate system or in a boiler that is out of service. The
black oxides (magnetite) are formed under reducing conditions that
typically exist in an operating boiler.
The deposition of
these metallic oxides in the boiler is frequently more troublesome
than the actual damage caused by the corrosion. Deposition is not
only harmful in itself, but it offers an opening for further
corrosion mechanisms as well.
Contaminant products in the
feed water cycle up and concentrate in the boiler. As a result,
deposition takes place on internal surfaces, particularly in high
heat transfer areas, where it can be least tolerated. Metallic
deposits act as insulators, which can cause local overheating and
failure. Deposits can also restrict boiler water circulation.
Reduced circulation can contribute to overheating, film boiling
and accelerated deposition.
Localized attack on metal can
result in a forced shutdown. The prevention of a forced shutdown
is the true aim of corrosion control.
are used to provide clean steam to the process. Strainers are
installed in the steam pipes to ensure that no dirt gets through
with the steam. Often, pipeline debris such as dirt, metal burrs
from welding, scale, rust and other solids find their way into the
steam pipes leading to more maintainance hassles and plant
shutdowns. Strainers are an important pipeline accessory that
literally 'strains out' these solids in flowing liquids or gases,
and protects steam equipment. Every important equipment like a PRV
or trap has to have a strainer fitted upstream, ie just before
There is a fine mesh provided in the strainer which
effectively filters out solids from the system. During routine
maintenance strainers must be cleaned regularly otherwise unclean
steam will go through and damage the plant pipework and fittings.
It may contaminate the product as well.
makes two strainers. The CRPS and trap modules have the
Y-strainers and the PRS has a 'bucket' strainer.
These strainers are manufactured in-house for
the CRPS and the Trap modules. These are standard strainers and
can be used for steam, any other gas, or even liquids. The body is
a cylindrical pipe and has a mesh pocket attached to it which
contains the strainer mesh (80microns). This filters out all the
solids. It can handle pressures upto 10 kg/cm2g and is available
in line sizes upto 2". Generally used for condensate or small
the Y-type strainers are more compact than the pot strainers, the
surface area of the mesh available for straining is less and
therefore, the dirt accumalates faster. This means more frequent
cleaning. This is only a problem during commissioning when the
plant is new and a lot of welding grit is present in the
Installation of Y-type strainers.
Steam : Horizontal mounting with drain pocket in the horizontal
plane prevents water collection, which prevents carryover.
Liquids : For eg. in our CRPS systems, the strainer is mounted
with the mesh pocket facing vertically down. If this is not done,
the water may draw back the dirt upstream if the flow reduces.
you install the strainer with the mesh pocket pointing up, all the
debris will fall into the pipe!!
Steamline pot strainer has a bucket type structure. This is a
vertical cylinder. It's chamber is larger than a typical Y-type
strainer. The straining area is therefore much larger and can go
without cleaning longer. This also reduces the pressure drop
across the pot strainer as the flow is not hampered by that much
debris. The bucket strainer can be used on bigger dia pipes.
Strainers may have accumalated debris in the bottom of the bucket,
which is removed via the drain plug.
Bucket strainers have
to be installed in a horizontal position only.
purity requirements can vary widely. A low pressure firetube
boiler can usually tolerate a high level of water hardness, with
proper chemical treatment, while virtually all impurities must be
removed from the feedwater of most modern high pressure water-tube
boilers. Most plants use one or more of the following processes.
is ideal feedwater like? Ideally feedwater should conform to the
must supply boiler feedwater at not less than 75 – 85°C.
We must remove dissolved gases, ie, de-aerate feedwater. Dissolved
gases like oxygen lead to corrosion inside the boiler.
Feedwater needs chemical treatment to avoid excessive foaming and
scaling in the boiler. This can result in other problems like
carryover, priming, dirty and wet steam which hamper efficiency
and cause untold damage to the boiler.
Cold make-up water and returned Condensate
usually mix in the feedtank. Conventionally, both make-up water
and condensate are fed to the feedtank above the water
We heat feedwater because of three reasons.
feed will result in thermal shock to the boiler. When we feed at
optimum temperatures the life of boiler is also prolonged
When feedwater is at the highest temperature for injection to the
boiler, the boiler efficiency increases drastically. Return of
condensate further boosts η.
