FGD: capturing mineral opportunities

Published: Monday, 21 September 2009

Murray Lines examines the key concepts and minerals in one of the most effective weapons against green house gas emissions, flue gas desulphurisation - the leading environmental market for minerals

Flue gas desulphurisation (FGD) is the technology used for removing sulphur dioxide (SO2) from the exhaust flue gases in power plants that burn coal or oil.

As the need for energy intensifies together with tightening environmental restrictions, significant opportunities exist for a host of industrial minerals in FGD which are used as the main capturing agent.

Calcium minerals (limestone powder, burnt lime and hydrated lime), and sodium bicarbonate are the main minerals used in FGD while wide applications for wollastonite and other minerals are being investigated. Caustic calcined magnesia is also used in limited volumes for specific FGD applications.

Flue gas desulphurisation will remove 95% or

more of the SO2 in the flue gases for typical

coal fired power station

The burning of coal and the cleaning of flue gases produces a large volume of material or residue (including fly ash, bottom ash, boiler slag, fluidised bed combustion (FBC) ash and FGD material) collectively referred to as coal utilisation by-products (CUB).

FGD units typically use a lime or limestone reagent to capture SO2 gas as calcium sulphite, most of which is subsequently converted to gypsum - a by-product of the capturing process - (CaSO4•2H2O) in forced oxidation units.

FGD-produced gypsum is mainly used as a substitute for natural gypsum in the manufacturing of wallboard, though it is also used, to a lesser extent, as a soil amendment or as an additive in cement. Coal contains a number of trace metals, and as a result CUB typically contains low concentrations of these metals.

As stricter emission control/reduction policies, particularly those focusing on mercury, are implemented, an increase in metals concentration in these by-products will likely occur.

Wet FGD technologies used for the removal of SO2 can result in the co-removal of highly-soluble oxidised mercury. Mercury removal efficiencies (on a coal-feed basis) in FGD units range from 50 - 75%, but when the units are preceded by selective catalytic reduction (SCR), devices which enhance the oxidation of HgO to the Hg2+, the range increases to 85 - 90%.

Depending on the FGD process, a portion of this mercury may be incorporated into the FGD slurry and its solid by-products including synthetic gypsum. The amount of mercury in FGD products may increase in the future if these units are optimised for co-capture. Among the issues that arise are the potential for atmospheric and groundwater releases of mercury during subsequent manufacturing processes, releases from the manufactured products, and post-disposal mobilisation from the wallboard or other products.

For this reason, it is important to understand the chemistry of the mercury-CUB interaction, to be able to predict the environmental fate of the CUB-bound mercury, and to be able to anticipate the effect of additional mercury loads in the CUB material.

The potential problems that may be encountered during the disposal of materials are most commonly addressed using laboratory leaching tests. In general, leaching techniques focus on the potential release of heavy metals to the surface and groundwater environments.

Leaching studies of CUB are often performed to determine the compatibility of the material in a particular end-use or disposal environment. Typically, these studies involve either a batch or a fixed-bed column technique. A number of studies have shown that fixed-bed column leaching can be used to estimate the impact of coal utilisation by-products under simulated field conditions.

Unfortunately, for some materials, permeability losses can occur in fixed-bed leaching columns, either because of cementing properties of the material itself, such as is seen for FBC fly ash, or because of precipitate formation, such as can occur when a high-calcium ash is subjected to sulfate-containing leachates.

Also, very fine-grained materials, such as gypsum, do not provide sufficient permeability for study in a fixed-bed column. A continuous, stirred tank extractor (CSTX) is an alternative technique that can provide the elution profile of column leaching but without the permeability problems. Objectives for this project are to use the CSTX and mineral extraction techniques to investigate the stability of mercury and other metals (particularly arsenic and selenium) in CUB, to obtain fundamental chemical data on the leaching process (KD, Ksp, rates, etc), and to explain the chemistry underlying the stability of mercury and other metals in CUB.

In addition to the CSTX leaching studies, a sequential extraction scheme is used to subject FGD-derived materials to a series of phase-targeted dissolution reagents. The amount of Hg extracted by each solution is chemically related to the mineral phases targeted by that solution. In this manner, the mineral phases with the greatest affinity for Hg and the form in which Hg is naturally immobilized can be discovered and related to the mineralogy of FGD materials. This data may also provide a basis for advanced Hg capture and sequestration technologies.

