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 per Nm3. This is way above the levels specified in the revised emission norms, issued in December 2015, by the Ministry of Environment, Forest and Climate Change (MoEFCC). Developers are, therefore, retrofitting thermal power plant (TPP) units with SOx-control technologies.
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 FGD as reagents. Some of the other post-combustion SOx-control technologies are dry and semi-dry 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 FGD
The most commonly installed SOx removal technology solution is wet FGD. The first FGD system was installed at NTPC’s 500 MW Vindhyachal Stage V project and is based on wet limestone technology. It has been able to achieve SOx emissions of 80-90 mg per Nm3 from an inlet of 1,200 mg per Nm3. Other projects where wet FGD technology is being implemented include the 1,320 MW Solapur super thermal power plant, the 1,320 MW Tanda Stage II project, the 500 MW Unchahar project and the 1,320 MW Meja power project.
Wet FGD systems roughly have SOx removal efficiency of over 90 per cent. On the basis of the reagent used, an FGD can be classified as seawater based, ammonia based and limestone-based. Wet FGD comprises four main processes- flue gas handling, reagent (limestone) handling and preparation, absorber and oxidation, and secondary water and gypsum handling. Wet freshwater FGD 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 FGD 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 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 FGD technology 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 FGD 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 FGD system, 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 FGD
Dry and semi-dry FGDs include 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 are economically more feasible for smaller power producing units. In units of capacity of over 400 MW, wet FGD installation works out to be less expensive.
DSI system
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 FGD 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.
Other technologies
One of the in-combustion methods to manage SO2 emissions is the use of CFBC. Crushed coal (5mm to 20mm in size) and limestone, mainly calcium carbonate (CaCO3), are injected into the bed just above an air distribution grid located at the bottom of the bed. The boiler tubes are immersed in the fluidised bed, and are in direct contact with the burning particles of coal. This results in a high rate of heat transfer. The limestone introduced with the pulverised coal reacts with the sulphur dioxide in the fluidised bed and absorbs it, thereby producing calcium sulphate or sulphite. The calcium salts formed are solids and remain trapped in the combustion chamber. SO2 emission reductions of up to 90 per cent can be achieved in fluidised bed combustion, and, therefore, can even be used for high sulphur coal. Another in-combustion SOx control technology is limestone injection. The limestone is either injected above the flame in the boiler, or into the ductwork. The SOx present in flue gases bonds with the dry sorbent and forms sulphites, which can be captured in the existing particulate controls. Limestone injection is one of the cheaper methods to control SOx emissions. This is mostly used for plants where adequate land is not available for installing post-combustion control technologies. However, managing SOx emissions by boiler limestone injection requires sophisticated design and fabrication modifications to ensure that boiler efficiency is not affected.
Apart from this, pre-combustion methods such as coal beneficiation can be deployed for reducing the sulphur content in coal. Coal beneficiation is a process in which coal is washed before pulverisation, to reduce its ash content. The use of washed coal can reduce SOx emissions by 25 per cent. Further, it helps in lowering particulate matter emissions by 30 per cent.
Conclusion
A number of technology solutions are available for meeting the MoEFCC’s prescribed SOx emission norms for coal-based plants. However, for best results, it is necessary to judiciously select the technology solution, based on factors such as the geographical location and age of the plant. That said, a host of issues and challenges such as the lack of manufacturing capacity and skilled manpower, problems in gypsum disposal, and unavailability of quality limestone continue to hamper FGD deployment. Further, developers are concerned about the loss in revenue during plant shutdowns for equipment installation, and the operational efficiency of SOx-control equipment during low load operation of plants. The resolution of these issues through policies and regulatory frameworks would go a long way in promoting the deployment of SOx-control technologies in the country.