• All water sources have
a certain amount of dissolved gases mixed in them at ambient
temperature. Cold water absorbs free oxygen and other gases. As
the condensate heats the make-up water, the temperature of the
make-up water rises. At high temperatures undesirable gases have
minimum solubility and are liberated when heated.
is always present during equipment start-up and in the boiler
feed-water. The most common source of corrosion in boiler systems
is dissolved gas: oxygen, carbon dioxide and ammonia. Of these,
oxygen is the most aggressive. The importance of eliminating
oxygen as a source of pitting and iron deposition cannot be
over-emphasized. Even small concentrations of this gas can cause
serious corrosion problems.
Makeup water introduces
appreciable amounts of oxygen into the system. Oxygen can also
enter the feed water system from the condensate return system.
Possible return line sources are direct air-leakage on the suction
side of pumps, systems under vacuum, the breathing action of
closed condensate receiving tanks, open condensate receiving tanks
and leakage of nondeaerated water used for condensate pump seal
and/or quench water. With all of these sources, good housekeeping
is an essential part of the preventive program.
One of the
most serious aspects of oxygen corrosion is that it occurs as
pitting. This type of corrosion can produce failures even though
only a relatively small amount of metal has been lost and the
overall corrosion rate is relatively low. The degree of oxygen
attack depends on the concentration of dissolved oxygen, the pH
and the temperature of the water.
The influence of
temperature on the corrosivity of dissolved oxygen is particularly
important in closed heaters and economizers where the water
temperature increases rapidly. Elevated temperature in itself does
not cause corrosion. Small concentrations of oxygen at elevated
temperatures do cause severe problems. This temperature rise
provides the driving force that accelerates the reaction so that
even small quantities of dissolved oxygen can cause serious
It is essential to remove the dissolved gases –
"deaerate" – before it can be released in the
boiler or the feedtank, to prevent corrosion of the tank, the
boiler and the steam system.
The feedwater used in
generating steam will, of course, contain oxygen. It can also
contain bicarbonate and carbonate alkalinities which, when broken
down due to high temperatures, will produce C02. These two gases,
O2 and CO2, alone or combined, when disolved in condensate are
very corrosive. The oxygen causes oxygen pitting while the carbon
dioxide, in solution with the condensate, forms carbonic acid.
When combined, the oxygen accelerates the corrosive effects of the
Deaerating the feedwater removes almost all of these
gases. In general, as the feedwater enters the deaerator low
pressure steam, typically 0.35 kg/cm2 g, is used to break up the
water into a spray continuing across the spray carrying off the
All modern boilers have some form of deaeration
arrangement. The removal of this oxygen can be done by three ways
– thermal, mechanical and chemical.
chemical removal of oxygen, an oxygen scavenger like Sodium
Sulphite is dosed to the feedtank, which absorbs the oxygen.
However, this is detrimental because the addition of any chemical
to the boiler water increases its TDS (explained later in this
section), again causing problems.
• In mechanical
de-aeration, water is stirred or sprayed, causing removal of
oxygen from the feed water.
• Thermal de-aeration uses
the property of water shown in the graph . As is seen, the amount
of dissolved oxygen in water is proportional to its temperature.
So if we can heat the make-up water before it enters the feedtank,
it will liberate the oxygen, thus preventing corrosion of the
tank. Further, if the system used to preheat the make-up is made
of Stainless Steel, corrosion will be negligible.
is the job of a deaerator?
remove oxygen, carbon dioxide and other noncondensable gases from
feed water. Oxygen and carbon dioxide are very harmful to boiler
systems. Deaerators are designed to remove dissolved gases from
boiler feedwater. They are effective and oxygen can be reduced to
trace levels, about 0.005 ppm.
• Along with
temperature control systems, an effective deaeration system can
heat the incoming cold makeup water and mix it with available
Cutaway of a pressurized deaerator tank with live steam sparging
deaerators – how do they work?
larger boiler plants, pressurised de-aerators like the one shown
above are installed. Live steam is used to bring feed water temp
above 100ºC to “drive off” the oxygen content.
This action is normally enhanced by the steam “scrubbing”
the feedwater. The make-up water enters the deaerator and is
broken into a spray or mist, and scrubbed with steam to force out
the dissolved gases. At the elevated temperature the solubility of
oxygen is extremely low. Steam and other non-condensibles flow
upwards into the vent condensing section where the steam is
condensed. Freed oxygen and other gases are vented to the
atmosphere through the vent outlet. However, these are pressure
vessels and are therefore expensive.
This type of deaerator
usually consists of a heating and a deaerating section. The
storage section of these units typically have a residual deaerated
feedwater storage tank often designed to hold about 10 mins of
rated capacity of boiler fedwater.