Capturing SO2

SO2 is the main cause of acid rain formation. Tall flue gas stacks disperse the emissions by diluting the pollutants in ambient air and transporting them to other regions.

As a result of stringent environmental protection regulations regarding SO2 emissions that have been enacted in a great many countries, SO2 is now being removed from flue gases by a variety of methods, with the following being the most common:

  •  Wet scrubbing using a slurry of alkaline sorbent, usually limestone or lime (both burnt lime and hydrated lime) or seawater to scrub the gases
  • Spray-dry scrubbing using similar sorbent slurries
  • Wet sulphuric acid process recovering sulphur in the form of commercial quality Sulphuric acid
  • Dry sorbent injection systems.

For a typical coal-fired power station, FGD will remove 95% or more of the SO2 in the flue gases, making it a very effective weapon against environmental damage.

The extended use of both retrofitting FGD and new units provides large new markets for lime producers. Asia has now embraced this new way of thinking and several companies are already positioning themselves for this growth. Asia is now well advanced in implementing this technology

Dry FGD basics

Limestone usage ~1.7 tonnes limestone/1 tonne SO2 removed
Limestone cost ~$6-15/tonne
Gypsum production ~3.1 tonnes gypsum/1 tonne SO2 removed (95% purity, 10% moisture)
Gypsum value >$10/tonne
Water consumption 1.5-1.8 gpm/MW
Power consumption ~Low S – 1.0-1.5% generation

~High S – 1.5-2.0% generation

Excludes the Particulate Collector

Source: Alstom

Lime usage ~1.2 ton limestone/1 tonne SO2 removed
Lime cost ~$60/tonne
By-product production Fly ash + Lime
Gypsum value Landfill or possible road bed
Water consumption ~1 gpm/MW
Power consumption ~.12-.15% generation 

Includes Particulate Collector

Source: Alstom

Emissions from fossil fuels

Flue gas emissions from fossil fuel combustion refers to the combustion product gas resulting from the burning of fossil fuels. Most fossil fuels are combusted with ambient air (as differentiated from combustion with pure oxygen). Since ambient air contains about 79% volume of gaseous nitrogen (N2), which is essentially non-combustible, the largest part of the flue gas from most fossil fuel combustion is nitrogen. The next largest part of the flue gas is carbon dioxide (CO2) which can be as much as 10-15% volume.

This is closely followed in volume by water vapour (H2O) created by the combustion of the hydrogen in the fuel with atmospheric oxygen. Much of the ‘smoke’ seen pouring from flue gas stacks is this water vapour forming a cloud as it contacts cool air.

A typical flue gas from the combustion of fossil fuels will also contain some very small amounts of nitrogen oxides (NOx), sulphur dioxide (SO2) and particulate matter. The nitrogen oxides are derived from the nitrogen in the ambient air as well as from any nitrogen-containing compounds in the fossil fuel. The sulphur dioxide is derived from any sulphur-containing compounds in the fuels. The particulate matter is composed of very small particles of solid materials and very small liquid droplets which give flue gases their smoky appearance.

The steam generators in large power plants and the process furnaces in large refineries, petrochemical and chemical plants, and incinerators burn very considerable amounts of fossil fuels and therefore emit large amounts of flue gas to the ambient atmosphere. The table on p.68 presents the total amounts of flue gas typically generated by the burning of fossil fuels such as natural gas, fuel oil and coal. The data in the table was obtained by stoichiometric calculations.

It is of interest to note that the total amount of flue gas generated by coal combustion is only 10% higher than the flue gas generated by natural gas combustion.

FGD wet scrubbers

To promote maximum gas-liquid surface area and residence time, a number of wet scrubber designs have been used in wet FGD systems, including spray towers, venturis, plate towers, and mobile packed beds.

Because of scale build-up, plugging, or erosion, which affects FGD dependability and absorber efficiency, the trend is to use simple scrubbers such as spray towers instead of more complicated ones. The configuration of the tower may be vertical or horizontal, and flue gas can flow co-currently, counter-currently, or cross-currently with respect to the liquid. The chief drawback of spray towers is that they require a higher liquid-to-gas ratio requirement for equivalent SO2 removal than other absorber designs.

