WET FGD (DUAL ALKALI)
The flue gas is passed through specially designed Enviropol-Ventray FGD Scrubber to suit dual alkali (Caustic/lime) application for over 95% Sox removal at optimized operating cost.
This Scrubber is designed to de-sulfurize the flue gas in two stages with lime & Caustic solution as solvents. The primary stages includes a Venturi section operating with lime followed by the final scrubbing with caustic solution using multi stage tray/spray tower.
The clean and de-sulphurised gas is then reheated using steam heater, mounted on top of the tray tower as an optional device before exit to the atmosphere through integrated stack.
The effluent generated is processed for de-watering for sludge disposal or for byproduct recovery in the form of saleable Gypsum/Sodium Sulphate.
Enviropol Engineers is a leading flue gas desulfurization manufacturers, suppliers and exporters company from India. We are supplying high quality flue gas desulphurization technology around the world at the most competitive prices.
Indian coal contains sulphur in the range of 0.2 per cent to 0.7 per cent by weight. With this sulphur content, it is estimated that domestic coal-based plants emit Sulphur Dioxide (SO2) in the range of 800-1,600 mg/Nm3. This is way above the levels specified in the revised emission norms. Revised emission norms of flue gas desulfurization in India was specified by govt in December 2015, by the Ministry of Environment, Forest and Climate Change (MoEFCC). All companies are, therefore, retrofitting thermal power plant (TPP) units with SOx-control technologies from the flue gas desulfurization manufacturer. So flue gas desulfurization companies are providing the SOx-control technologies to follow the govt norms for the emission.
One of the most widely used technologies for Sulphur Oxide (SOx) control is wet flue gas desulphurisation (FGD) based on limestone. Under this post-combustion SOx elimination method, SOx is oxidised to form gypsum, which can then be eliminated as a byproduct. Apart from limestone, seawater and ammonia can be used in wet flue gas desulfurization (FGD) as reagents. Some of the other post-combustion SOx-control technologies are dry and semi-dry flue gas desulfurization (FGD), and dry absorbent injection (DSI). SOx emissions can also be managed through pre-combustion technologies such as coal beneficiation as well as in-combustion technologies such as circulating fluidised bed combustion (CFBC).
Wet flue gas desulphurization system roughly has SOx removal efficiency of over 90 per cent. On the basis of the reagent used, an FGD equipment can be classified as seawater based, ammonia based and limestone-based. Wet flue gas desulfurization system (FGD) comprises four main processes- flue gas handling, reagent (limestone) handling and preparation, absorber and oxidation, and secondary water and gypsum handling. Wet freshwater flue gas desulphurization equipment uses limestone slurry to remove SOx. The flue gas drawn from the boiler is directed into the absorption tower by a booster fan. Inside the absorber tower, the flue gas comes in contact with the limestone slurry, sprayed through nozzles installed at the top of the tower. A chemical reaction occurs between the SOx in the gas and the limestone slurry, leading to the formation of calcium sulphite. Calcium sulphite is then oxidised at the bottom of the tower using compressed air and converted into calcium sulphate or gypsum. A saleable byproduct, gypsum can be used as a raw material in the cement manufacturing industry. However, good quality limestone is required to produce saleable gypsum.
Seawater-based flue gas desulphurization technology uses seawater as a reagent and no other chemicals are required for SOx removal. Since seawater is naturally alkaline, it absorbs acidic gases like SOx. The effluent seawater, after the reaction, flows into a seawater treatment system to complete the oxidation of the absorbed SOx into sulphate. The sulphate ion thus formed is harmless and can be sent back to the sea.
The selection of flue gas desulphurization technology (FGD) is done on the basis of economic, technical and commercial aspects. These include capital cost, operating cost, the efficiency to remove SO2, performance reliability, space requirement, and a proven track record. While wet limestone-based freshwater flue gas desulfurization system is techno-economically feasible for inland power stations, ammonia-based FGDs are not very popular because the reagent (ammonia) is considerably more expensive and hazardous than limestone. Moreover, there is a risk of ammonia slip, that is, ammonia releasing into the atmosphere without any reaction taking place in the flue gas desulphurization system (FGD), which poses environmental hazards. Hence, wet limestone-based FGD is a preferred option because the reagent is easily available and inexpensive and can be easily handled. Meanwhile, seawater-based FGD is mostly used in coastal plants.
Dry and semi-dry flue gas desulfurization equipment includes a range of technologies in which SOx reacts with limestone particles in a humid environment to form sulphite. Broadly, dry and semi-dry FGD processes include furnace/duct sorbent injection using sodium/calcium-based reagent and the spray drier absorber (SDA) technology using slaked lime or limestone as reagent. An SDA system uses a roof gas disperser, a central gas disperser for dispersing flue gas and an atomiser to spray the reagent slurry. Inside an SDA system, limestone slurry is atomised and sprayed over the flue gas to absorb SOx. The dry product thus formed is collected in an electrostatic precipitator (ESP). Dry FGDs equipments are economically more feasible for smaller power producing units. In units of the capacity of over 400 MW, wet flue gas desulphurization system installation works out to be less expensive.
Another post-combustion SOx removal technology is DSI. This is mostly used in small power generation units that are less than or equal to 250 MW. DSI has SOx removal efficiency of 50–60 per cent. This is sufficient to meet the SO2 emission norms, in cases where these emissions are in the range of 800-1,000 mg per Nm3. DSI uses calcium-based (calcium hydroxide) or sodium-based (sodium bicarbonate) sorbent to remove SO2. It is a feasible alternative for units that would not find it cost-effective to invest in a wet or dry flue gas desulphurisation system. Besides this, the erection and commissioning period of a DSI system is only around one year, which is much lower than other technologies. However, the downside of DSI is that sorbent injection generates extra dust loads on electrostatic precipitators (ESPs), thus necessitating retrofitting of ESPs simultaneously. Notably, NTPC has opted for DSI at its Dadri power plant.
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