Slow Compliance

Challenges in meeting emission control requirements

India is expected to achieve a total installed power generation capacity of 830 GW by 2030, half of which will be coal based. Coal-fired power plants, however, are big contributors to emissions of sulphur oxide (SOx), nitrogen oxide (NOx), suspended particulate matter (SPM) and mercury. In this context, the Ministry of Environment, Forest and Climate Change (MoEFCC) issued environmental norms in December 2015, aimed at reducing the emission of SPM, SOx, NOx and mercury by thermal power plants (TPPs).

However, compliance has remained slow. The industry has been seeking an extension of the 2022 deadline because of the Covid-19 pandemic and the import ban. Recently, the Ministry of Power (MoP) wrote to the MoEFCC seeking an extension of two years up to 2024, for the installation of emission control equipment on account of equipment import curbs from China as well as supply disruptions, owing to Covid-19.

In addition, the Central Electricity Autho-rity (CEA) came out with a report last month suggesting that TPPs can install emission control equipment in phases, with immediate installation required only in areas with high levels of sulphur dioxide (SO2). For instance, flue gas desulphurisation (FGD) systems would be installed on a priority basis in areas where SO2 concentrations are above 40 micrograms per cubic metre (mg per m3) (24-hour average). Areas with lower concentrations of the pollutant may not require emission control equipment in the near future.

A look at the various technologies being deployed for emission control and the progress in implementation so far…

SOx control

FGD involves the removal of SO2 from flue gas. By far, the most commonly used FGD technology is 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 dry scrubbing technologies.

As of November 2020, the total capacity for monitoring FGD implementation is approximately 170 GW and the number of units, after including the newly commissioned ones, stands at 448. So far, FGD systems have been commissioned for 2,160 MW of capacity across six units in NTPC’s 4×210 MW Dadri TPP and CLP India’s 2×660 MW Mahatma Gandhi TPP. Meanwhile, bids have been awarded for 155 other thermal units aggregating 68.66 GW of capacity. Further, tenders have been issued for 130 GW of capacity across 324 units. Tender specifications have been finalised for another 142 GW of capacity across 361 units. Apart from this, feasibility studies have been completed for 432 units, totalling 163.5 GW and have begun for 444 units, totalling 168 GW.

As per the CEA’s new report, based on satellite imagery reports, SO2 concentrations have been found to be high in Odisha, Jharkhand, Chhattisgarh, Maharashtra, Tamil Nadu and Gujarat. It has been recommended that in the first phase, emission control equipment should be installed in areas where SO2 levels are higher than 40 mg per m3 (level I). About 1,460 MW of capacity falls in this level at present (although data has not been received from all TPPs). Subsequently, a year after the completion of the first phase and upon analysing the effectiveness of the control equipment, plants located in areas where ambient SO2 levels are higher than 30 mg per m3 (level II) can take up FGD installation, identified as 5,048 MW. Meanwhile, TPPs located in areas where ambient SO2 levels are lower than 30 mg per m3 (levels III, IV and V, identifying 290 MW, 17,890 MW and 11,020 MW, respectively) need not take any corrective measures at present.

NOx control

There are various technologies available that can help in curtailing NOx emissions. These include selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) systems, and over fire air (OFA) systems and low NOx burners (LNBs).

SCR technology injects ammonia into flue gas to reduce NOx in the presence of a catalyst. SNCR is a simpler post-combustion control system, which can help achieve reliable NOx reductions ranging from 25 to 50 per cent, and can be installed within a regular plant outage schedule. SNCR systems do not require a catalyst, but their effectiveness is dependent upon sufficient reaction time within a narrow flue gas temperature window and adequate mixing of the reagent with flue gas. Other non-catalytic technologies include LNB and OFA systems. OFA and LNB are already being used in India, but they are capable of reducing NOx emissions of only up to 600 mg per Nm3.

As per the 2015 norms, the NOx emission limit for TPPs installed before December 31, 2003 was set at 600 mg per Nm3; for TPPs installed after January 1, 2004 and up to December 31, 2016, at 300 mg per Nm3; and for TPPs installed from January 2017 onwards, the emission limit was 100 mg per Nm3. In July 2020, the Supreme Court allowed relaxation of NOx norms for TPPs installed between January 1, 2004 and December 31, 2016 from 300 to 450 mg per Nm3. The MoP had proposed revising these norms as TPPs were unable to meet the existing limit at varying load conditions. The CPCB monitored emissions at seven of NTPC’s power plants for a specific period and results were found to be in line with the MoP’s observations.

With the change in NOx limits, TPPs commissioned between 2004 and 2006 will not be required to implement advanced de-NOx technologies such as SCR or SNCR; as a NOx emission level of 450 mg per Nm3 could be achieved by combustion modification. The NOx limits for TPPs commissioned after January 1, 2017 at 100 to 450 mg per Nm3 are also under review.