Venturi scrubber

A venturi scrubber is a converging/diverging section of duct. The converging section accelerates the gas stream to high velocity. When the liquid stream is injected at the throat, which is the point of maximum velocity, the turbulence caused by the high gas velocity atomizes the liquid into small droplets, which creates the surface area necessary for mass transfer to take place. The higher the pressure drop in the venturi, the smaller the droplets and the higher the surface area. The penalty is in power consumption.

For simultaneous SO2 and fly ash removal, venturi scrubbers can be used. In fact, many of the industrial sodium-based throwaway systems are venturi scrubbers originally designed to remove particulate matter. These units were slightly modified to inject a sodium-based scrubbing liquor. Although removal of both particles and SO2 in one vessel can be economically attractive, the problems of high pressure drops and finding a scrubbing medium to remove heavy loadings of fly ash must be considered. However, in cases where the particle concentration is low, such as from oil-fired units, simultaneous particulate and SO2 emission reduction can be effective.

Plate towers

A packed scrubber consists of a tower with packing material inside. This packing material can be in the shape of saddles, rings or some highly specialised shapes designed to maximise contact area between the dirty gas and liquid. Packed towers typically operate at much lower pressure drops than venturi scrubbers and are therefore cheaper to operate. They also typically offer higher SO2 removal efficiency. The drawback is that they have a greater tendency to plug up if particles are present in excess in the exhaust air stream.

A spray tower is the simplest type of scrubber. It consists of a tower with spray nozzles, which generate the droplets for surface contact. Spray towers are typically used when circulating a slurry. The high speed of a venturi would cause erosion problems, while a packed tower would plug up if it tried to circulate a slurry.

Counter-current packed towers are infrequently used because they have a tendency to become plugged by collected particles or to scale when lime or limestone scrubbing slurries are used.

Scrubbing reagent

Alkaline sorbents are used for scrubbing flue gases to remove SO2. Depending on the application, the two most important are lime and sodium hydroxide (also known as caustic soda). Lime is typically used on large coal or oil fired boilers as found in power plants, as it is very much less expensive than caustic soda.

The problem is that it results in slurry being circulated through the scrubber instead of a solution. This makes it harder on the equipment. A spray tower is typically used for this application. The use of lime results in a slurry of calcium sulphite (CaSO3) that must be disposed of. Fortunately, calcium sulphite can be oxidised to produce by-product gypsum (CaSO4 á 2H2O) which is marketable for use in the building products industry.

Caustic soda is limited to smaller combustion units because it is more expensive than lime, but it has the advantage that it forms a solution rather than a slurry. This makes it easier to operate. It produces a solution of sodium sulphite/bisulphite (depending on the pH), or sodium sulphate that must be disposed of. This is not a problem in a kraft pulp mill for example, where this can be a source of makeup chemicals to the recovery cycle.

Scrubbing with sodium sulphite

It is possible to scrub SO2 by using a cold solution of sodium sulphite; this forms a sodium hydrogen sulphite solution. By heating this solution it is possible to reverse the reaction to form sulphur dioxide and the sodium sulphite solution.

In some ways this can be thought of as being similar to the reversible liquid-liquid extraction of an inert gas such as xenon or radon (or some other solute which does not undergo a chemical change during the extraction) from water to another phase. While a chemical change does occur during the extraction of the sulphur dioxide from the gas mixture, it is the case that the extraction equilibrium is shifted by changing the temperature rather than by the use of a chemical reagent.

Alternatives to FGD

An alternative to removing sulphur from the flue gases is to remove the sulphur from the fuel before or during combustion. Hydrodesulphurisation of fuel has been used for treating fuel oils before use. Fluidised bed combustion adds lime to the fuel during combustion. The lime reacts with the SO2 to form sulphates which become part of the ash.

From strength to strength

The removal of sulphur emissions from coal-fired power stations has been recognised for many years, but it is really in the past 30 years when the various technologies have evolved to a situation where high levels of efficiencies are now routinely sought and achieved.

