Emission Control: Retrofitting could reduce the environmental impact of TPPs

Retrofitting could reduce the environmental impact of TPPs

The thermal power generation industry has been retrofitting thermal power plant (TPP) units with pollution control technologies in order to comply with the emission limits notified by the Ministry of Environment, Forest and Climate Change (MoEFCC) in December 2015. The aim is to reduce the emission of major pollutants such as suspended particulate matter (SPM), sulphur oxide, nitrogen oxide and mercury. In order to meet the standards, new emission control systems, including flue gas desulphurisation (FGD) and electrostatic precipitators (ESPs), needed to be installed at power plants.

In the national capital region (NCR), pollution control equipment at TPPs needs to be installed by 2019. Plants in other critically polluted areas and places with high population density will have to meet the SOx and SPM norms by 2021. The final timeline for all thermal power plants is 2022 as per the phased implementation plan prepared by the Central Electricity Authority (CEA) in consultation with regional power committees and the MoP, and submitted to the MoEFCC in 2017. As per the revised plan, FGD systems will be installed at 414 units with an aggregate installed capacity of about 161 GW and ESPs will be upgraded in 231 units aggregating 66 GW. In December 2017, the Central Pollution Control Board issued directives to TPPs to ensure compliance as per the revised plan.

Overview of emission norms

Apart from tightening the existing standards for SPM emissions, the ministry has issued new standards pertaining to nitrogen oxide (NOx) and SOx. The TPPs have been classified into three categories – units installed before December 31, 2003, after 2003 till December 31, 2016, and after December 31, 2016. Different emission standards have been set for the three categories. For TPP units older than 2003, the norms are relatively relaxed. The SOx and mercury emission standards are more stringent for plants with a higher capacity (more than 500 MW).

Different technologies have been identified to control different types of emissions. For meeting the PM norms, plants are required to retrofit/upgrade/install ESPs. For meeting the SOx emission norms, FGDs will have to be installed. FGD options include wet, semi-dry and dry sorbent injection. Wet FGD can be based on limestone, ammonia or seawater. In India, there are 10-15 competent players in the FGD market. The optimum time required for FGD installation is around 24 months, with an additional five to six months required for commissioning. For reducing NOx emissions, plants need to install selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR) technologies. The globally available SCR system for NOx control is, however, not been tested for Indian coal that has high ash content. Currently, eight SCR and two SNCR pilot tests are being executed by NTPC across eight vendors to assess the performance of these systems using Indian coal. The tests are likely to be completed by May 2019.

One feature that distinguishes NOx control from SO2 or SPM control is the unique opportunity to achieve it at source. TPPs can achieve NOx emission reduction through pre-combustion modifications in boilers, and install low NOx burners and over-fire air systems. However, developers have expressed concern regarding the deployment of SCR and SNCR equipment, especially in older plants that face layout/space constraints.

Focus on SOx emissions

The new norms lay emphasis on SOx reduction. The existing levels of SOx emissions, which are currently as high as 1,000-1,200 mg per Nm3, have to be brought down to 600 mg per Nm3 for units that are 15-25 years old. For a five to seven year old unit, the emission level needs to be reduced to 300 mg per Nm3, and the latest commissioned units need to limit their SOx emissions to 100 mg per Nm3.

To this end, the first FGD system has been installed at NTPC’s 500 MW Vindhyachal Stage V project. The FGD system is based on wet limestone technology, and has been able to achieve SOx emission of 80-90 mg per Nm3 from an inlet of 1,200 mg per Nm3. The other projects where wet FGD technology is being implemented include the 1,320 MW Solapur super thermal power plant, the 1,320 MW Stage II of the Tanda project, the 500 MW Unchahar project and the 1,320 MW Meja power project. Meanwhile, for the Dadri plant, NTPC has opted for the DSI system.

The majority of DeSOx systems adopted worldwide are based on wet lime stone technology. Wet limestone FGD is best suited for large units (500 MW and above) and those that require high removal efficiency. For newer units, too, it is considered to be the best available technology. However, the technology needs to be assessed on a case-by-case basis, depending on the sulphur content of coal, efficiency requirements, capital and operating costs, location of plants, suppliers, availability costs of reagent, and the supply chain and disposal/sale of the by-product. Seawater FGDs are suitable for coastal plants and open water cycle-based plants. Ammonia-based FGD is suited for units using coal with high sulphur content. However, it has limited suppliers, requires a high amount of ammonia and poses safety hazards. Dry and semi-dry FGDs are mainly used for units with low plant loads. However, they have lower efficiency.

Issues and concerns

One of the major reasons for the slow implementation of FGD and other emission control systems has been the requirement for additional capital and operating costs. While this issue has been addressed to a certain extent, with the cost being allowed as a pass-through in tariff, the plant owners have been facing difficulties in arranging funds. Banks and other financial institutions have been reluctant to fund these investments due to the high level of stress in the sector.

The unavailability of good quality limestone, one of the key raw materials, poses another major challenge. The CEA is in discussions with the Ministry of Mines regarding meeting the limestone requirement at power plants. When FGD system would be deployed at all plants, around 38 million tonnes of gypsum would be generated every year. The disposal/utilisation of such a large quantity of gypsum is another area of concern.

The disposal of water effluents from FGD systems, which have high chloride, is also a challenge. A solution to this is treating the water through an RO (reverse osmosis) system to reach a zero liquid discharge condition in line with the water consumption norms.

Further, there have been variations in FGD tender specifications. To this end, in December 2017, the CEA issued standard technical specifications for retrofitting wet limestone-based FGD systems in a typical 2×500 MW coal-based power plant. It is also in the process of finalising specifications for seawater-based FGD systems.

The way forward  

According to the CEA, FGD systems have been commissioned for only 1,820 MW of capacity as of September 2018. These are Tata Power’s 500 MW Trombay thermal power station (TPS) and CLP India’s 2×660 MW Mahatma Gandhi TPS, which is currently under renovation and maintenance (R&M). Meanwhile, bids have been awarded for NTPC’S 27 thermal power units aggregating 13,540 MW of capacity. NTPC is leading the way in FGD implementation. Further, tenders have been issued for 66,640 MW of capacity across 162 units and tender specifications have been finalised for another 89,720 MW across 211 units. Apart from this, feasibility studies have been completed for 118 units aggregating 39,990 MW.

While this shows significant progress with regard to the installation of FGD systems at power plants, the current ordering trend still does not support the CPCB timelines. The state gencos and private players, which are all still at early stages of implementation, need to catch up. Meanwhile, the government needs to regularly track the progress in project implementation made by plant owners.