Pressurized Steamline deaerator at Fresenius Kabi, Ranjangaon
the Deaerator Head was developed – a compromise for fitting
to any feedtank to drive off as much oxygen as possible at
atmospheric pressure. The Steamline De-aerator Head uses a
combination of thermal de-aeration and mechanical de-aeration. It
has three restrictions to the flow – a nozzle in the make-up
line, a baffle plate between the mixing head and the immersion
tube, and a sparger in the immersion tube. Therefore it ensures
that the oxygen in the make-up water is driven off by using the
heat in the condensate which it is mixed with, and all the
dissolved gases are released in the De-aerator Head before it
enters the feed tank and the boiler. These are vented out by the
automatic Air Vent provided on top of the De-aerator Head.
A Steamline Flash condensate Deaertor Head
has an all SS
assembly and is fitted to the top of the feedtank
for condensate, make up water and flash steam.
addition, sometimes Flash Steam is generated from high pressure
Condensate. This flash steam will escape to the atmosphere and the
heat will be lost. A third inlet is sometimes provided in a
De-aerator Head to mix flash steam with make-up water, thus
condensing the flash steam and saving its heat. This type of unit
is called the Flash Condensing De-aerator Head.
are typically elevated in boiler rooms to help create head
pressure on pumps located lower. This allows hotter water to be
pumped without vapor locking should some steam get into the pump.
dosing of feedwater
The basic contaminants are reduced to a
minimum, consistent with boiler design and operation parameters.
That is - calcium and magnesium hardness, migratory iron,
migratory copper, colloidal silica, etc.
Ion exchange systems range from
light commercial water softeners and filters to specially designed
industrial equipment. Also known as deionizations (DI) systems.
These systems are considered high-end where the highest quality of
water treatment is needed, such as with steam turbines.
Reverse Osmosis systems are available
for tap water, brackish water or seawater. These systems are
considered high-end where the highest quality of water treatment
is needed, such as with steam turbines
Water that is fit for human
consumption is not necessarily fit for a boiler. This is because
water can have many dissolved solids that lead to " hardening
" of water. These cause scaling which in turn leads to '' hot
spots" in the boiler which lead to corrosion.
feed water contains dissolved solids, both from raw water and
water treatment chemicals. As steam is raised from a boiler, the
level of concentration of Total Dissolved Solids (TDS) in the
boiler water increases.
The maximum allowable TDS is 3500
ppm for any boiler. This seems very small. How can such a small
value affect the working of such a large body of water inside the
salt truck story
Suppose the TDS in a boiler is 200 ppm
(Parts Per Million). This gives us a percentage value of
/ 1,000,000 X 100 = 0.002 %
This salt does not evaporate.
So, over time the TDS valves keep rising. 0.002% is seeming such a
small number, but look what happens inside the boiler.
assume a 10 ton boiler working 3 shifts ( 24 hours) for 30 days.
The feed water has 200 ppm TDS.
We will have 14.4 kgs of
salt in 30 days. So, in a few months we will have a small
truck-load of salt in the boiler!
Lets see if the TDS can
be reduced in a water softening plant.
Total Dissolved solids (TDS) is the sum of both
Hard and Soft salts.
A water softener basically uses
chemicals to remove (precipitate) the hand salts and substitutes
it with a soft salt. It does this by a reaction called base
Ca SO4 + Na OH -------- Na 2 SO4 + Ca
salt + Hard salt precipitate
Hard salts + Soft salts = TDS
Hard salts + Soft salts =
So, unfortunately, while a water softening plant
reduces the “hardness” (i.e. the presence of scale
forming salts), it does not reduce the TDS of the feed water. In
practice we may in fact, find a slight rise in TDS as brine (NaOH)
gets added to precipitate the hard salts. So, in a boiler the
foaming and carryover problems remain as the TDS has not
decreased. The only issue we have dealt with is reduced the
scaling because the hard salts are precipitated.
Even if we
use RO water, the Boiler water TDS keeps rising, albeit
Normally, plants periodically drain 10-15% of the
boiler water and this is called blowdown.
High TDS, big
Pure water does not foam when it
boils. However, as the amount of impurities rise, a foam layer is
formed at the steam separation surface. The amount of foaming is
directly proportional to the TDS level in the boiler.
(or “priming”) causes carryover of water, or wet
contaminated steam, which may be carried over into the steam
system and depending on the conditions at the steam water
interface, can even cause surges of water into the steam system.
The products of carryover would be deposited on heat transfer
surfaces and ancillary equipment, reducing steam system efficiency
and plant productivity. This is what causes fouling of heat
exchangers, malfunctioning of control valves and steam traps
Formation of foam at the separation layer is a matter
of great concern for any boiler operator. Level controls in a
boiler recognize liquids and gas. But, they start malfunctioning
when confronted with foam in the boiler. We know that the water
must never drop below the fire tube level. If the water level is
falling, but the foam prevents a level control from sensing low
level water the feed pumps do not switch on and a potentially
dangerous situation could develop.
