Ensuring Compliance

Technologies being adopted by TPPs to meet the emission norms

The Ministry of Environment, Forest and Climate Change notified the new emission norms for air and water consumption in December 2015. For thermal power plants (TPPs), these norms imply significant investments in em­ission reduction technologies for particulate matter (PM), sulphur oxide (SOX) and nitrogen oxide (NOX). As per estimates, approximately 440 TPPs, whi­ch account for 166.5 GW of capacity, re­quire retrofitting with pollution control systems. A number of technologies su­ch as flue gas desulphurisation (FGD), se­lec­tive catalytic reduction (SCR) and se­lective non-catalytic reduction (SNCR) are currently being adopted by the ind­us­try to meet the norms.

Key emission control technologies


After the notification of the new emission norms, it has become necessary for several TPPs across the country to install FGD units to curtail the emission of SO2 from the stacks to comply with the above stipulated SO2 emission limits.

The SO2 emission norms are based upon the commissioning date and the capacity of the TPP. For example, for plants with generation capacity more than or equal to 500 MW, the SO2 concentration limit is 2,000 mg per Nm3 and for the plants with generation capacity less than 500 MW, the limit is 600 mg per Nm3.

There are two types of FGD processes – the dry and the wet FGD processes. The dry FGD process involves a dry scrubbing injection system where lime is used as a reagent to react and remove gaseous pollutants. The two most popular dry methods are the dry injection system and the spray drying system. The former injects dry hydrated lime directly into the flue gas duct, while the latter injects atomised lime slurry into a separate vessel.

The wet FGD process involves wet scrubbing, which uses alkaline-based slurry of lime to scrub gases. A shower of lime slurry is then sprayed into a flue gas scrubber, where the SO2 is absorbed into the spray and becomes a wet calcium sulphite. One by-product of that sulphite is that it can be converted into soluble gypsum. Wet scrubbing provides high efficiency sulphur dioxide removal capacity, in addition to reducing any scaling potential. For a regular coal-fired power plant, FGD can potentially improve 90 per cent or more SO2 from flue gases.

In the FGD market around the world, wet limestone scrubbing is the most prominent and widely used technology becau­se of the lower capital and operating expenditure involved in this and it leads to a by-product, which is marketable gypsum.

As per equipment manufacturers, a realistic time period for the implementation of a small-size semi-dry FGD system is about 24 months and for wet limestone scrubbing FGD, it is 30-36 months after receiving the contract. There is adequate domestic manufacturing capacity for major FGD components/subsystems in the country. However, due to factors like customer requirements or cost-competitiveness, some of the equipment/subsystems are procured indigenously or through imports. The level of imports may vary on a case-to-case basis.

The per MW cost of setting up an FGD system varies on a case-to-case basis, based on various factors such as project la­y­out, available land, sulphur content in input fuel, soil conditions and civil works requirement, local labour availability and multiplicity of units (project configuration). Typically, the per MW cost of FGD packages may vary from Rs 5 million to Rs 12 million per MW as per BHEL’s estimates. The cost of FGD implementation does not depend on the age of the TPP as it is dependent on factors such as project scope, layout, configuration/sizing of FGD and other contractual requirements.

However, there are a few challenges associated with this technology. Althou­gh India has the manufacturing capability of nearly 70 per cent FGD components, it still depends on imports from other countries as its manufacturing capacity is insufficient to cater to the huge surge in demand in a short period of time. The remaining 30 per cent of FGD components that are not manufactured in India must be imported. Due to import restrictions the price of equipment has increased, increasing the overall cost of the installation project. The pandemic-related supply chain disruptions have added to the woes.


Over-fire-air (OFA) systems and low NOX burners (LNBs) are the two primary technologies that are less expensive and can be executed much faster versus advanced control procedures. Most TPPs commissioned after 2000 already have some form of in-house combustion-based NOX control. Low NOX burners are designed to control fuel and air mixing at each burner in order to create larger and more branched flames. They reduce the peak flame temperature, resulting 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. LNBs can be combined with other primary measures such as OFA, reburning or flue gas recirculation. Plant experience shows that a combination of LNBs and other primary measures can help achieve up to 74 per cent NOX removal efficiency. Similarly, OFA and flue gas recirculation systems can optimise NOX generation in a cost-effective manner.

Secondary technologies like SCR and SNCR limit the production of NOX more effectively. For NOX reduction, SCR is one of the most effective methods of post-combustion NOX reduction. In this process, a catalyst is used to promote the reaction of ammonia and NOX to fo­rm nitrogen and water. Several different forms of ammonia like water solution of ammonia, ammonia dry gas, or urea, are used in the process. However, the form of ammonia can change the result of the entire process and make it safe or hazardous for the environment. Anhydrous ammonia or dry ammonia is very toxic and difficult to handle safely. Ammo­nia water solution is safer to store and deliver to the NOX abatement system but requires vaporisation. Urea is the safest of all reductants, but it needs to be thermally decomposed to ammonia to be used, which implies higher capital and operating costs. The SCR process has removal efficiency ranging from 90 per cent to 95 per cent, which can be further increased by using additional catalysts.

However, a major problem with these systems is that the arrangement for avai­lability, transportation, handling and st­o­ra­ge of such large quantities of ammonia is yet to be addressed by TPPs. An­other issue in SNCR technology is that TPPs have to maintain a sufficiently high temperature in the boiler for the effective disposal of NOX. NTPC has conducted pilot-based studies on SNCR and SCR technologies at seven stations by various SCR system suppliers and asse­ss­ed the technically viable emission limit after taking into consideration In­di­an coal. The results of the tests have been submitted to the Supreme Court.


Another key technology being adopted is electrostatic precipitator (ESP). It removes PM from gas streams with electrically charged particles that are attracted to collector plates embodying opposite charge. The collected particles are removed from collector plates as dry material or are washed from the plates with water. ESPs have an efficiency of greater than 99 per cent. On the flip side, ESP performance can be affected by particle resistivity, which can affect the deposition and removal of particles from the collection plates. The efficacy can also be affected by the temperature and moisture content of the flue gas, making it difficult to strike a balance.

Meanwhile, many gencos have taken ste­ps to reduce emissions other than in­s­talling pollution control systems. NTPC Limited started the practice of biomass co-firing in its plants. Residual crop burning by farmers in the winters causes severe air pollution in Delhi-NCR. NETRA came up with this alternative of co-firing of biomass in the existing coal-fired boilers, giving economic value to farm residue. Bio­mass is considered a “carbon-neutral” fuel and co-firing of biomass prevents air pollution and reduces carbon emissions from coal-fired plant. Biomass pellets are fed into identified bunkers. Th­en, the blend of biomass and coal is milled in the system and fired in the boiler, making it a much cleaner process.

The way forward

As of December 2022, only around 8,780 MW of thermal capacity, as against the total 211.5 GW, had FGD systems. Im­plementation issues, capex optimisation, derailed progress due to the pandemic and import restrictions have resulted in several deadline extensions for TPPs to install emission control systems, the third time in the past five years. The most recent notification extended the deadline for the TPPs till December 31, 2024 for plants within 10 km radius of the capital and other cities with a population of more than 1 million, while for non-attainment cities and for plants in the 10 km radius of critically polluted regions the deadline has been pushed to December 31, 2025. For the rest of the plants, the deadline stands at December 31, 2026. Overall, addressing issues pertaining to the availability of equipment, trained manpower and funding could accelerate the compliance of TPPs with the emission norms.