Over the past few years, thermal power plant (TPP) developers in India have been taking steps to comply with the emission norms set by the Ministry of Environment, Forest and Climate Change (MoEFCC) in December 2015 the sulphur oxide (SOx) emission limit for TPPs. Indian coal contains sulphur in the range of 0.2 per cent to 0.7 per cent by weight, which results in domestic TPPs emitting sulphur dioxide (SO2) in the range of 800-1,600 mg per Nm3, which is way above the levels specified in the revised emission norms. Developers are, therefore retrofitting TPP units with SOx control technologies.
Recently, the MoEFCC extended the timelines for coal-based TPPs to comply with the emission norms by three to four years, depending upon the location of the plant. Besides this, the ministry has, for the first time, introduced a penalty mechanism, wherein a penalty would be levied on the operation of TPPs that remain non-compliant beyond the timeline.
One of the most widely used technologies for SOx control is wet flue gas desulphurisation (FGD) based on limestone. 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). The technology selection is based on several factors such as sulphur content in coal, SO2 removal efficiency requirement of a particular plant, availability of reagents (if any), disposal and handling of by-products, locational/geographical factors of the plant, unit size, plant life, and the space required for an FGD facility.
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 in 2018 and was based on wet limestone technology. NTPC projects where wet FGD technology is being implemented include the 1,320 MW Solapur Super TPP, 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. Depending on the reagent used, an FGD can be classified as seawater based, ammonia based or 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.
By far the most commonly used FGD technology is the wet scrubber. In a wet scrubber, a reagent such as limestone or lime, in slurry form, perhaps with additives, reacts in a spray tower with oxides of sulphur to form calcium sulphite, which is oxidised to form calcium sulphate or gypsum. This technology, however, requires large quantities of water. Water usage can be reduced by using semi-dry scrubbers, such as spray dry scrubbers or circulating dry scrubbers, or by dry scrubbing technologies.
Seawater-based FGD uses seawater as a reagent. They require no other chemicals for SOx removal. Since seawater is naturally alkaline, it absorbs acidic gases such as 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 considerations. FGD technologies that use ammonia as a reagent are preferable for units below 500 MW. Ammonia-based technologies have approximately 10 per cent less capex and auxiliary power consumption (APC) as compared to limestone-based FGD. Additionally, ammonia-based FGD technologies have the added advantage of readily saleable by-products such as ammonium sulphate. However, when choosing ammonia-based FGD technologies, the handling of ammonia and its availability need to be worked out properly. Moreover, there is a risk of “ammonia slip”, that is, ammonia being released into the atmosphere without any reaction taking place in the FGD system, which poses environmental hazards. FGD technologies that use limestone slurry as reagent are most versatile and suitable for units of any size. Limestone technology has a large footprint, relatively higher capex and reagent purity issues as compared to ammonia-based and dry-type FGD technologies. 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 reagents, 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 with capacities of over 400 MW, wet FGD installations work out to be less expensive.
Another post-combustion SOx removal technology is DSI. It is particularly preferable for small unit sizes in the 60-250 MW range. Since the cost of reagent in this technology is relatively higher than in wet limestone and ammonia-based FGD, units running on low plant life factors and with low remaining operating lives (seven to nine years) are preferable for DSI. DSI has an 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) sorbents to remove SO2. It is a feasible alternative for units that would not find it cost effective to invest in wet or dry FGD systems. Besides, the time needed to erect and commission a DSI system is only around one year, which is much lower than other technologies. Additionally, DSI-based technologies have considerably low capex (1/4th) and very little APC (1/10th) compared to wet limestone – and ammonia-based FGD technologies. However, the downside of DSI is that sorbent injection generates extra dust loads on ESPs, thus necessitating simultaneous retrofitting of the ESPs. Notably, NTPC has opted for DSI at its Dadri power plant.
One of the in-combustion methods of managing SO2 emissions is the use of CFBC. In this method, crushed coal (5 mm to 20 mm 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 come into 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 thus formed are solid and remain trapped in the combustion chamber. SO2 emission reduction of up to 90 per cent can be achieved through fluidised bed combustion. Therefore, this method 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 duct work. 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. It is mostly used for plants which do not have adequate land to install post-combustion control technologies. However, managing SOx emissions through 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 to reduce 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.
Issues and challenges
The wet lime desulphurisation process removes one mole of SO2 and in turn, produces one mole of CO2, a greenhouse gas responsible for global warming and climate change. The same is applicable to other SO2 control technologies such as DSI, semi-dry FGD and seawater FGD. Moreover, depending on the FGD technology implemented, coal consumption may also increase by up to 1 per cent due to increased APC, leading to the release of greenhouse gases. Besides, increased APC also reduces the efficiency of power plants. 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.
With regard to the generation of by-products, post the implementation of wet lime FGD in approximately 214 GW of power plants (about 90 per cent of the total capacity that is installing wet lime FGD), gypsum production is expected in the range of 14-21 million metric tonnes per annum, depending on the PLF range of 55-80 per cent and the sulphur content of 0.32 per cent in coal. Further, the FGD market is still developing in India, with limited availability of vendors and high dependence on imports from neighbouring countries. The overbooking of suppliers has resulted in an increase in manufacturing time for FGD equipment.
On the financing front, the installation of FGD systems is likely to entail a huge capital expenditure. FGD systems are to be installed in170 GW of the existing capacity, 10 GW of the capacity commissioned since the preparation of the phasing plan by the Central Electricity Authority, and around 58 GW of under-construction capacity. Considering the average price of Rs 5.5 million per MW, these FGD installations are estimated to entail a total capital expenditure of around Rs 131 trillion. Private power plants will face even worse funding issues. The Covid-19 outbreak has also added to the challenges being faced in FGD equipment manufacturing and installation.
The way forward
Although various emission control technologies are available in the market, understanding their efficacy in the Indian context is critical. Besides, addressing issues pertaining to the availability of equipment, trained manpower and funding could accelerate the compliance of TPPs with emission norms. Going forward, there is a need to extend the timeline for installation of FGDs, develop a graded action plan involving immediate FGD installations at the TPPs located in critically polluted areas, and initiate a phased manufacturing programme for FGD units.