Foaming and carryover in a boiler
If the TDS is too high, scale will
deposit on the boiler tubes and furnace (water side), all the heat
transfer surfaces. This has the effect of reducing heat transfer
with its subsequent effect on fuel consumption. When scaling goes
up exponentially, as seen in the graph, tube failure can occur.
only 1mm thick on the water side could increase fuel consumption
by 5 to 8%. (Source: PCRA Handbook No. 3 - Efficient Generation of
Tube surfaces underneath the scale may become
overheated leading to tube damage or tube failure. High TDS levels
in a boiler also shows up in the steam system -valves get while
deposits strainers need to be cleaned very often, etc.
order to prevent these problems, the TDS needs to be controlled
within a certain specified maximum limit. The chart below shows
the recommended water characteristics for shell boilers in
accordance with IS: 10392-1982 and BS: 2486-1964, for pressures up
to 25 bar g:
Dissolved solids, PPM (parts per million) is 3500. This is the Set
point of TDS that no boiler should be allowed to across because of
scale, foam and carryover problems. This set point can be measured
by a conductivity meter dipped in a sample of boiler water.
(Conductivity is directly proportional to TDS
All steam boilers need to be
"blown down" to control their TDS level.
main purpose of blowdown is to maintain the solids content of the
boiler water within prescribed limits. This would be under normal
steaming conditions. However, in the event contamination is
introduced in the boiler, high continuous and manual blowdown
rates are used to reduce the contamination as quickly as
Because each boiler and plant operation is different,
maximum levels should be determined on an individual
Conventionally, this is done through a
manual slide valve. By definition, bottom blowdown is intermittent
and designed to remove sludge or sediment from the bottom of the
boiler where it settles. The frequency of bottom blowdown is a
function of experience and plant operation. Bottom blowdown can be
accomplished manually or electronically using automatic blowdown
controllers. The control is a large (usually 25 to 50 mm) key
operated valve. This valve might normally be opened for a period
of about 1 - 2 minutes, once a shift.
large quantity of hot, saturated water is drained and the same
amount of relatively cold make-up water is added. This leads to
thermal shock in the boiler.
we now have to provide more heat to bring this extra water to
100ºC, we are decreasing the overfall efficiency of the
formula for amount of blowdown required is
= Feedwater TDS in ppm
B = Boiler water set point in ppm
Steam generation in kg/hr.
Frequently used in conjunction with
manual blowdown, continuous blowdown constantly removes
concentrated water from the boiler.
allows for better control over boiler water solids. In addition,
it can remove significant levels of suspended solids. Another
advantage is that the continuous blowdown can be passed through
heat recovery equipment.
blowdown is enough?
Too little, and your TDS
could rise above limits specified for your boiler, giving rise to
foaming, scaling and wet steam. Too much, and you're draining
water that you've paid to heat.
The need for Automatic
Blowdown Controller (ABCO)
Blowdown of the boiler can keep
TDS within the required limits. Blowdown is achieved either by
manual or automatic methods. In the manual method, blowdown is
achieved by opening a large bore valve at the bottom of the drum
(or on the side of the drum in case of continuous blowdown).
However, this practice can be highly wasteful. As the period of
blowdown is not related with either boiler steam load or feedwater
purity, the TDS level in manual methods can vary greatly, causing
an average TDS level much lower than the allowable limit, and
leading to excess blowdown.
On the other hand, an automatic
blowdown control system, based on TDS measurement and subsequent
corrective action, can maintain a TDS level much closer to the set
point, resulting in considerable fuel savings.
Blowdown quantity is reduced with an automatic system
seen in the graphs above, the automatic control of TDS results in
an average TDS level much closer to the set point. This means that
the actual quantity of blowdown over a period of time gets reduced
compared to the manual method. Blowdown water is water that has
been heated to the saturation temperature of the boiler, so it
contains a lot of heat. At a boiler pressure of 10.5 Kg/cm2 g,
each kg of blowdown water contains almost 190 kcal of heat energy.
