FGD’s solution for pollution

By Jessica Roberts
Published: Tuesday, 28 June 2011

END USER FOCUS: New coal-fired power capacity and crackdowns on existing polluting sites continue to lead demand for flue gas desulphurisation and its key mineral consumption

Sokolovska Uhelna’s 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 product.

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&W’s 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.

Wet scrubbers

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 Power’s 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 site’s proximity to the coast.

Wet scrubber designs vary significantly, with available technologies including:

  • 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 sorbent;
  • Fluidised packed tower design or turbulent contact absorber: similar to the packed tower, with the main difference being that the packing is fluidised.
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 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.

Sorbent injection

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 (CaSO3).

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.

A regenerable 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 stations.

End markets

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

Plant basics: Ratcliffe-on-Soar is one of the UK’s 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.

Technology: Wet scrubbing. Warman centrifugal pumps transport limestone slurry to Ratcliffe’s 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 gas.

Comanche power station, USA, operated by Xcel Energy

Plant basics: 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.

Technology: Lime spray dry-scrubbing. Systems were installed by Babcock & Wilcox Power Generation Group, the exclusive North American licensee of GEA Process Engineering’s Niro spray dryer absorber technology.

B&W PGG project scope: 

  • 7x spray dry absorber systems (two for Units 1 and 2 and three for Unit 3)
  • Recycle ash systems
  • Lime railcar unloading systems
  • Lime slaking systems
  • 2x10 compartment pulse jet fabric filter for Unit 3
  • Mercury removal system
  • 2x15,000 hp induced draft axial fans for Unit 3
Property Total
Area covered by FGD plant 12.5 hectares
Absorber tower height 50 metres
Construction materials used
Concrete/stone 58,500 tonnes
Steel reinforcement 5,000 tonnes
Hardcore /stone filling 16,000 tonnes
FGD plant steel work 50,000 tonnes
Total area of rubber lining in absorbers 9,400 m2
Area of ductwork lined with glass flake vinylester 35,200 m2
Glass reinforced pipework 10,000 metres
Carbon pipework 8,000 metres
Process parameters
Weight of gas treated 57,000 tpd
Design SO2 efficiency 92%
Typical quantity of SO2 removed 155,000 tpa
Average quantity of limestone used 340,000 tpa
Average quantity of gypsum produced 480,000 tpa