Operations and maintenance (O&M) of thermal power plants (TPPs) is crucial for efficiency, safety and environmental compliance. Emission control is a key aspect of O&M, involving retrofits and modifications to technologies such as electrostatic precipitators, flue gas desulphurisation and selective catalytic reduction to minimise pollutants like PM, SOX and NOX. Reducing emissions from coal-based TPPs is crucial for a successful energy transition. While renewable energy sources are growing rapidly, coal-based plants will continue to play a key role in ensuring grid stability in the near future, providing reliable power until energy storage solutions become more accessible and cost-effective. Therefore, it is essential for these plants to minimise their environmental impact while they remain in operation. As electricity demand rises and environmental regulations become more stringent, continuous innovation in pollution control technologies and environmental management systems will become increasingly essential.
SOX emissions
On December 7, 2015, the Ministry of Environment, Forest and Climate Change (MoEFCC) introduced stricter environmental standards for coal-based TPPs under the Environment (Protection) Act, 1986 for SOX, NOX and
PM emissions.
In September 2022, the MoEFCC extended the deadlines for TPPs to implement sulphur oxide (SOX) reduction equipment based on their location. Category A plants (within 10 km of Delhi-NCR and cities with over 1 million population) were given a deadline of December 31, 2024, Category B plants (within 10 km of critically polluted areas or non-attainment cities) had a deadline of December 31, 2025, while Category C plants had time until December 31, 2026.
In December 2024, another three-year extension was issued. Category A plants have been given a deadline of December 31, 2027, Category B December 31, 2028, and Category C December 31, 2029. For retiring units, the deadline has been extended from December 31, 2027 to December 31, 2030.
Progress in meeting these norms has been slow. According to the Central Electricity Authority (CEA), as of January 2025, flue gas desulphurisation (FGD) systems are planned for 537 coal-based units or 204.16 GW of capacity, of which installation has been completed in 49 units (25.59 GW). In the NCR region, around 35 units are required to install FGD units, of which installation has been done in 13 units so far.
Meanwhile, contracts/letters of award have been awarded for 211 units or 91.88 GW of capacity. Bids have been opened for 47 units (16.19 GW) and notice inviting tenders has been issued for 85 units (26.53 GW).
Recently, in February 2025, the CEA issued an advisory regarding FGD technology selection by TPPs. The advisory outlines key factors in the selection of technology, including SOX removal efficiency, unit size, remaining plant life, geographical location, potential secondary pollution, by-product management and water consumption. It advises utilities to conduct comprehensive techno-economic feasibility studies and life cycle cost analyses before finalising FGD technology. Plant-specific factors to consider include coal quality, sulphur content, space constraints, reagent availability and the environmental impact of the chosen technology.
Gencos have also been facing significant challenges in deploying FGD systems due to a lack of concessional financing, high capital costs, space and infrastructure constraints and delays in tariff adjustments. A recent NITI Aayog study notes that the current cost of FGD systems is approximately Rs 14 million per MW. As per CEA data estimates, around Rs 1,470 billion of capital investment will be required for FGD installation across the remaining coal-based power plants.
Meanwhile, concerns have been raised regarding the impact of FGDs on carbon emissions. A CEA report titled “Review Report on New SOX Norms” examined the environmental impact of FGD systems, highlighting additional pollution concerns associated with the mining and transportation of limestone and gypsum. The report noted that running FGD systems increases auxiliary power consumption by approximately 1 per cent, which requires the burning of more coal, further elevating CO2 emissions. The report also noted that while FGD implementation is expected to reduce around 5.54 million tonnes of SOX annually, it is projected to cause an immediate rise of approximately 14.33 million tonnes per annum in CO2 emissions. It also recommends conducting further studies to evaluate the long-term implications of these installations.
NITI Aayog, through CSIR-NEERI, Nagpur, has conducted a study titled “Analysis of Historical Ambient Air Quality Data Across India for Developing a Decision Support System”. The aim of the study is to analyse SO2 emissions from coal-based TPPs using data from the Continuous Ambient Air Quality Monitoring System and the Online Continuous Emission Monitoring System. It employs air pollutant emission dispersion modelling with a prognostic model to develop a decision support system. The study’s recommendations are under review by the Ministry of Environment, Forest and Climate Change.
NOX reduction
As per the MoEFCC guidelines, TPPs commissioned between 2003 and 2016 must adhere to a less stringent limit of 450 mg per cubic metre (Nm³), while plants commissioned after 2017 face a stricter limit of 100 mg per Nm³. Older plants built before December 2003 are allowed up to 600 mg per Nm³. These regulations will be enforced in phases, with progressively stricter compliance deadlines.
