|Sokolovska Uhelnas 125 MWe
plant in Vresova, Czech Republic, was retrofitted FGD
technology by Enprima Engineering in 2000, and can now
remove 95% SO2 emissions.
Enprima Engineering Ltd
Flue gas desulphurisation (FGD)
technology is primarily used by fossil fuel-burning power
stations to remove acids - namely sulphur dioxide
(SO2) - from gaseous effluents, although
smaller markets such as incinerators and industrial boilers
also use FGD systems to clean up their emissions.
The harmful effects of
SO2 on the environment have been well-documented,
and it is known that both natural and man-made sources of
SO2 and nitric acid (NOx) contribute to
the formation of acid rain - created when the gases react
in the atmosphere with oxygen, water, and other chemicals to
form numerous acidic compounds.
FGD technology is based on a
chemical reaction that occurs when the warm exhaust gases from
the coal-fired boiler come into contact with a reagent -
usually a calcium-based mineral such as limestone - to
generate an inert waste product. In this instance,
SO2 in the flue gas reacts with the limestone to
form gypsum (CaSO3, calcium sulphite), effectively
trapping the sulphur and producing a commercially viable waste
Overall there are six main
categories under which FGD technology can be classified: wet
scrubbers, spray dry scrubbers, dry scrubbers, sorbent
injection, regenerable systems, and combined
SO2/NOx removal processes.
As Ryan Cornell of Babcock &
Wilcox Co. (B&W) told IM, the selection of
certain FGD technologies by a company is based primarily on the
combination of the properties of the fuel being burned and the
outlet emissions necessary.
Wet scrubber technology is
most prevalent on units burning mid-high sulphur fuels
(>1.5% sulphur) and the spray dry absorber technology is
most prevalent on units burning low sulphur fuels (<1.5%
sulphur), Cornell explained.
B&Ws subsidiary company,
B&W Power Generation Group Inc., produces a range of
technologies for SO2 control including wet,
seawater, spray dry absorber, circulating dry scrubber, and dry
sorbent injection systems.
Depending on the needs of the
customers, all five of our technologies have been
deployed, Cornell revealed.
The most prevalent FGD technology is wet scrubbing, which can
remove up to 99% of pollutants from power station emissions. It
uses slurry mixtures of calcium, sodium and ammonium-based
sorbents to react with SO2 gases inside vessels
designed for the task. Limestone is the preferred sorbent for
wet scrubbers, followed by minerals such as lime, owing to its
wide availability and low cost.
Seawater, caustic soda, sodium
carbonate, potassium and magnesium hydroxide have also been
applied in wet scrubbing Scottish Powers Longannet
power station in Scotland, UK (where $650m. has been invested
in FGD technology since 2006), uses seawater scrubbing on three
coal-fired generating units, owing to the sites proximity
to the coast.
Wet scrubber designs vary
significantly, with available technologies including:
pressurised scrubbing slurry enters the reaction chamber
through spray nozzles, which atomises the scrubbing liquid; gas
is dispersed into bubbles, providing large sorbent surface
area; vertical chamber in which a turbulent frothing zone is
created to generate the reaction contact;flue gas flows upwards
through a packing material counter-current to the sorbent;
similar to the packed tower, with the main difference being
that the packing is fluidised.
Spray tower design: pressurised
scrubbing slurry enters the reaction chamber through
spray nozzles, which atomises the scrubbing liquid;
Plate tower design: gas is dispersed
into bubbles, providing large sorbent surface area;
Impingement scrubber design: vertical
chamber in which a turbulent frothing zone is created to
generate the reaction contact;
Packed tower design: flue gas flows
upwards through a packing material counter-current to the
Fluidised packed tower design or turbulent
contact absorber: similar to the packed tower,
with the main difference being that the packing is
Spray dry scrubbers
After wet scrubbing technology (which accounts for around 85%
of installed FGD units in the USA), spray dry scrubbing is the
second largest technology for FGD, accounting for about 12% of
installed units in the USA.
The principal industrial minerals
used as sorbents in this application are lime and quicklime
(calcium oxide, CaO), which are sprayed in the form of lime
slurry into a reactor vessel as fine droplets. The heat of the
flue gas causes water to evaporate while the lime reacts with
acidic gases within the flue gas (including SO2,
SO3, and HCl) to produce dry calcium sulphate.
Because water is evaporated in the
spray dry absorber there is no waste water to treat, while some
of the lime may be reused in a new slurry mixture if it does
not react in its initial application.
Despite these benefits, spray dry
scrubbing technology uses a more expensive sorbent (lime-based)
and so is comparable in cost to wet scrubbing. In addition, it
is most efficient used on small (<200 MW) sites, as larger
plants can require a number of modules to cope with the total
flue gas flow. Spray dry scrubbing requires the use of
efficient filters to control particulates.
Also requiring particulate control measures is sorbent
injection technology which, at its simplest, is the injection
of a sorbent (usually limestone or hydrated lime) into the
upper level of a furnace containing flue gases. In practice
there are four injection systems, including furnace sorbent
injection, but also: economiser sorbent injection, duct sorbent
injection, and hybrid sorbent injection.
