Flue gas desulfurization is commonly known as FGD and is the technology used for removing sulfur dioxide (SO2) from the exhaust combustion flue gases of power plants that burn coal or oil to produce steam for the turbines that drive their electricity generators.

1. A presentation report
on
FLUE GAS DESULFURIZATION
Submitted by
Mr. GAJENDRA SINGH
(MSDIT/18/02)
Under the supervision of
Dr. MANJULA DAS GHATAK
(Assistant Professor)
Department of Mechanical Engineering
NATIONAL INSTITUTE OF TECHNOLOGY
ARUNACHAL PRADESH

2. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
2 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
Introduction
Combustion of fossil fuels resulting in emissions of sulphur dioxide (SO2). Flue gas desulfurization is
commonly known as FGD and is the technology used for removing sulfur dioxide (SO2) from the
exhaust combustion flue gases of power plants that burn coal or oil to produce steam for the turbines
that drive their electricity generators. The most common types of FGD contact the flue gases with an
alkaline sorbent such as lime or limestone.
Prior to the advent of strict environmental protection regulations, tall flue gas stacks (i.e., chimneys)
were built to disperse rather than remove the sulfur dioxide emissions. However, that only led to the
transport of the emissions to other regions. For that reason, a number of countries also have regulations
limiting the height of flue gas stacks.
For a typical conventional coal-fired power plant, FGD technology will remove up to 99 percent of the
SO2 in the flue gases.
Influence of Sulphur Oxides (SOx)
As sulfur dioxide is responsible for decrease in visibility by absorbing or diffracting sun light in the
atmosphere along with floated particles. Incidence of chronic diseases at eyes, nose, neck or bronchus
by exposure for long time. It decrease production and growth of plants by interrupting photosynthesis
due to the black spot or chlorosis. Destruction of ecosystem by acidifying land or river due to acid rain
or acid snow and corroding architectures.
Stringent environmental protection regulations have been enacted in many countries to limit the amount
of sulfur dioxide emissions from power plants and other industrial facilities.
History
Methods for removing sulfur dioxide (SO2) from flue gases have been studied for over 150 years. Early
concepts useful for flue gas desulfurization appear to have germinated in 1850 in England.
With the construction of large-scale power plants in England in the 1920s, the problems associated with
large volumes of sulfur dioxide emissions began to concern the public. The problem did not receive
much attention until 1929, when the British government upheld the claim of a landowner against the
Barton Electricity Works for damages to his land resulting from sulfur dioxide emissions. Shortly
thereafter a press campaign was launched against the erection of power plants within the confines of
London. This led to the imposition of sulfur dioxide controls on all such power plants.
During this period, major FGD installations went into operation in England at three power plants. The
first one began operation at the Battersea Station in London in 1931. In 1935, the second one went into
service at the Swansea Power Station. The third one was installed in 1938 at the Fulham Power Station.
All three installations were abandoned during World War II. Large-scale FGD units did not reappear in
commercial operation until the 1970s, and most of the activity occurred in the United States and Japan.

3. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
3 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
Theory of Operation:
The FDG or SO2 scrubbing process typically uses a calcium or sodium based alkaline reagent. The
reagent is injected in the flue gas in a spray tower or directly into the duct. The SO2 is absorbed,
neutralized and/or oxidized by the alkaline reagent into a solid compound, either calcium or sodium
sulfate. The solid is removed from the waste gas stream using downstream equipment.
Scrubbers are classified as “once-through” or “regenerable”, based on how the solids generated by the
process are handled. Once-through systems either dispose of the spent sorbent as a waste or utilize it as
a by-product. Regenerable systems recycle the sorbent back into the system. At the present time,
regenerable processes have higher costs than once-through processes; however, regenerable processes
might be chosen if space or disposal options are limited and markets for by-products (gypsum) are
available.
Both types of systems, once-through and regenerable, can be further categorized as wet, dry, or semi-
dry. Each of these processes is described in the following sections.
SO2 is an acidic gas. Therefore, the most common large-scale FGD systems use an alkaline sorbent such
as lime or limestone to neutralize and remove the SO2 from the flue gas. Since lime and limestone are
not soluble in water, they are used either in the form of an aqueous slurry or in a dry, powdered form.
When using an aqueous slurry of sorbent, the FGD system is referred to as a wet scrubber. When using
a dry, powdered sorbent, the system is referred to as a dry system. An intermediate or semi-dry system
is referred to as a spray-dry system.
FGD Chemistry
The reaction taking place in wet scrubbing using a CaCO3 (limestone) slurry produces CaSO3
(calciumsulfite) and can be expressed as:
𝐶𝑎𝐶𝑂3 (𝑠𝑜𝑙𝑖𝑑) + 𝑆𝑂2 (𝑔𝑎𝑠) ⇒ 𝐶𝑎𝑆𝑂3 (𝑠𝑜𝑙𝑖𝑑) + 𝐶𝑂2 (𝑔𝑎𝑠)
When wet scrubbing with a Ca(OH)2 (lime) slurry, the reaction also produces CaSO3 (calcium sulfite)
and can be expressed as:
𝐶𝑎(𝑂𝐻)2 (𝑠𝑜𝑙𝑖𝑑) + 𝑆𝑂2 (𝑔𝑎𝑠) ⇒ 𝐶𝑎𝑆𝑂3 (𝑠𝑜𝑙𝑖𝑑) + 𝐻2𝑂 (𝑙𝑖𝑞𝑢𝑖𝑑)
When wet scrubbing with a Mg(OH)2 (magnesium hydroxide) slurry, the reaction produces
MgSO3(magnesium sulfite) and can be expressed as:
𝑀𝑔(𝑂𝐻)2 (𝑠𝑜𝑙𝑖𝑑) + 𝑆𝑂2 (𝑔𝑎𝑠) ⇒ 𝑀𝑔𝑆𝑂3 (𝑠𝑜𝑙𝑖𝑑) + 𝐻2𝑂 (𝑙𝑖𝑞𝑢𝑖𝑑)
Some FGD systems go a step further and oxidize the CaSO3 (calcium sulfite) to produce marketable
CaSO4· 2H2O (gypsum):
𝐶𝑎𝑆𝑂3 (𝑠𝑜𝑙𝑖𝑑) + ½ 𝑂2 (𝑔𝑎𝑠) + 2𝐻2𝑂 (𝑙𝑖𝑞𝑢𝑖𝑑) ⇒ 𝐶𝑎𝑆𝑂4 · 2𝐻2𝑂 (𝑠𝑜𝑙𝑖𝑑)
Aqueous solutions of sodium hydroxide (NaOH), known as caustic soda or simply caustic, may also be
used to neutralize and remove SO2 from flue gases. However, caustic soda is limited to small-scale FGD
systems, mostly in industrial facilities other than power plants because it is more expensive than lime. It
has the advantage that it forms an aqueous solution rather than a slurry and that makes it easier to operate.
It produces a solution of sodium sulfite or sodium bisulfite (depending on the pH), or sodium sulfate that
must be disposed of. This is not a problem in a paper mill for example, where the solution can be recycled
and reused within the paper mill.

4. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
4 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
Comparison & Classification Based on Process
1. Wet Systems
In a wet scrubber system, flue gas is ducted to a spray tower where an aqueous slurry of sorbent is
injected into the flue gas. To provide good contact between the waste gas and sorbent, the nozzles and
injection locations are designed to optimize the size
and density of slurry droplets formed by the system.
A portion of the water in the slurry is evaporated and
the waste gas stream becomes saturated with water
vapour. Sulfur dioxide dissolves into the slurry
droplets where it reacts with the alkaline particulates.
The slurry falls to the bottom of the absorber where
it is collected. Treated flue gas passes through a mist
eliminator before exiting the absorber which
removes any entrained slurry droplets. The absorber
effluent is sent to a reaction tank where the SO2-
alkali reaction is completed forming a neutral salt. In
a regenerable system, the spent slurry is recycled
back to the absorber. Once through systems dewater
the spent slurry for disposal or use as a by-product.
Typical sorbent material is limestone, or lime.
Limestone is very inexpensive but control
efficiencies for limestone systems are limited to approximately 90%. Lime is easier to manage on-site
and has control efficiencies up to 95% but is significantly more costly (Cooper 2002). Proprietary
sorbents with reactivity enhancing additives provide control efficiencies greater than 95% but are very
costly. Electrical utilities store large volumes of limestone or lime on site and prepare the sorbent for
injection, but this is generally not cost effective for smaller industrial applications.

5. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
5 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
Wet limestone scrubbing has high capital and operating cost due to the handling of liquid reagent and
waste. Nonetheless, it is the preferred process for coal-fired electric utility power plants burning coal
due to the low cost of limestone and SO2 control efficiencies from 90% up to 98% (Schnelle, 2002).
2. Semi-Dry Systems
Semi-dry systems, or spray dryers, inject an aqueous sorbent slurry similar to a wet system, however,
the slurry has a higher sorbent concentration. As the hot flue gas mixes with the slurry solution, water
from the slurry is evaporated. The water that remains on the solid sorbent enhances the reaction with
SO2. The process forms a dry waste product which is collected with a standard particulate matter (PM)
collection device such as a baghouse or ESP. The waste product can be disposed, sold as a byproduct or
recycled to the slurry.
Various calcium and sodium based reagents can
be utilized as sorbent. Spray dry scrubbers
typically inject lime since it is more reactive
than limestone and less expensive than sodium
based reagents. The reagent slurry is injected
through rotary atomizers or dual-fluid nozzles
to create a finer droplet spray than wet scrubber
systems (Srivastava, 2000).
SO2 control efficiencies for spray dry scrubbers
are slightly lower than wet systems, between
80% and 90% due to its lower reactivity and
L/G ratios. Application of a single spray dry
absorber is limited to combustion units less
than 200 MW (IEA, 2001). Larger combustion
units require multiple absorber systems. The
capital and operating cost for spray dry
scrubbers are lower than for wet scrubbing
because equipment for handling wet waste
products is not required. In addition, carbon
steel can be used to manufacture the absorber since the flue gas is less humid. Typically applications
include electric utility units burning low- to medium- sulfur coal, industrial boilers, and municipal waste
incinerators that require 80% SO2 control efficiency (Schnelle, 2002).
3. Dry systems
Dry sorbent injection systems, pneumatically inject powdered sorbent directly into the furnace, the
economizer, or downstream ductwork. The dry waste product is removed using particulate control
equipment such as a baghouse or electrostatic precipitator (ESP). The flue gas is generally cooled prior
to the entering the PM control device. Water can be injected upstream of the absorber to enhance SO2
removal (Srivastava, 2001).
Furnace injection requires flue gas temperatures between 950°C to 1000°C (1740°F to 1830°F) in order
to decompose the sorbent into porous solids with high surface area (Srivastava 2001). Injection into the
economizer requires temperatures of 500°C to 570°C (930°F to 1060°F) (Srivastava 2001). Duct

6. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
6 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
injection requires the dispersion of a fine sorbent spray into the flue gas downstream of the air preheater.
The injection must occur at flue gas temperatures between 150°C to 180°C (300°F to 350°F) (Joseph,
1998).
Dry sorbent systems typically use calcium and
sodium based alkaline reagents. A number of
proprietary reagents are also available. A typical
injection system uses several injection lances
protruding from the furnace or duct walls.
Injection of water downstream of the sorbent
injection increases SO2 removal by the sorbent.
Dry scrubbers have significantly lower capital
and annual costs than wet systems because they
are simpler, demand less water and waste
disposal is less complex. Dry injection systems
install easily and use less space, therefore, they
are good candidates retrofit applications. SO2
removal efficiencies are significantly lower than
wet systems, between 50% and 60% for calcium
based sorbents. Sodium based dry sorbent
injection into the duct can achieve up to 80%
control efficiencies (Srivastava 2001). Dry sorbent injection is viewed as an emerging SO2 control
technology for medium to small industrial boiler applications. Newer applications of dry sorbent
injection on small coal-fired industrial boilers have achieved greater than 90% SO2 control efficiencies.
Comparison & Classification Based on Chemicals

7. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
7 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
Wet Limestone Gypsum Process
The wet limestone-gypsum process uses a wet scrubber to remove SOx from flue gas. Limestone or
slaked lime is used as sorbent. As the sorbent reacts with SOx, gypsum is generated as a byproduct. The
discharged gypsum is recycled to
make gypsum board or cement.
SO2 is removed from flue gas in the
absorber or scrubber tower using
limestone slurry. The absorbed SO2 is
oxidized in the absorber sump to form
marketable calcium sulfate crystals
(gypsum). The pH level in the
absorber sump, which changes
depending on the quantity of SO2
removed in the absorber, is controlled
by adding limestone slurry. This
enables continuous production of high
purity gypsum.
Gypsum slurry from the absorber
sump is thickened in a hydro cyclone
and then more than 90% is dewatered by a vacuum belt filter. Alternatively, a centrifuge may be used in
place of the vacuum belt filter.
There are various types of wet scrubbers. For example, spray towers, venturi scrubbers, packed towers
and trayed towers. Slurries would cause serious erosion problems in a venturi scrubber because of the
high speeds at the throat of the venturi section. Packed towers or trayed towers would plug up if handling
slurries. For handling slurries, the spray tower is a good choice and it is in fact a commonly used choice
in large-scale FGD systems.
Absorption efficiency depends on the amount of scrubbing liquid, the size of particle, velocity of gas
and contact duration or ratio between gas/liquid.
Alternative methods of reducing sulfur dioxide emissions
An alternative to removing sulfur dioxide from the flue gases after combustion is to remove the sulfur
from the fuel before or during combustion. Catalytic hydro desulfurization has been used for treating
petroleum fuel oils. Fluidized bed combustion (FBC) adds lime to the fuel during combustion. The lime
reacts with the SO2 in the flue gas to form sulfates which become part of the combustion ash and are
removed in the particulate removal equipment
Future Scope: Combined 𝑺𝑶 𝟐 / 𝑵𝑶 𝒙 Removal Process
Combined SO2/NOx removal processes remain considered fairly complex and costly. However,
emerging technologies have the potential to reduce SO2 and NOx emissions for less than the combined
cost of conventional FGD B for SO2 control and selective catalytic reduction (SCR) B for NOx control.

8. Flue Gas Desulfurization Gajendra Singh (MSDIT/18/02)
8 | P a g e
Department of Mechanical Engineering
National Institute of Technology, Arunachal Pradesh
Most processes are in the development stage, although some processes are commercially used on low to
medium-sulphur coal-fired plants.
Miscellaneous fact and statistics
The information in this section was obtained from a U.S. EPA published fact sheet dated 2003.
Flue gas desulfurization scrubbers have been applied to combustion units firing coal and oil that range
in size from 5 MW to 1500 MW.
Dry scrubbers and spray scrubbers have generally been applied to units smaller than 300 MW.
Approximately 85% of the flue gas desulfurization units installed in the US are wet scrubbers, 12% are
spray dry systems and 3% are dry injection systems.
The highest SO2 removal efficiencies (greater than 95%) are achieved by wet scrubbers and the lowest
(less than 80%) by dry scrubbers. However, the newer designs for dry scrubbers are capable of achieving
efficiencies in the order of 90%
References
1. Air Pollution Control Technology Fact Sheet: Flue gas desulfurization. Report: EPA-452/F-03-
034, from the U.S. EPA website.
2. Karl B. Schnelle and Charles A. Brown (2001), Air Pollution Control Technology, CRC Press,
ISBN 0-8493-9599-7.
3. Milton R. Beychok, "Coping With SO2", Chemical Engineering/Deskbook Issue, October 21,
1974.
4. Air Pollution Control Technology Fact Sheet: Spray tower wet scrubber, Report: EPA-452/F-03-
016, from the U.S. EPA website.
5. Dr. James Katzer et al and MIT Coal Energy Study Advisory Committee (2007), The Future of
Coal, Massachusetts Institute of Technology (MIT), ISBN 0-615-14092-0.