Selecting Flue Gas Desulfurization Technology for Existing Coal-Fired

Power Plants

Andrew Carstens, Director Environmental Sciences, Sargent & Lundy, Chicago, USA
Yogendra D Mishra, Group Head Mechanical Engineering, L&T – Sargent & Lundy, Vadodara, India
Hardik Bhavsar, Manager, Mechanical Engineering, L&T – Sargent & Lundy, Vadodara, India

Abstract: India’s Ministry of Environment, Forests, and Climate Change has proposed emission standards for
coal-fired power plants that includes significant reductions in sulfur dioxide (SO2), oxides of nitrogen (NOx),
particulate matter (PM) and Mercury (Hg) emissions. In context of SO2 emissions, depending on how the rule
is finalized, this could cause many existing coal-fired power plants to retrofit flue gas desulfurization (FGD)
technology to reduce SO2 emissions. The first step in a FGD retrofit project is to evaluate the technologies to
determine which represents the best selection for each power plant based on its configuration, fuel properties,
performance requirements, and other site-specific factors. Since very few Indian power plants currently utilize
FGD technology, this paper will describe various technology options including: Dry Sorbent Injection (DSI),
Spray Dryer Absorber (SDA) FGD, Circulating Dry Scrubber (CDS) FGD, Limestone-based Wet FGD, all of
which have been evaluated and installed extensively in the United States to reduce SO2 emissions. For each
of the technologies considered, we will explore the major features of the technologies, potential operating and
maintenance cost impacts, as well as key factors that contribute to the selection of one technology over
another.

Keyword: Wet FGD, Dry FGD, Selection Criteria, Other FGD Systems

INTRODUCTION

Being the 3rd largest economy and the 4th largest consumer of electricity in the world with more than a billion
people and government thrust on development of infrastructure and manufacturing industry, the supply of
power in India can scarcely keep up with demand. As of 30th September 2015, coal fired thermal power plant
contributes to 169.117 GW which is 60.67% of total power generation capacity in the country.
To meet the growing electricity demand, the installation of large coal-fired thermal power plants (TPPs) is the
most likely scenario for India to have economical electricity generation, which results in the emission of sulfur
dioxides (SO2), nitrogen oxides (NOX), particulate matter (PM) and metals like mercury (Hg). Emissions of
sulfur and nitrogen compounds are transformed into acidifying substances such as sulfuric and nitric acid in
the atmosphere. To date India does not have the environmental regulations for SO2, NOx, or Hg specifically for
coal based thermal power plant.

Ministry of Environment, Forest and Climate Change (MOEFCC) has issued a draft notification in April 2015
that proposes to regulate SO2, NOx and Hg in coal-fired thermal power plants. This draft is currently being
discussed with technology suppliers, developers and the generation companies, and it is likely to be issued by
2017, although the final rule and its implementation may differ from the proposed one based on the current
discussions. Countries like the United States, the European Union, China, and Australia already have
environmental regulations limiting the emissions of some or all of these constituents. The draft emission

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regulations issued by MOEFCC specifies proposed emissions norms to be achieved by existing and the future
power plants as per the following table.

Proposed Emission Limits

Power Plant Before December 31, After 2003 to December

After January 1, 2017
Construction Date 2003 31, 2006

PM, mg/Nm3 100 50 30

600 (Units <500MW)

SOx, mg/Nm3 200 (Units >=500MW) 100
200 (Units >=500MW)

NOx, mg/Nm3 600 300 100

Mercury (Hg), mg/Nm3 0.03 (Units >500MW) 0.03 0.03

The proposed rule would require all new coal-fired power plants to install flue gas desulfurization (FGD)
systems to reduce SO2 emissions. In addition, perhaps the most significant impact of this proposed regulation
is that it would require many existing coal-fired power plants to retrofit FGD systems, causing additional capital
investments and higher operating costs. The first step in FGD retrofit project is to evaluate the technologies to
determine which one represents the best selection for each power plant based on its configuration, fuel
properties, performance requirements, and other site-specific factors to minimize the both capital and
operating costs. This paper will review FGD technologies including wet FGD systems, primarily limestone-
based wet FGD and dry FGD systems including spray dryer absorbers (SDA) and circulating dry scrubbers
(CDS).

