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Technologies and retrofits to curb emissions from coal-fired plants  

The primary emissions in the air from the combustion of coal are sulphur dioxide (SO2), nitrogen oxide (NOx), particulate matter (PM), carbon monoxide (CO), and greenhouse gases such as carbon dioxide (CO2). Depending on the fuel type and quality, other substances such as heavy metals (mercury, arsenic, cadmium, etc.), unburned hydrocarbons and volatile organic compounds may be emitted in smaller quantities, but may have a significant impact on the environment due to their toxicity.

To reduce pollution during the process of electricity generation by coal-fired power plants, the Ministry of Environment, Forest and Climate Change (MoEFCC) had announced new emission standards in 2015. The aim was to address emission norms of pollutants such as SOx, NOx, PM, mercury and fly ash. The new emission control norms factored in the age of these coal-based power plants and provided for some allowances for over two-and-a-half-decade-old power plants. However, to effectively check pollution from such units, retrofitting and technological upgradation would be required such as the installation of FGD systems on boilers and post-combustion technologies such as SCR and SNCR, and effective tuning of boiler settings.  A quick look at the technologies and retrofits involved….



The range of options for reducing the emission of sulphur oxide varies substantially because of large differences in the cost of controls and the sulphur content in different fuels. The choice of technology depends on a cost-benefit analysis of the environmental performance of different fuels, and the existence of a market for sulphur control by-product.

One of the recommended measures is the use of FGD for large boilers using coal and large reciprocating engines. The optimal type of FGD for a plant is determined based on the capacity of the plant, fuel properties, site conditions, etc. (for example, wet FGD using limestone with up to 98 per cent removal efficiency, semi-dry FGD using lime with up to 94 per cent removal efficiency, seawater FGD with up to 90 per cent removal efficiency).

Wet scrubbers are the most widely used FGD technology for SO2 control throughout the world. Calcium-, sodium- and ammonium-based sorbents are used in a slurry mixture, which is injected into a specially designed vessel to react with the SO2 in flue gas. The preferred sorbent in operating wet scrubbers is limestone followed by lime. These are favoured because of their availability and relative low cost.

The air in flue gas causes some oxidation and the final product is a wet mixture of calcium sulphate and calcium sulphite (sludge). A forced oxidation step, in situ or ex situ (in the scrubber or in a separate reaction chamber) involving the injection of air produces the saleable by-product gypsum.

In  simple wet lime/limestone/gypsum scrubbers, all chemical reactions take place in a single integrated absorber resulting in reduced capital cost and energy consumption. The integrated single-tower system requires less space thus making it easier to retrofit in the existing plants.

Circulating fluid bed and moving bed technologies, which utilise a dry sorbent to reduce SO2 emissions in a flue gas stream in a dedicated reaction chamber, are categorised as dry scrubbers. In the circulating fluid bed (CFB) dry scrubber process, hydrated lime is injected directly into the CFB reactor. Water is also injected into the bed to obtain an operation close to the adiabatic saturation temperature. The process is easy to maintain and operate because it does not require high-maintenance mechanical equipment such as abrasion-resistant slurry pumps, water atomisers or sludge dewatering devices.


The formation of NOX can be controlled by modifying the operational and design parameters of the combustion process (primary measures), through the use of low-NOX burners with other combustion modifications, such as low excess air (LEA) firing, over-fire air, or flue gas recirculation for boiler plants and the use of dry low-NOX combustors for combustion turbines (burning natural gas).

Burner optimisation is usually the first method used to control NOX formation. Optimisation is achieved by modifying boiler operating conditions. In the excess air control procedure, minimising the air (oxygen) flow to the fuel during the initial stages of combustion leads to reduced NOX formation. As the oxygen level is reduced, combustion may become incomplete and the amount of unburned carbon in the ash may increase. Reducing the oxygen in the primary zones to very low amounts (< 1 per cent) can also lead to high levels of carbon monoxide. These changes can result in a reduction in boiler efficiency, slagging, corrosion and have a counteractive overall impact on boiler performance.

Fine-tuning the boiler settings include mill balancing, adjusting air registers, air and coal flow balancing, tuning firing configuration and improving the plant control system.

Low-NOX burners are designed to control fuel and air mixing in each burner in order to create larger and more branched flames. Peak flame temperature is thereby reduced, and results in less NOX formation. The improved flame structure also reduces the amount of oxygen available in the hottest part of the flame thus improving burner efficiency. Combustion, reduction and burnout are achieved in three stages within a conventional low-NOX burner. In the initial stage, combustion occurs in a fuel-rich, oxygen-deficient zone where NOX is formed. A reducing atmosphere follows where hydrocarbons are formed which react with the already formed NOX. In the third stage, internal air staging completes the combustion but may result in additional NOX formation. This, however, can be minimised by completing the combustion in an air lean environment.

Apart from primary measures, an SCR system can be used for coal-fired plants or an SNCR system for a fluidised bed boiler. In SNCR systems, a reagent is injected into the flue gas in the furnace within an appropriate temperature window. NOX emissions can be reduced by 30-50 per cent. The NOX and the reagent (ammonia or urea) react to form nitrogen and water. A typical SNCR system consists of reagent storage, multi-level reagent injection equipment, and associated control instrumentation. SNCR reagent storage and handling systems are similar to those for SCR systems. However, because of higher stoichiometric ratios, both ammonia and urea SNCR processes require three or four times as much reagent as SCR systems to achieve similar NOX reductions.

The temperature window for efficient SNCR operation typically occurs between 900 °C and 1,100 °C depending on the reagent and condition of SNCR operation. When the reaction temperature increases over 1000 °C, the NOX removal rate decreases due to thermal decomposition of ammonia. Meanwhile, the NOX reduction rate decreases below 1,000 °C and ammonia slip may increase. The optimum temperature window generally occurs somewhere in the steam generator and convective heat transfer areas. The longer the reagent is in the optimum temperature window, the better the NOX reduction.

PM control

During coal combustion, the mineral matter (inorganic impurities) is converted to ash. Part of the ash is discharged from the bottom of the furnace as bottom ash. The particles suspended in the flue gas are known as fly ash. Fly ash constitutes the PM matter, which enters the particulate control device.

The technologies that are used to control PM emissions from coal combustion are electrostatic precipitators (ESPs), fabric filters (baghouses), wet particulate scrubbers, mechanical/inertial collectors (cyclones/multicyclones), etc. The quantity and characteristics of the fly ash and particle size distribution depend on the coal mineral matter content, combustion system, and boiler operating conditions.

The combustion technique mainly determines the particle size distribution in the fly ash and hence the final particulate emissions. Common combustion systems in pulverised coal firing include dry bottom boilers, wall (front, opposed) and corner (tangential) burners, and wet bottom cyclone furnaces. In dry bottom boilers, 10-20 per cent of the ash is discharged as dry bottom ash. In wet bottom boilers, 50-60 per cent of the ash is discharged at the bottom of the boiler as slag.


The deadline to meet the new environment norms is different for different power plants but all plants are supposed to comply with rules by December 2022. As gencos evaluate and deploy various emission technologies, boiler, turbine and generator manufacturers and technology providers can help in their efforts to identify techniques and solutions that can contribute to plants becoming more environmentally sustainable.


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