If an automatic boiler controller can reduce the blowdown of a 10
TPH boiler from 6% to 3%, i.e. a saving of 3%, the blowdown
quantity would reduce by 300 Kg/hr, or 7200 kg/day. This would
mean a saving of 1368000 kcal/day. This would mean a fuel saving
of approximately 180 litres of oil, if the boiler was fired with
furnace oil. The cost benefit of preventing corrosion in the
boiler and the steam system, though it cannot be quantified
exactly, would be in addition.
is a process of oxidation in which combusinble products such as
fuel is burned in the presence of oxygen. Combustion liberates
heat and by products such as ash.
liquid or gaseous fuels, we use a Burner. A burner sends heat into
the boiler tubes and it is set to maintain the correct pressure in
the boiler. If the boiler pressure falls because of growing steam
demand, the burner switches on to produce more steam from the
boiler. As long as the amount of steam being produced in the
boiler is as great as that leaving the boiler, the boiler will
remain pressurised. This maintains correct pressure. If correct
pressure is maintained, correct temperature is also maintained as
they are interlinked.
Proper atomised fuel gives better
combusion efficiencies. Modulating control gives optimum fuel
handling. Also provision of appropriate excess air for combusion
gives good results.
In case of gaseous fuels, minimum
excess air is required and there is no extra cost incurred in
In case of solid fuels, there is no
burner required. Fuel is supplied over a grate which is fire
pulverise, and excess air is supplied to acheive better combusion
efficiencies. Ash handling is main problem incase of solid fuels.
Turndown tells us the amount of control we have
over the fuel.
a simple on-off control, the boiler either fires x amount of fuel
or is switched off.
A boiler turndown of 1.2 means we can
fire less fuel on more fuel.
A 1:2 turndown means a 2 step
control is possible.
1:4 turndown looks something like
It has 4 step control. Modern boilers can also provide a
stepless control from 25-100%.
As fuel load increase or
decreases, the amount of fuel fired into the boiler should
proportionately be increased or decreased. But when modulation is
not possible, (as in a simple on-off control) , the boiler burns
less fuel at low loads and the rest of the unburnt fuel is blown
out through the stack .
The O in the left side of the
equation is the exact amount of air required to burn a given
amount of fuel, also called stoichiometric air
Practically though, the amount of air needed is
in excess of times, to achieve complete combustion of fuel.
Therefore we provide "excess air". Excess air from
20-30% is normally used. We have to carefully control this excess
air quantity as we risk blowing out unburnt fuel.
losses can really add up over time.
The boiler furnace has
a punker plate (similar to our home gas burners ) through which a
pressurized mixture of liquid fuel and air is sprayed. This
atomizes the fuel and a proper mixing of fuel with air takes
place. This ensures the highest combustion efficiency.
fuels too are crushed or broken down (there is always a coal
crusher at power plants) to increase the combination
Perfect combustion is
attained when the flue gas analysis shows no carbon monoxide or
oxygen. This means that every available fuel molecule and every
available oxygen molecule came into contact with each
Ideally, the Combustion Equation (stoichiometric
air) should look something like this:
Cn Hn + O2
------> CO2 + H2O + Heat
Such perfect mixing is not possible, even with the
most advanced burner. Given complete mixing, a precise amount of
air (stoichiometric) is required to completely react with a given
quantity of fuel. In practice, if only stoichiometric amount of
air is provided, then the combustion looks something like
Cn Hn + O2 ------> CO2 + H2O
+ CO + Heat
Fuel Stoich. Air
As seen above, CO (unburnt
fuel) is present in the flue gas as the stoichiometric air
quantity is insufficient to ensure complete
Therefore, additional or “excess air”
must be supplied for complete combustion to occur. The presence of
excess air means that more air is available for combustion than is
actually required. For efficiency reasons, “excess air”
is always provided to assure that all fuel is burned inside the
boiler. There is no CO component anymore. By operating your boiler
with a minimum amount of excess air, you can decrease stack heat
losses and increase combustion efficiency.
In addition, air
has other components besides O2, and fuel may have impurities like
sulphur. Hence the real world combustion equation, looks like
Cn Hn + S2 + N + O2 ------>
CO2 + H2O + Heat + O2 + SOx + NOx
However, the excess air passing through the
boiler is heated by the fuel, and vented out of the chimney. So,
the more the excess air, the lower the boiler efficiency. Hence,
excess air must be optimized such that it is just enough to burn
all the fuel while not removing too much heat.
unnecessary amounts of excess air can occur because of:
Burner/control system imperfections
♦ Variations in
boiler room temperature, pressure, and relative humidity
Need for burner maintenance
♦ Changes in fuel
In modern history, excess air is controlled
using a feedback system in which a sensor (generally O2) is used
to provide feedback on flue gas constituents and controls the
amount of combustion air provided to the boiler. This is called
Trim Control, or Combustion Control.