LIMESTONE-BASED WET FGD SYSTEMS

The term wet FGD refers to a system using an absorber that completely saturates the inlet flue gas with water.
Wet limestone FGD systems have been operating in utility applications since the 1970s. Early generations of
wet FGD technology had internal scaling and corrosion problems that caused the absorbers to be brought off
line for frequent maintenance. However, state-of-the-art wet FGD systems do not experience these problems.
It is generally more applicable for medium to high-sulfur coals where removal of 95- 99% of the inlet SO2 can
be achieved, but many units firing low sulfur fuels also employ this technology.

The flue gas typically is about 150°C (300°F) when it enters the absorber, then the gas is adiabatically cooled
to a saturation temperature between 52-57°C (125-135°F) by liquid slurry containing a mixture of water and
limestone. In a limestone forced oxidation (LSFO) FGD system, flue gas containing SO2 is brought into
contact with limestone slurry droplets and the SO2 is absorbed into the water droplet. The saturated flue gas
allows for quick mass transfer of the SO2 gas into the slurry droplets. Within the droplet, the SO2 and calcium

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from the limestone (CaCO3) react to form calcium sulfite (CaSO3), according to the following simplified
reaction:

CaCO3 + SO2 → CaSO3 + CO2

The slurry spray falls into the reaction tank below, where it is eventually recirculated back into the flue gas
stream. The reaction tank has agitators to keep the slurry in solution and also has an oxidation air grid to
force-oxidize the reaction product. The calcium sulfite is force-oxidized to calcium sulfate, which does not
scale, and the final product is calcium sulfate dehydrate (CaSO4·2H2O), commonly known as gypsum. The
oxidation reaction is as follows:

CaSO3 + 1/2O2 (flue gas) + 2H2O → CaSO4·2H2O

Most of the solids are recycled through the absorber several times and a small bleed stream is sent to a
dewatering step and separated from the water. Vacuum-drum or belt filters are used to concentrate the bleed
slurry stream. The water from this process is returned to the FGD process. If salable-grade gypsum is to be
produced, the solids are sprayed with a clean water to remove the chlorides. This water is also returned to the
process. The waste water may be subjected to treatment depending on the discharge requirement. Figure 1
shows an example of a typical limestone-based wet FGD system.

Figure 1: Typical Wet Limestone FGD System

LIMESTONE HANDLING SYSTEM

Crushed limestone received at a plant typically is delivered by bottom-dump railcars or trucks and is
transported to an outdoor, uncovered limestone storage pile. Feeders supply the reclaim conveyor, which
carries the limestone to the day silos located immediately above the wet grinding ball mills. Preparation of the
limestone slurry involves wet grinding the limestone in a horizontal ball mill. The ball mill grinds the limestone
and discharges it into a small receiving tank that is then pumped through hydro-cyclone classifiers. The
limestone that is off the appropriate size is ready for use and sent to a storage tank, but the larger particles
are returned to the ball mills for further grinding and size reduction. Process makeup water or recycle water is

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added to produce approximately 30% by weight solids slurry, which is stored until it is fed as reagent makeup
into an absorber.

ABSORBER SYSTEM

There are two main absorber configurations: a vertical spray/tray tower and an open-spray tower. Both
configurations use counter-current contact between the flue gas and scrubber slurry. This counter-current type
is the most commonly used absorber in the utility industry in the United States. The mass transfer occurs in
the tray and in the open-spray zone. The tray is a horizontal perforated plate that causes the slurry to form a
froth layer. SO2 in the flue gas that comes in contact with this froth reacts with the slurry. When a tray is
present, most of the sulfur collection occurs at the tray and the spray levels do less of the sulfur collection.

An open-spray tower relies on several spray levels to create enough droplets to carry out the necessary mass
transfer. The liquid to gas (L/G) ratio for an open-spray tower is greater than for a tray. Open- spray towers
use a baffle around the inside circumference of the absorber to prevent gas flow from escaping the spray
zone. After falling through the spray zone, the slurry accumulates in the reaction tank. The reaction tank is
agitated to keep the solids in suspension and air is forced into the reaction tank to force-oxidize the CaSO3 in
the slurry. From the reaction tank the slurry is pumped back into the absorber’s spray zone. High-horsepower
pumps are used for the recycle. Above the spray zone is the mist eliminator, which removes the entrained
slurry droplets so they do not exit the absorber and create particulate emissions leaving the chimney. The
absorber inlet is an especially corrosive environment due to wet/dry interface that occurs when some of the
slurry deposits on the inlet floor of the duct. The absorber vessel must be constructed of materials that resist
corrosion, erosion, and scaling. To reduce corrosion, expensive high alloy materials are required.

