The Indian power sector has been witnessing several changes in the past few years – a change in the generation mix with a sharp increase in the share of intermittent renewable energy, the development of an organised power market, the creation of a single and synchronous national grid, and a significant increase in the number of grid participants. All these factors have put enormous pressure on system operators to maintain grid stability and reliability. System operators need to be adequately empowered to deal with fluctuations and maintain grid frequency within the prescribed range. In March 2017, the Central Electricity Regulatory Commission (CERC) declared the national reference frequency at 50 hertz (Hz) and formed a high-level expert group to suggest measures to bring power system operations closer to this frequency.
The expert group, headed by A.S. Bakshi, member, CERC, along with representatives from the Central Electricity Authority (CEA), Power System Operation Corporation of India (POSOCO) and Power Grid Corporation of India Limited, released its report in two volumes in November 2017 and January 2018. The first volume focuses on reviewing the Indian and global grid operation experience as well as the existing operational frequency band in India for safe, secure and reliable system operation. The second volume reviews the principles of the deviation settlement mechanism rates, including their linkage with frequency in light of the emerging market realities.
There is a sense of urgency in implementing a whole range of power system operation reforms. According to S.K. Soonee, adviser, POSOCO, “If we have to integrate 175 GW by 2022, time is running out. We have to start now, as there are so many things to do. We have to work on building system inertia, implement primary response, introduce secondary and fast tertiary controls, reduce settlement times, and bring in a real-time market.” Power Line presents the key highlights of the findings and recommendations of the first volume of the report…
Indian and global grid operation experience
Currently, the primary frequency control in India is mandated (through restricted governor mode of operation [RGMO]), but needs to be enforced. A pilot project for the implementation of secondary frequency control through automatic generation control (AGC) has been implemented in the northern region. The present ancillary services implementation through reserves regulation ancillary services (RRAS) falls in the category of tertiary frequency control.
There has been a gradual improvement in the frequency profile over the years. As a result, the underfrequency load shedding relays have not operated in day-to-day normal operations (last operated on May 24, 2015 due to the separation of the southern region grid from the rest of the grid). The DF/DT (rate of change of frequency) relays have operated only in the case of a major contingency (last operated on March 12, 2014 due to tripping of all lines evacuating from the 4 GW Mundra ultra mega power plant [UMPP]).
There has been a marked improvement in the frequency profile since the introduction of RRAS in April 2016. The average frequency remains very close to 50 Hz in a day. The frequency variation index has improved to 0.03-0.05 with the frequency remaining within the Indian Electricity Grid Code (IEGC) frequency band for 75-80 per cent of the time. Having gained two-year experience of the ancillary services market, the time is now right to review the existing mechanism and introduce new ancillary services.
The report studies the international scenario in detail with regard to frequency control for North America (North American Electric Reliability Corporation prescribed-reliability standards) and Continental Europe (CE) (European Network of Transmission System Operators for Electricity’s network code on load frequency control and reserves).
The Indian power system (which operates in the 49.9-50.05 Hz band) has been compared with the CE power system (49.95-50.05 Hz). The frequency for CE remains close to 50 Hz for a large part of the day. Automatic controls such as AGC facilitate frequency restoration within the above range within 30-40 seconds in CE as against over two minutes in India, indicating huge scope for improvement in grid frequency quality.
Based on the Indian experience and international practices, the expert group has made important recommendations in 12 areas to help bring Indian power system operations closer to 50 Hz.
Frequency control as a continuum in terms of time horizon: The report recommends a schematic of reserves, balancing and frequency control continuum (see accompanying figure) and that this schematic should be incorporated in the IEGC through an amendment. The figure indicates the frequency control mechanisms in a continuum starting from a few seconds to a time period of less than an hour. Any persistent deviations beyond this time horizon will be owing to issues related to forecasting, unit commitment, scheduling and despatch.
Reference frequency for the purpose of control: While the CERC has declared the target frequency at 50 Hz for the purpose of frequency control, it suggests that the same must be notified in the IEGC.