In furnace sorbent injection, the
sorbent is distributed evenly over the upper region of the
furnace, reacting with O2 and SO2 at
temperatures around 750-1,250¼C to form calcium sulphate
(CaSO4) - later captured, along with unreacted
sorbent and fly ash, in filters.
The economiser sorbent injection
process, meanwhile, uses hydrated lime to capture acid gases by
injecting the sorbent into the flue gas stream near the
economiser region. This differs to the reaction in the furnace
process described above, because the temperatures are much
lower (around 300-650¼C) meaning the sorbent is not
dehydrated Ð and so the waste product of the reaction
between the sorbent and SO2 is calcium sulphite
Duct sorbent injection tends to use
calcium or sodium-based sorbents, which are distributed after a
preheater in the flue gas duct - meaning the reaction
between the flue gas and sorbent is contained within the
ductwork. If a prefilter is installed, it is possible to create
a set-up whereby fly ash and desulphurisation waste products
are separated - ie. for commercial use later. This set-up
also aids the recirculation of unreacted sorbents.
Hybrid sorbent injection tends to
combine the furnace injection system with duct injection
technology, resulting in an overall more efficient
desulphurisation process - owing to greater utilisation of
the sorbent plus higher rates of SO2 removal.
Other FGD technologies
Dry scrubbers utilise a dry sorbent to reduce
SO2 emissions in the flue gas stream via two
methods - a circulating fluid bed (CFB) process, and a
moving bed system.
Hydrated lime is used with CFB,
where it is injected into the CFB reactor along with water.
Flue gas enters at the base of the reactor and moves upwards
through a venturi scrubber (a converging/diverging section of
duct). When the sorbent and flue gas meet, the turbulence
atomises the liquid into small droplets and the desired
chemical reactions take place. Over 95% of SO2
content can be removed from flue gases using this process, but
it consumes a significant amount of energy.
The moving bed system, a
lesser-used technology, uses a dry sorbent mixture of fly ash
and lime which is injected into the absorber. The process
removes around 90% of SO2 emissions.
system essentially regenerates the sorbent via
chemical or thermal means for re-use. In this process,
elemental sulphur and sulphuric acid can be recovered from the
SO2 removed. Although this system can achieve
SO2 removal rates of 95%, while generating little or
no waste (or waste water), it requires a pre-scrubber stage to
control the chloride content of the flue gases. High power
consumption is also a penalty.
Combined FGD systems for SO2 and
NOx removal are fairly rare and still in the
developmental stage, although commercially they have been
installed on low to medium-sulphur coal-fired power
Utility power plants are the largest consumers of minerals for
FGD, accounting for 93% of the US FGD market in 2009, according
to the US Geological Survey. The balance of the FGD market
comes from incinerators, industrial boilers, and others.
Although the need to remove
SO2 from power station emissions has been addressed
for many years, the technology to do this has only become
efficient enough during the last few decades - led mainly
by Europe and North America.
But Asia, where coal remains by far
the largest source for power generation, will undoubtedly need
to invest heavily in FGD technology over the coming
years - the Mae Moh power plant in Thailand, with a 2,625
MW capacity, being a prime example of an environmental-led
intervention and retrofit.
Installation of new coal-fired energy capacity in addition
to necessary retrofitting will undoubtedly see demand for FGD
technologies - and the mineral sorbents utilised by
them - continue to grow over the long-term.
FGD case studies
Racliffe-on-Soar power station, UK,
operated by E.ON
Ratcliffe-on-Soar is one of the UKs most efficient coal
fired power stations, with a total generation capacity of 2,000
MW sourced from four 500 MW units. Each of the four 500 MW
generation units is fitted with FGD equipment, removing 92% of
the SO2 from flue gases before they are released
into the environment.
scrubbing. Warman centrifugal pumps transport limestone slurry
to Ratcliffes absorber towers. These are the largest of
their type in the world and are capable of circulating in
excess of 8,000 tph of slurry. The limestone slurry also
removes up to 95% of the hydrogen chloride present in the flue
Comanche power station, USA,
operated by Xcel Energy
Comanche power station in Pueblo, Colorado, has a generation
capacity of 1,555 MW, sourced from three units - two
smaller (360 MW and 365 MW) units, together with one 830 MW
unit that was commissioned in 2006 from Alstom.
spray dry-scrubbing. Systems were installed by Babcock &
Wilcox Power Generation Group, the exclusive North American
licensee of GEA Process Engineerings Niro spray dryer
B&W PGG project scope:
|Area covered by FGD plant
|Absorber tower height
|Construction materials used
|Hardcore /stone filling
|FGD plant steel work
|Total area of rubber lining in absorbers
|Area of ductwork lined with glass flake
|Glass reinforced pipework
|Weight of gas treated
|Design SO2 efficiency
|Typical quantity of SO2 removed
|Average quantity of limestone used
|Average quantity of gypsum produced