DEWATERTING AND BYPRODUCT HANDLING SYSTEM

The bleed stream from the reaction tank is pumped to a set of hydro-cyclones for primary dewatering. The
hydro-cyclone underflow, containing approximately 50% solids, is fed to a belt filter for secondary dewatering.
Belt filters are typically designed to achieve 90% solids in the gypsum byproduct to meet the requirements of
gypsum buyers, if the gypsum is being sold to the wallboard industry. Hydrochlorine gas is absorbed from the
flue gas and they concentrate in the recycle slurry solution in the form of chlorides. A small blowdown stream
may be required to remove chlorides and other contaminants from the process. A FGD waste water treatment
facility is necessary to treat and remove heavy metals like mercury and arsenic from the blowdown stream of
the absorber, depending on regulated discharge requirements.

SELECTION CRITERIA FOR WET FGD SYSTEM

Some positive features that can play an important role in the selection of wet FGD technology are that, in
general, wet FGD systems:
 Can accept a wide variety of fuel sulfur levels allowing for greater fuel flexibility
 Are highly efficient at removing SO2 and other acid gases from the flue gas

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  Can play an important role in the reduction of mercury emissions, depending on other
characteristics in the flue gas
 Are able to operate at all power plant loads
 Can produce a saleable byproduct (gypsum) that can be used in the production of wall-board that
is used extensively in the construction industry
 Can be used in conjunction with existing electrostatic precipitators (ESPs)

Some potential disadvantages of wet FGD systems that can drive the selection to a dry FGD technology are
that, in general, wet FGD systems:
 Have higher capital costs due to absorber metallurgy, new wet stacks (or gas-to-gas exchangers
to dry the gas), and other features
 Are more complex to operate because of pH and other requirements in the reaction tank
 Require a large footprint area because of the reagent preparation, byproduct dewatering
equipment and waste water treatment plant to remove the heavy metals.
 Are not very efficient at removing fine ash particles or sulfuric acid mist

DRY FGD SYSTEMS

There are two general categories of dry FGD technology. The spray dryer absorber (SDA), also called semi-
dry technology, and circulating dry scrubber (CDS), referred to as dry technology. The SDA and CDS
technologies have been treating flue gas from coal-fired industrial and utility boilers for many years with recent
trend towards the use of CDS scrubbers due to low sulfur applications in the USA.

In dry FGD systems, flue gas is brought into contact with lime slurry in the vessels. Lime (CaO) must be
hydrated before use, by adding water. This hydration occurs in a slaker (used for SDA) or hydrator (used for
CDS), and the chemical reaction is as follows:

CaO + H2O ↔ Ca(OH)2

Calcium reacts with the SO2 to form waste solids calcium sulfate (CaSO4) and calcium sulfite (CaSO3). About
one-third of the waste is sulfate and two-thirds is sulfite. The chemical reactions are:

Ca(OH)2 + SO2 + H2O → CaSO3 • 1/2H2O + 3/2H2O

CaSO3 • 1/2H2O + 3/2H2O + 1/2O2 (flue gas) → CaSO4 • 2H2O

A small amount of carbon dioxide also reacts with hydrated lime to form calcium carbonate per the following
reaction:

Ca(OH)2 + CO2 → CaCO3 + H2O

The dried solids are entrained in the flue gas and exit the dry FGD, along with the fly ash, and are collected in
a particulate collection device. Most of the SO2 removal occurs in the absorber itself, although additional SO2
capture occurs downstream if there is a baghouse installed.

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The SDA FGD technology was developed beginning in 1977, to serve users of low-sulfur coal who had to
meet a requirement of only 70-80% SO2 removal. Some of the early SDA installations utilized an electrostatic
precipitator (ESP) after the scrubber since the SO2 reduction requirement was only 70-80%. As the
technology’s experience grew and matured, it demonstrated much higher performance capabilities. With the
development of the baghouse technology, the SO2 removal capability increased to 90-95%. Figures 1 shows
a typical configuration for SDA FGD systems. In SDA systems, lime slurry is fed to atomizers that spray the
slurry into the flue gas. The water is evaporated due to its contact with the hot flue gas, and the flue gas
temperature must be controlled to remain above the adiabatic saturation temperature of the flue gas to protect
the downstream equipment, especially the filter bags that are utilized in the downstream fabric filter.

