Thermal power plants, in addition to emitting greenhouse gases, also release local pollutants such as sulphur dioxide (SO2) and nitrogen dioxide (NO2). As per the data recorded and studied by the National Aeronautics and Space Administration, SO2 emissions in India increased by over 70 per cent between 2005 and 2012. Thermal power generation is seen as the largest contributor to the SO2 emissions in the country. With coal expected to continue to be the mainstay of power generation in India, SO2 emissions are likely to increase unless measures are adopted to control them.
There are two basic approaches to controlling SO2 emissions from power plants. These approaches reduce the sulphur in the fuel either through fuel blending or fuel switching to lower sulphur coal, or utilising a technology to remove SO2 from the flue gas. Depending on the needs of specific power plants, various technologies have evolved for this over time. These include wet flue gas desulphurisation (FGD), dry FGD, circulating dry scrubber (CDS), and dry sorbent injection (DSI).
The adoption of SO2 emission control technologies has been limited in India. One of the key reasons for this has been the absence of definitive SO2 emission regulations. Policies to control air pollution from power plants have traditionally focused on reducing particulate emissions due to the high ash content of Indian coal. The low sulphur content of Indian coal has, perhaps, been the reason for the lack of focus on the control of SO2 emissions. However, with the increasing use of imported coal, which has a higher-sulphur content, it is important to look into SO2 emission control.
Supporting this view, the Ministry of Environment, Forest and Climate Change notified the Environment (Protection) Amendment Rules, 2015 in December, 2015, which specify the SO2 emission limits for thermal power plants. According to the notification, the SO2 emission limit for thermal power plants installed/to be installed by December 31, 2016 with a capacity of less than 500 MW is 600 mg per Nm3 (milligrams per normal cubic metre), and for units with a capacity of 500 MW and above, the limit is 200 mg per Nm3. Meanwhile, for plants under construction that will be installed after January 1, 2017, the SO2 emission limit is specified as 100 mg per Nm3 only, irrespective of the capacity. The amendment also requires all the plants installed/to be installed by December 31, 2016 to be in compliance with the standards by December 2017.
In this context, Power Line takes a look at some of the technologies that are currently being deployed for SO2 emission control…
Wet FGD is the predominant and oldest technology used across the world for reducing SO2 emissions from power plants. The process typically uses a calcium or sodium-based alkaline reagent in a solution or slurry form. Limestone is the most commonly used reagent for wet FGD since it is more abundant and relatively cheap as compared to other alkalis such as sodium carbonate, magnesium carbonate and ammonia. In wet FGD systems, the alkali and flue gas are brought into contact in a spray tower where the alkali reacts with SO2 in the flue gas to produce a mixture of sulphite and sulphate salts. The sulphite and sulphate salts thus produced precipitate out of the solution, depending on the relative solubility of the different salts present.
Wet processes are highly efficient and can achieve SO2 removal of 90 per cent or more. In addition to these, wet FGDs have been used successfully for various types of coal including anthracite, bituminous, sub-bituminous, lignite and brown coals.
Dry and semi-dry FGD
Dry FGD is an alternative to wet FGD for SO2 emission control in power plants. The process is similar to wet FGD, except that it uses a dry solid reagent in place of a solution reagent. A spray dryer absorber (SDA) is an example of a dry FGD system. In an SDA system, lime slurry is atomised and sprayed into the hot flue gas to absorb the SO2 and other acid gases. The SDA cools the flue gas to 65-75 degree Celsius (149-167 degree Fahrenheit) before the gas passes through the fabric filter. As a result, any metals that have a vapour pressure at flue gas temperature tend to be present more in the solid state and are easier to capture in the fabric filter. The resulting dry material, which includes reaction products and fly ash, is collected in a downstream particulate control device, typically a fabric filter or sometimes an electrostatic precipitator (ESP).
Dry systems are capable of removing 70–90 per cent of sulphur oxide and often have lower capital and operating costs, energy and water requirements, and maintenance requirements. Another advantage of this process is that the dry material can be recycled back into the lime mixture, which can help in minimising lime usage because of the alkaline nature of the ash. Another form of FGD is the semi-dry FGD system. In semi-dry FGD systems, the sorbent is introduced as aqueous slurry, but the water content is controlled so that the slurry dries completely in the flue gas ductwork and the by-products are dry solids.
CDS technology is another type of a dry FGD system. It is primarily useful where the sulphur content in coal is medium to high. This technology uses a fluidised bed to bring the reagent (typically hydrated lime) in contact with the SO2 in the flue gas. Water spray is introduced into the fluidised bed separately from the dry reagent, which enhances the performance by optimising the surface moisture content of the lime. The mixture of the remaining products (calcium sulphite/sulphate), unused lime, and fly ash is carried to a downstream particulate collector and is separated from the gas stream. Some part of the waste is mixed with fresh calcium hydroxide to be used again in the process.
CDS can remove SO2 up to around 98 per cent, depending on specific conditions of the application. In addition, the use of an integral jet fabric filter can lead to a higher emission reduction. Compared to wet FGD systems, CDS systems involve lower costs. Also, the CDS creates a dry solid by-product and hence does not require a wastewater treatment facility.
Dry sorbent injection
DSI is the cheapest technology for emission reduction as compared to the above three technologies. DSI involves the injection of a dry sorbent (typically sodium bicarbonate or lime) into the ductwork from the boiler. SO2 reacts directly with the dry sorbent, and the dry product is collected in a downstream particulate control device. Since the system does not require a separate absorber vessel, the capital costs are considerably lower. However, the low capital costs are partially offset by lower reagent utilisation, which results in higher operating costs for equivalent SO2 removal. Dry injection systems can typically achieve removal efficiencies ranging from 50 per cent to 70 per cent, depending on the specific conditions of the application.
As seen above, there are a number of technologies available for controlling SO2 emissions from power plants. The choice of emission control technology, however, depends on various factors such as scale of process, sulphur content in the coal, and the availability and cost of reagents. Some of the power plants that have installed SO2 reduction technologies in India are Adani Power’s Mundra power plant, Tata Power’s 500 MW Trombay power plant, Reliance Infrastructure’s 500 MW Dahanu power plant and the CLP Group’s 1,320 MW Jhajjar power plant. NTPC has also implemented FGD in its recently commissioned 500 MW plant in Madhya Pradesh, and has proposed to implement the same in upcoming projects such as the Bongaigaon Thermal Power Station in Assam due to the high sulphur content of Assam coal.
Although the adoption of SO2 reduction technologies has been relatively low in India, it is picking up steadily. Moreover, with the introduction of regulations to limit the SO2 emissions from power plants and developers looking to modernise their systems and improve overall efficiencies, emission control technologies are poised to play a greater role in the near future.