Monitoring inertia of the system and inertial response: The inertia in the power system has improved with the formation of the national grid (with a peak demand of 160 GW), resulting in substantially reduced frequency fluctuations. This situation is, however, expected to reverse due to an increase in static silicon loads and a reduction in the rotating mass of conventional machines due to greater penetration of solar and wind generation in the system. By 2022 (assuming 175 GW of renewable capacity), instantaneous penetration of renewable energy in MW could reach as high as 54 per cent. This will affect the system inertia and the frequency fall following a large contingency before the primary response effect comes into play.
The report recommends that POSOCO could start monitoring the inertia of the system on a real-time basis, at the regional and all-India level, using the typical inertia values of machines initially, followed by more technological solutions. This will help establish a baseline, which is monitored for low net load periods. Simulation studies could be carried out to assess the inertia and any adverse impact on stability due to low inertia. There is a need for suitable provisions for stipulating minimum inertia in the grid code and CEA standards in the near future besides the provision of synthetic inertia from renewable resources.
Primary control: Primary response from generating units has been mandated as per the IEGC in the form of RGMO since May 2010. However, it has not been implemented in the true spirit and has been interpreted differently by the generators. The key purpose of primary control is to resist any change in frequency in any direction automatically without any manual intervention.
In this regard, the expert group suggests that RGMO must be phased out by April 1, 2018 and replaced with the term “speed control with droop” as is used internationally. Further, the dead band of ±0.03 Hz must be gradually phased out. This could be done voluntarily initially. Further, the CEA must mandate a primary response from renewable energy sources through the notification of proper provisions in grid connectivity standards. The CERC must define the performance metrics in the test procedures for testing the primary control periodically.
Additional parameters to be notified in the IEGC: In addition to incorporating the national reference frequency in the IEGC, the report recommends the notification of four more values. This includes the permissible frequency band to be further tightened to 49.95-50.05 Hz by 2020 when secondary and tertiary reserves would be operationalised in substantial quantum both at the interstate and the intra-state level. The reference contingency for primary response must be specified as the outage at a 4,000 MW UMPP. Following the above reference contingency, the minimum frequency (nadir value) as well as the quasi-state frequency value after primary response must be notified as 49.5 Hz and 49.8 Hz respectively. The IEGC must also specify the standards for frequency recording and archival at the Regional Load Despatch Centre/National Load Despatch Centre (RLDC/NLDC) level.
FRC: The frequency response characteristic (FRC) is calculated as MW generation or load lost divided by change in frequency. The FRC value is derived through recording numerous incidents in the grid. There has been a gradual improvement in all-India FRC over the past two years, from 6,000 MW per Hz in 2015 to 9,000 MW per Hz in 2017. This is, however, much lower as compared to systems like the Western Interconnection in the US (comparable to India in terms of system size), which has recorded an FRC of 20,000 MW per Hz despite a lower obligation under its reliability standard.
The RLDCs and the NLDC have been recommended to continue the practice of computing FRC as is being done currently for each control area, region and at the all-India level. In addition, the same should be worked out at the nadir frequency at the all-India and regional levels to track the impact of inertia. Although the report refrains from prescribing a target FRC for now, the control area-wise FRC and percentage of ideal response must be tracked for each event. The report suggests that cases where the generator response is less than 40 per cent of the ideal response must be reported to the CERC for levy of penalty.
Roadmap for operationalising reserves: The report directs POSOCO to implement its October 2015 order on the roadmap for operationalising spinning reserves at the earliest so that secondary and tertiary reserves are available for frequency control.