Figure 2: Typical SDA FGD System

Circulating Dry Scrubber (CDS) technology is a dry scrubbing process that is generally used for low- sulfur
coal. However, a unique feature is that CDS can achieve very high SO2 removal (95% or higher), even at
higher inlet sulfur level, compared to the SDA FGD. Similar to the SDA, the CDS system is typically located
after the air preheater, and the waste products are collected in a baghouse or ESP. Figure 3 shows a typical
process flow diagram for a CDS FGD system. Inside the CDS absorber the velocity provided by the flue gas
maintains a fluidized bed that is comprised of solids that are recirculated from the baghouse, including the
lime reagent and fly ash. In contrast to the SDA system, lime and water are injected separately into the CDS
absorber. Reagent is added to control SO2 removal, and water is added to control the exit temperature above
the adiabatic saturation temperature, again to protect downstream equipment.

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REAGENT HANDLING AND PREPARATION

Preparation of the hydrated lime involves an atmospheric lime hydrator for a CDS system or a lime slaker in
an SDA system. In this process, the pebble lime, CaO, is hydrated to Ca(OH)2 with the addition of water. The
hydrated lime also can be purchased as a reagent; however, converting commercially available lime into
hydrated lime on the plant premises generally offers a lower-cost solution. The reagent is fed to the absorber
to replenish hydrated lime consumed in the reaction, and the feed rate is typically controlled based on the
removal efficiency required.

Figure 3: Typical CDS FGD System

For SDA systems, the slaked lime slurry flows to a storage tank where it is held until it is needed by the
atomization process. The slurry is stored in a dedicated lime slurry storage tank prior to being combined with
the recycle stream.

For the CDS process, the dry hydrated lime is stored in a day silo until it is used in the absorber. Typically, the
hydrated lime is fed to the CDS absorber by means of a rotary screw or gravimetric feeder after being mixed
with the dry recycle products.

RECYCLE ASH SYSTEM

Dry FGD technologies can continuously recycle solids to the absorber to achieve high utilization of the
reagent. A portion of the waste solids from the baghouse or ESP will be sent to the recycle system. The
recycle train is important in achieving high SO2 removal efficiencies. There is residual activity left in the lime
after it has been passed through the system once; therefore, it is re-introduced to gain additional lime

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utilization. Systems designed with little or no recycle use a much higher quantity of reagent as compared to
the SO2 removed (referred to as the stoichiometric ratio).

The CDS has a distinctive feature in that material also recirculates within the absorber/baghouse system to
achieve a high lime particle retention time. It is this solid circulation that makes high removal efficiency
possible with such a dry process and for this reason the process is called the Circulating Dry Scrubber. The
CDS is designed for high recycle rates and therefore high ash loading is not unusual. The venturi nozzles at
the inlet (bottom) of the absorber are made of erosion resistant steel, so there is less concern about potential
erosion from the high ash content of the fuel.

TEMPERATURE CONSIDERATIONS

In the process of evaporating the moisture, the flue gas is cooled from the absorber inlet temperature of
approximately 150°C (300°F) to an outlet temperature of 71-82°C (160-180°F) depending on the adiabatic
saturation temperature of the flue gas. The actual outlet temperature is chosen based on the optimum reagent
utilization, the flue gas saturation temperature, and the required SO2 removal efficiency. The absorber typically
will be operated at 16°C (30°F) above the flue gas saturation temperature (also known as the approach
temperature) to prevent solids deposition on the walls of the absorber and to avoid moisture condensing in the
particulate collector. Because the flue gas exiting the DFGD typically is held at 16°C above saturation, carbon
steel ductwork is adequate and alloys are not needed. Therefore, the downstream ducts, baghouse, and
chimney liner can all be made of carbon steel in DFGD systems.