European and North American companies have led the way with innovations and now state of the art processes are being introduced into the Asian region where coal remains the largest source for power generation at over 80%. Liquefied natural gas (LNG) is emerging as a strong secondary contender but it is obvious coal will be vital to maintaining our increasing need for electricity well into the future.

Therefore FGD will continue to grow strongly both in retrofitted units but also in virtually all new electricity power generating facilities. The volumes of lime and sodium bicarbonate will continue to grow and offer opportunities for industrial mineral producers.

Further reading

Hawley, G, “Minerals key to locking emissions”, Industrial Minerals, June 2009, p.48-53

Contributor: Murray Lines of Australia based industrial minerals market consultants, Stratum Resources

FGD at a glance

  • The main FGD methods are: Wet scrubbing, spray-dry scrubbing, wet sulphuric acid process, and dry sorbent injection systems
  • FGD will remove 95% or more of the SO2 in the flue gases for typical coal fired power station
  • Flue gas desulphurisation scrubbers have been applied to combustion units firing coal and oil that range in size from 5 MW to 1500 MW.
  • Scottish Power is spending £400m. ($660m.) installing FGD at Longannet Power Station which has a capacity of over 2 GW. Dry scrubbers and spray scrubbers have generally been applied to units smaller than 300 MW
  • The highest SO2 removal efficiencies (>90%) are achieved by wet scrubbers and the lowest (<80%) by dry scrubbers, however, the newer designs for dry scrubbers are capable of achieving efficiencies in the order of 90%
  • In spray drying and dry injection systems, the flue gas must first be cooled to about 10-20¡C above adiabatic saturation

    to avoid wet solids deposition on downstream equipment and plugging of bag houses

  • The capital, operating and maintenance costs per s. ton of SO2 removed (in 2001 US dollars) are:

Wet scrubbers > 400 MW              Cost: $200-$500

Wet scrubbers <400 MW               Cost: $500-$5,000

Spray dry scrubbers >200 MW     Cost: $150- $300

Spray dry scrubbers<200 MW      Cost: $500-4,000

Installed US FGD units


The basics of FGD chemistry

Most FGD systems employ two stages: one for fly ash removal and the other for SO2 removal. Attempts have been made to remove both the fly ash and SO2 in one scrubbing vessel. However, these systems experienced severe maintenance problems and low simultaneous removal efficiencies. In wet scrubbing systems the flue gas normally passes first through a fly ash removal device, either an electrostatic precipitator or a wet scrubber, and then into the SO2 absorber. However, in dry injection or spray drying operations, the SO2 is first reacted with the sorbent and then the flue gas passes through a particulate control device.

Another important design consideration associated with wet FGD systems is that the flue gas exiting the absorber is saturated with water and still contains some SO2. (No system is 100% efficient.) Therefore, these gases are highly corrosive to any downstream equipment - i.e., fans, ducts, and stacks. Two methods that minimise corrosion are:

(1) Reheating the gases to above their dew point and

(2) Choosing construction materials and design conditions that allow equipment to withstand the corrosive conditions.


SO2 is an acid gas and thus the typical sorbent slurries or other materials used to remove the SO2 from the flue gases are alkaline. The reaction taking place in wet scrubbing using a CaCO3 (limestone) slurry produces CaSO3 (calcium sulphite):

CaCO3 (solid) + SO2 (gas) → CaSO3 (solid) + CO2 (gas)

When wet scrubbing with a Ca (OH)2 (lime) slurry, the reaction also produces CaSO3 (calcium sulphite):

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 sulphite):

Mg(OH)2 (solid) + SO2 (gas) → MgSO3 (solid) + H2O (liquid)

To partially offset the cost of the FGD installation, in some designs, the CaSO3 (calcium sulphite) is further oxidized to produce marketable CaSO4 á 2H2O (gypsum). This technique is also known as forced oxidation:

CaSO3 (solid) + H2O (liquid) + ½O2 (gas) → CaSO4 (solid) + H2O

A natural alkaline usable to absorb SO2 is seawater. The SO2 is absorbed in the water, and when oxygen is added reacts to form sulfate ions SO4- and free H+. The surplus of H+ is offset by the carbonates in seawater pushing the carbonate equilibrium to release CO2 gas:

SO2 (gas) + H2O + ½O2 (gas)→ SO42- (solid) + 2H+

HCO3- + H+ → H2O + CO2 (gas)