Secondary control through AGC: In line with the above CERC order, in July 2017, POSOCO published the detailed modus operandi for the implementation of AGC. Prior to this, a pilot AGC project was undertaken at NTPC’s Dadri Stage II project in Uttar Prasesh. The pilot project yielded the desired results during a mock test conducted in June 2017. In December 2017, a CERC order allowed the operation of the AGC project at Dadri and ordered similar pilots to be undertaken in each region. With respect to the latter, four NTPC stations at Simhadri (in the southern region), Mauda (western region), Barh (eastern region) and Bongaigaon (north-eastern region) have been identified. Meanwhile, the Dadri pilot project is under continuous operation since January 4, 2018 in line with the CERC order. Full-scale implementation of secondary control through AGC is expected to take place in the next two to three years.
The expert group recommends AGC implementation at the earliest. The performance metrics for AGC payments could be introduced once sufficient experience is gained through the pilot at Dadri. Further, AGC must be implemented at the intra-state level through appropriate regulations by the SERCs, particularly for larger states. In this regard, under the United States Agency for International Development’s Greening the Grid programme, an AGC pilot is under consideration for some of Karnataka Power Corporation Limited’s hydro power units.
Slow tertiary control through RRAS: The expert group recommends expanding the ambit of RRAS at the interstate level (which is under the CERC’s regulatory control) and making refinements based on the experience so far, the introduction of performance metrics for mark-up payments for such services, as well as the introduction of such ancillary services at the intra-state level through regulations by the respective SERCs. This would necessitate implementing the scheduling, accounting, metering and settlement of transactions mechanism at the intra-state level. Work is under way on this front with almost all the state load despatch centres (SLDCs) on board.
Fast tertiary control at the interstate level: The expert group suggests that fast tertiary services through RRAS using hydro could be introduced at the interstate level initially. Hydropower stations, which can provide a faster response than the currently effective slow tertiary RRAS (where the impact is felt only after 20-30 minutes), have not been utilised for RRAS so far.
Monitoring of ACE: With the implementation of all the above measures, frequency is expected to be within the IEGC band for almost 100 per cent of the time. However, for a time horizon beyond one hour, forecasting and scheduling are vital. Hence, monitoring each control area performance is also important. Area control error (ACE) is essentially the difference between the frequency control error (KxDf) and the net interchange error (DP) where K is the frequency bias of the control area, usually with a negative sign. The expert group recommends calculating and monitoring the ACE for each state control area, region as well as neighbouring countries. For calculation purposes, the bias could be set as 4 per cent of the area load per Hz, which could be reduced over time. The interstate and interregional tie-line values and frequency measurements must be updated within 10 seconds at the SLDCs, RLDCs and the NLDC. The ACE must cross zero value and change sign at least once every hour, which could be narrowed down to 30 minutes eventually. Persistent violation of this condition would render the utility liable for penalties. Another factor that could result in the imposition of penalties on the utility is if the 90th percentile value of overdrawals below 49.95 Hz and underdrawals above 50.05 Hz exceeds 150 MW on a monthly basis.
Time error: This is the difference between the time reported by a synchronous clock and the time reported by a reference synchronous clock. This error signifies the deviation of average frequency from reference frequency. Time error should be recorded at the NLDC level on a daily basis. The CERC will notify the standards for cumulative time error separately based on the experience gained and considering the cross-border interconnections.
The significance of monitoring the ACE can be appreciated by the fact that sustained non-reversal of sign change will lead to a large accumulation of time error. Both these indicate sustained deviations and non-adherence to the schedule, which are highly detrimental to secure grid operations and could result in grid failure.
The Indian power system is among the most complex in the world given its sheer size as well as synchronous operations as a single grid. It is also one of the most progressive systems in terms of adopting the latest available technologies and techniques in managing the grid securely and reliably in light of the dynamic power sector developments. This holds true at least at the interregional and interstate levels. However, several measures need to be taken to replicate this success at the intra-state level. The CERC, in collaboration with all stakeholders, is taking steps to ensure secure grid operations given the rapidly changing market scenario and the expected integration of huge renewable energy capacity. There are exciting times ahead for the Indian power system as it gears up for the introduction of new concepts and services at all levels of controls in a tighter frequency regime.