PM emission control

The emission control norms notified by the MoEFCC in December 2015 have considerably lowered the PM emission limits for TPPs. The PM limit is 100 mg per Nm3 for projects commissioned before 2003, 50 mg per Nm3 for those commissioned between 2003 and 2016, and 30 mg per Nm3 for TPPs commissioned in 2017 and beyond.

PM emissions can be controlled pre-combustion, in-combustion and post-combustion in coal-based power plants. Pre-combustion control can be achieved by selecting the right type of coal and by washing the coal, while in-combustion control is carried out by optimising combustion and injecting sorbents into the flame zone. Post-combustion can be controlled by the installation of electrostatic precipitators (ESPs) and fabric or baghouse filters. An ESP is a device that electrostatically separates particles from the flue gas stream while imposing minimal pressure loss on the stream. Most of the TPPs in the country have already installed ESPs. However, with the narrowing of PM emission norms, there are concerns regarding the efficacy and operational performance of the existing ESPs.

As per the CEA, 220 units aggregating 63 GW are required to be compliant with the new norms with the installation/ upgradation of ESPs by 2022. Of these, about 30 units (12.2 GW) are expected to upgrade their ESP systems between 2018 and 2020. Further, 97 units (23.5 GW) and 93 units (27.7 GW) will complete the upgradation of ESPs in 2021 and 2022 respectively.

Water consumption norms

The environmental norms required all existing TPPs to achieve a specific water consumption of 3.5 m3 per MWh by December 2017. Further, plants with once-through cooling were required to install cooling towers. Another gazette notification in January 2016 mandated the use of treated sewage water from sewage treatment plants if it is available within a 50 km radius of a TPP. TPPs set up after January 2017, however, are required to operate at a water consumption level of 2.5 m3 per MWh and achieve zero discharge. In October 2017, these norms were eased and are now allowed to utilise up to 20 per cent more water than that permitted earlier.

TPPs require water for various uses such as cooling, fly ash disposal, and for condensers and demineralisation plants. According to a NITI Aayog study, TPPs, on an average, require 5-7 m3 of water per MWh, and are currently consuming at least 16.8 million m3 of water per day at 80 per cent load factor, equivalent to the per capita water requirement of about 20 per cent of the country’s population. However, water consumption can be optimised by conducting water audits and ensuring efficient usage, and by treating and recycling water. Further, implementation of zero liquid discharge (ZLD) systems can ensure that the discharged water is recycled back to the plant. While ZLD systems have higher operating costs, investments are justified by a high recovery of water (90-95 per cent) and several by-products from salt.

The various systems used to reduce water footprint in ash handling include minimising the ash production, ash water recirculation system (which requires water recovery from the ash pond for reuse in the system), dry fly ash handling system and high concentration slurry disposal system.


While the deadline for extension of air emission norms is currently under consideration, in September 2020, the government reportedly identified 32 units across 12 TPPs aggregating 5,019 MW, which will have to be shut down as they have not submitted any plan to adhere to the prescribed emission control norms. These units are over 20 years old and the majority of them are run by state governments, while some are operated by the government-owned Damodar Valley Corporation (Bokaro and Durgapur) and CESC Limited (Titagarh).

Meanwhile, in October 2020, the CPCB extended the deadline for implementing environment pollution control measures by TPPs operating in Haryana. The Yamunanagar TPP is required to ensure the installation of  ESPs and FGD system by October 2021 and December 2021 respectively, while December 2022 is the deadline for controlling nitrogen emissions. The Panipat TPP is required to complete ESP installation in Units 7 and 8 by February 2021 and December 2021 and FGD implementation can be completed up to December 2021. For Aravali Thermal Power Company’s Jharli (NTPC) plant and CLP India’s Rajiv Gandhi TPP, deadlines have been extended till December 2021.

Overall, the installation of emission control equipment in the existing TPPs is challenging, and with greater integration of renewables, thermal gencos are already facing the brunt in terms of low load operation and flexibilisation requirements.

However, this does not undermine the fact that TPPs need to cap their emissions and promote sustainability. The Central Electricity Regulatory Commission (CERC) has already recognised the revised environmental norms as a “change in law” event, and is also planning to amend its tariff regulations for 2019-24 in order to incorporate the cost of emission control systems in tariff calculations. In September 2020, the CERC also floated a staff paper on the mechanism for compensation for competitively bid thermal generating stations for change in law, on account of compliance with the revised emission standards of the MoEFCC, where power purchase agreements do not have an explicit provision for such compensation.

Going forward, greater cooperation would be needed at the policy and industry levels to expedite the installation of emission control systems as well as balance environment and industry concerns.

Nikita Gupta


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