Exhaust flue gas generated by consumption of fossil fuels (in SI metric units and in USA customary units)

Combustion Data Fuel Gas Fuel Oil Coal
Fuel properties:
Gross caloric value, MJ / Nm 43.01
Gross heating value, Btu / scf 1,093
Gross caloric value, MJ / kg 43.5
Gross heating value, Btu / gallon 150,000
Gross caloric value, MJ / kg 25.92
Gross heating value, Btu / pound 11,150
Molecular weight 18
Specific gravity 0.9626
Gravity, °API 15.5
Carbon / hydrogen ratio by weight 8.1
weight % carbon 61.2
weight % hydrogen 4.3
weight % oxygen 7.4
weight % sulphur 3.9
weight % nitrogen 1.2
weight % ash 12
weight % moisture 10
Combustion air:
Excess combustion air, % 12 15 20
Wet exhaust flue gas:
Amount of wet exhaust gas, Nm/ GJ of fuel 294.8 303.1 323.1
Amount of wet exhaust gas, scf / 106 Btu of fuel 11,600 11,930 12,714
CO2 in wet exhaust gas, volume % 8.8 12.4 13.7
O2 in wet exhaust gas, volume % 2 2.6 3.4
Molecular weight of wet exhaust gas 27.7 29 29.5
Dry exhaust flue gas:
Amount of dry exhaust gas, Nm/GJ of fuel 241.6 269.3 293.6
Amount of dry exhaust gas, scf / 106 Btu of fuel 9,510 10,600 11,554
CO2 in dry exhaust gas, volume % 10.8 14 15
O2 in dry exhaust gas, volume % 2.5 2.9 3.7
Molecular weight of dry exhaust gas 29.9 30.4 30.7

Focus on Mae Moh Power Plant, Thailand

Location: Mae Moh Valley, Lampang province

Installed capacity: 2,625 MW from 13 units

Units: 13 in total - 3 x 75 MW with stack height of 80 metres (25 years old); 3 x 150 MW with stack height of 150 metres; and 6 x 300 MW with height of 150 MW

Fuel: 50,000 tpd lignite mined from adjacent deposit with 3% sulphur content, dry weight basis


With respect to air pollution control, all thirteen units have electrostatic precipitator for particulate control with control efficiency of 99.9%. Only Units 12 and 13 (300 MW) have forced oxidation wet limestone flue gas desulphurisation for sulphur dioxide control from their design with control efficiency of 95%. Units 1 to 11 do not have sulphur dioxide control from their design. Low NOx burners are used to control emission of nitrogen oxides. The by-product gypsum suspension is dewatered to a residual moisture content of 15% and used together with boiler ash for the backfilling of local open-cast lignite mining pits.

FGD installation:

In order to fulfil Thai environmental regulations, the power station operator EGAT decided to retrofit Units 4-7 with desulfurization plants, in addition to units 8-13 which had already been provided with desulphurisation plants. EGAT contracted Evonik as consulting engineer for this FGD retrofitting project.

The FGD retrofitting concept provided for two stainless steel roll-plated absorber units based on the wet lime scrubbing process with regenerative gas-gas heating of the clean gas and FGD ID fans. The produced gypsum suspension is dewatered to a residual moisture content of 15% and used together with boiler ash for the backfilling of local open-cast lignite mining pits.

Outcomes and Policy:

  • The most cost-effective SO2 emission control measures implemented
  • No more new power plant in the Mae Moh Basin
  • A 11 tph SO2 restriction applied at anytime in summer, and 7 tph in winter
  • Retrofit Units 4-11 with Wet Limestone Forced Oxidation FGD with 98% control efficiency (Units 12-13 have FGD with original design)
  • To use lignite S <1%
  • Install Continuous Emission Monitoring System in all generating units
  • Continuously monitor ambient air quality
  • Not allowed to operate the power plant without FGD in operation


Units Installed capacity (MW/unit) Stack height Air pollution control system
1 to 3 75 80 EP (99.0%) low NOx burner
4 to 7 150 150 EP (99.9%) low NOx burner
8 to 13 300 150 EP (99.9%) low NOx burner/ FGD burner (unit 12,13)