There are several technology options to regulate NOx emissions. In-combustion technologies regulate the combustion process to reduce thermal NOx formation, offering low-cost, easy-to-install solutions. India’s NOx emission standards for coal-fired power plants prioritise the adoption of cost-effective primary control methods such as advanced low-NOx burners (LNBs) and overfire air (OFA) systems. These technologies not only ensure compliance with the 450 mg per Nm³ limit but also have the potential to achieve lower emissions, below 300 mg per Nm³.
As of January 2025, according to the CEA, combustion modification was completed in 441 units totalling approximately 156 GW. Additionally, combustion modification is currently in progress for 14 units, accounting for around 5.4 GW. Furthermore, modifications are planned for 76 units, representing a capacity of 18.7 GW.
LNBs are also widely used to burn fuel in a limited oxygen zone to create an environment that allows unburnt hydrocarbons to react with NOx, converting it into nitrogen gas. By controlling the initial combustion stage, LNBs reduce peak flame temperatures, further minimising NOx formation. OFA systems control oxygen availability near burners, creating a fuel-rich zone to limit NOx formation. The combustion air is introduced in stages: partly near the burners and the rest higher in the furnace at lower temperatures. OFA systems can reduce NOx emissions by 20-45 per cent, with some variations achieving even higher reductions. When combined with LNBs, OFA systems provide a synergistic approach to NOx reduction.
Other technology options for NOx reduction are active control measures, allowing manual adjustments to boiler settings to optimise performance. It provides a cost-effective solution for coal plants, enabling NOx emission reductions of 15-35 per cent. This approach is especially suitable for boilers commissioned between 2003 and 2016, which are likely already equipped with LNBs and OFA systems. Another solution is flue gas recirculation, which involves diverting a portion of the hot exhaust gas back into the furnace, reducing combustion temperatures and oxygen availability.
Post-combustion control systems such as selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) capture or chemically convert NOx into harmless nitrogen gas after the flue gas exits the boiler. SNCR reduces NOx by injecting ammonia or urea into the furnace when the flue gas temperature is between 900 °C and 1,100 °C. Successful SNCR operation requires adequate residence time and proper mixing of the reducing agent. Plasma-assisted SNCR combines traditional SNCR with plasma technology, improving temperature distribution and enhancing the reaction for more effective NOx reduction. SCR injects ammonia into the hot exhaust gas after it exits the economiser and before it enters the air preheater. A catalyst speeds up the chemical reaction between ammonia and NOx, converting them into nitrogen gas and water vapour. The process is most efficient when flue gas temperatures are in the range of 300-400 °C.
At NTPC, various de-NOx techniques and modifications have been applied across 49 units, with additional implementation under way for one unit.
PM control
Fly ash, a by-product of coal combustion, constitutes a significant portion of PM (about 26 per cent of PM10 and PM2.5). As temperatures rise, fly ash can become airborne and contaminate air and water due to its content of heavy metals and other harmful substances.
There are several technologies available for PM control. Electrostatic precipitators (ESPs) are widely used in TPPs to control PM emissions by electrically charging ash particles in flue gas. ESPs are highly efficient, capturing over 99.99 per cent of particles ranging from 0.01 to 100 micrometres.
As per the CEA, as of January 2025, around 441 units (or 174.2 GW of capacity) comply with the PM norms. Around 69 units or 14.21 GW capacity have ESP upgrades planned. Another 21 units or 5.2 GW of capacity has ESP upgradation under progress. Further, 58 units or 16.17 GW of capacity expects to be PM compliant post FGD installation.
Reducing carbon emissions
Gencos are taking initiatives to invest in technologies such as carbon capture and storage to reduce emissions by capturing CO2 from power generation and securely storing it underground to prevent atmospheric release. NTPC Limited has already commissioned a pilot carbon capture project with a 20 tonnes per day capacity at the Vindhyachal thermal power station.
NETRA, the research and development wing of NTPC, has also developed an indigenous catalyst for hydrogenation of CO2 to methanol in collaboration with the Indian Institute of Petroleum, Dehradun. Long-duration quantitative and qualitative performance assessments of the catalyst are being carried out in a specially designed 10 kg per day methanol pilot plant. The purity of methanol produced by this catalyst is more than 99 per cent.
The way forward
Overall, coal-based power generation is expected to remain the backbone of India’s power generation over the next 7-10 years even as renewable energy expands. Going forward, addressing concerns over environmental compliance timelines and policy uncertainty will be crucial for gencos to make informed investment decisions and optimise operational planning.
Akanksha Chandrakar