ABSORBER SYSTEM

The SDA is a vertical, open chamber with concurrent contact between the flue gas and lime slurry. The slurry
is injected at the top of the tower using either a rotary atomizer or a dual-fluid nozzle, which produces fine
droplets to absorb the SO2. The slurry droplets come into contact with the flue gas inside the SDA vessel, and
the slurry droplets must be dry before they contact the SDA wall. The residence time of the cooled flue gas in
the SDA should be at least 10 seconds to ensure high SO2 removal efficiencies. Most current designs utilize a
residence time of over 12 seconds. The majority of the solids leaves with the flue gas and are collected in the
particulate collection device.

The CDS system started as a circulating fluidized bed (CFB) reactor and was invented in the 1980’s by Lurgi.
In the CDS absorber, flue gas is treated in a circulating fluid bed absorber by exposing the gas stream
counter-currently to a mixture of hydrated lime and recycled by-product. Flue gas enters the bottom of the
absorber at high velocity through venturi nozzles that help maintain the fluidized bed in suspension and well-
mixed. The water is injected in the absorber to cool the gas. The desulfurized flue gas passes out of the
absorber, along with the particulate matter (reaction products, unreacted hydrated lime, calcium carbonate,
and the fly ash) to the particulate collector (ESP or baghouse). The particulate matter that is collected is either
recirculated back to the reactor to utilize lime that has not yet reacted, or sent to the byproduct silo for
disposal.

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SELECTION CRITERIA FOR DRY FGD SYSTEM

Some positive features that can play an important role in the selection of dry FGD technology are that, in
general, dry FGD systems:
 Have lower capital costs due to carbon steel absorber metallurgy and dry stack operation without
requiring new stacks or gas-to-gas heat exchangers
 Are less complex to operate (although SDA recycle systems can be operator intensive)
 (CDS Systems) Have shown SO2 removal efficiencies close to wet FGD systems and are more
flexible with respect to fuel sulfur levels than SDA systems
 Require a smaller footprint area than wet FGD
 Are very efficient at removing fine ash particles or sulfuric acid mist (especially when used in
conjunction with a baghouse)

Some potential disadvantages of dry FGD systems that can drive the selection to a wet FGD technology are
that, in general, dry FGD systems:
 (SDA Systems) Cannot accept as wide variety of fuel sulfur levels and are not as highly efficient
at removing SO2 as wet FGD or CDS systems
 Generally do not remove significant quantities of mercury unless there is activated carbon, or
unburned carbon in the fly ash present
 Are limited in low load operation: the SDA because water and reagent are added together as a
slurry, and the CDS because it requires high enough velocities to maintain a fluidized bed
 Generally do not produce a saleable byproduct, which may be an important selection criteria in
India considering regulations to utilize fly ash; however, preservation of fly ash sales can be
maintained if existing ESP captures most fly ash ahead of the dry FGD
 Requires a new particulate removal device, generally a new baghouse, which increases both
capital and operating costs (higher pressure drop as well as filter bag replacement costs)

CONCLUSION

Depending on the year in which an existing coal-fired power plant began operation in India, increasing
stringency in SO2 removal may be required with the recently proposed regulation. Because retrofitting FGD
systems will increase capital investments required as well as operating costs, it is critical that the most
economical FGD technology be selected. Technology selection may depend on certain site-specific
requirements such as reagent availability, local regulations, or other factors; therefore, there is not a single
answer that is applicable to all coal-fired units.

This paper discussed some of the advantages and disadvantages of wet and dry FGD technologies.
However, the authors note that there are other lower cost technologies such as Dry Sorbent Injection (DSI),
where a sodium-based reagent such as sodium bicarbonate, is injected into the flue gas upstream of the
existing ESP. In addition, seawater scrubbers may also be selected for use in coastal areas.

When selecting technologies, it is important to analyze all of the available options and then perform an
economic analysis to determine the system that leads to the overall most economic choice over the lifetime of

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the plant. A technology selection study must be performed by personnel who have experience in all types of
FGD technologies to ensure that conceptual arrangements, design inputs, and costs are reflective of the
conditions that exist at each unique power plant.

REFERENCES

1. Draft notification issued by Ministry of Environment, Forest and Climate Change on April 2015 which Central Government
proposes to issue under the Environment Protection Act 1986 (29 of 1986).
2. Central Electricity Authority’s (CEA) September 2015 monthly report on all India installed capacity of power station -
http://cea.nic.in/reports/monthly/installedcapacity/2015/installed_capacity-09.pdf.

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