India has come a long way from the power shortage situation in the past to the current power surplus situation. With a large interconnected grid (meeting peak load of 160 GW) as well as the increasing penetration of variable renewable energy, there is a need for surplus capacity or reserves to be available with system operators for emergencies (such as a sudden rise in load or unscheduled shutting down of any unit. Reserves are important for secure, reliable and efficient system operations. With surplus power now available, it has become feasible to maintain a reserve. However, appropriate mechanisms need to be put in place to manage these reserves at all levels.
At present, primary and tertiary controls are in place through the governor mode of operation mandated for generators by the Indian Electricity Grid Code and the Reserves Regulation Ancillary Services (RRAS) respectively. In the latest development, secondary control is proposed to be implemented through automatic generation control (AGC). Essentially, AGC delivers reserve power to bring back the frequency and the area interchange schedules to their target values and restores the delivered primary control reserves.
The Central Electricity Regulatory Commission (CERC), in its October 13, 2015 order on the roadmap for operationalising spinning reserves, had directed the Power System Operation Corporation (POSOCO) to submit a detailed report on operationalising reserves. After several rounds of consultations, in July 2017, POSOCO published a detailed modus operandi on the operationalisation of spinning reserves for the implementation of AGC. Prior to this, a pilot AGC project was undertaken at NTPC’s Dadri Stage II (comprising two units of 490 MW). The pilot yielded the desired results during a mock test conducted recently. Based on these results, full-scale implementation of secondary control through AGC is feasible and it can be rolled out in two to three years.
Generation reserve basics
Reserves and their control can be classified into three – primary, secondary and tertiary. Primary reserve is defined as the maximum quantum of power that will instantaneously come into service in the event of a sudden generation loss in the system through governor action of the generator. It is at present organised through free or restricted governor mode of operation (FGMO/RGMO). The CERC’s roadmap mandates 4,000 MW of primary reserves distributed across generators to arrest any sudden frequency drop following the tripping of an ultra mega power project.
Secondary reserve is defined as the maximum quantum of power that can be activated through AGC to free the capacity engaged by the primary control. AGC is essentially a mechanism that automatically adjusts the generation of a control area to maintain its interchange schedule and its share of frequency response. This is done by maintaining the difference between the frequency control error and the net interchange error within an acceptable range. This difference is the area control error (ACE). It is necessary to define the ACE of each control area (region in the Indian context) based on the following formula:
ACE = DP + K x Df
DP = Actual net interchange (NIa) – scheduled net interchange (NIs) in MW
Df = Actual frequency (Fa) – scheduled frequency (FS) in Hz
K = Frequency bias of control area in MW per Hz, usually with a negative sign.
To begin with, the value of K could be taken based on the past trend of regional frequency response characteristics (FRCs). Usually, it is equal to the frequency response obligation (FRO) of each control area. FRO is defined as the minimum frequency response that a control area has to provide in the event of any frequency deviation. Accurate values of DP necessitate proper availability of real-time data. The CERC has mandated secondary reserves in each region to the tune of the largest-sized generating unit in the region (aggregating 3,623 MW).
Tertiary reserve is defined as the quantum of power that can be activated (mainly by rescheduling) to restore an adequate secondary reserve. This has been implemented through the RRAS launched by the National Load Despatch Centre (NLDC) in 2016. The CERC set the mark-up for participation in the regulation of RRAS at 50 paise per kWh. There are close to 50 RRAS providers aggregating 52,500 MW and the experience so far in relieving congestion has been encouraging.
Pilot experience at NTPC Dadri
In May 2016, a team from POSOCO, Power Grid Corporation of India Limited and Siemens visited NTPC Dadri to explore the ground-level requirements. In October 2016, NTPC invited bids from four supervisory control and data acquisition (SCADA) vendors – Alstom, Open Systems International, Siemens and ABB – for the execution of an AGC pilot project. The bids were opened on November 30, 2016 and the letter of award was issued to Siemens in January 2017. The contract price was Rs 8.87 million and the implementation time was four months.
The contract included the installation of AGC hardware and software at the NLDC, along with its integration between the SCADA/energy management system (EMS) at the NLDC and the distributed control system (DCS) of the generating station. The requirements at the generating station (at a cost of Rs 6 million) entailed the installation of control logic software as well as hardware, including a control logic unit at the plant and its integration with the station’s existing DCS. As per the contract, the control logic unit is capable of developing algorithms that help in calculating the unit level set point based on the signal (DP of the plant) received from the AGC at the NLDC and the vital parameters of the station. The unit is programmed for closed loop operation at the local level, and to restrict DP signals below predefined limits at the plant level. Cybersecurity is ensured through appropriate router configurations, firewalls and antivirus software. Further, communication between the nearest substation (Dadri HVDC) and the control room of the generating station where the DCS system is installed has been established through the laying of fibre optic (FO) cable and two sets of galvanised iron pipes. This last component is the most costly, accounting for 75 per cent of the total cost at the plant end.
For operationalising the AGC, the set points are calculated on the basis of static data configured in the AGC system, unit real-time data parameters, interchanges considered for the AGC system and unit regulating ranges. These set points are communicated over IEC 104 protocol to the plant operation area, where the set points are transferred to the control logic unit and further processed to be transferred to the unit DCS. The AGC system is able to exchange data with the NLDC SCADA/EMS and control logic unit. It also collects analog and digital data from the unit DCS system through the control logic unit.
For the mock exercise conducted on June 29, 2017, the northern region (NR)-scaled ACE was considered as the entire region’s ACE would have been too high for the Dadri station alone. Hence, an ACE of 50 MW was fixed. The ramp rate limit was set at 10 MW per minute. The AGC software processed the changes in set point with this ramp rate limit. The set point was sent every two seconds to the plant. Temporary instantaneous deviations in adhering to the ramp rate by the control mechanism were observed for 5 per cent of the time. The NLDC AGC, NTPC digital control system and the natural boiler/ turbine response smoothened this out. The two-minute average ramp rate of the set point was 100 per cent below the fixed limit. Overall, the plant reported smooth operation during the test.
In terms of the effect of the RGMO, it was observed that there is interaction between the AGC (where the signal passes through coordinated boiler and turbine controls and reaches the turbine governor) and the RGMO (where the signal is given directly to the turbine governor) if the grid frequency is out of the dead band (+/-0.03 Hz), which is frequently the case at present. The interaction will be minimised if the frequency stabilises at 50 Hz.
For commercial settlement of the AGC services offered by Dadri Stage II, three aspects have to be considered. The first is factoring AGC signals while evaluating deviations, because energy produced due to AGC signals should not be considered as deviation from the schedule. Deviations would be settled as per the existing deviation settlement mechanism (DSM) regulations. The second aspect is compensation for the extra energy spent or saved. For AGC MWh generated during a time block, variable charges will be paid to Dadri from the NR DSM pool and vice versa for AGC MWh reduced. The final aspect is the incentive for providing the secondary regulation service, which is equal to 50 paise per kWh, the mark-up payable to NTPC Dadri from the NR DSM pool.
Pan-Indian implementation plan
POSOCO’s modus operandi proposes the implementation of AGC in two phases. In Phase I, all interstate generating stations (ISGSs) whose tariff is regulated/adopted by the CERC will be covered. For these plants, the tariff rate and ancillary services framework for settlement are available, and these face fewer communication issues. Therefore, implementation may be dispute-free. However, the availability of the full quantum of reserves as mandated by the CERC may be an issue.
In Phase II, all the regional entity-generating stations scheduled by the regional load despatch centre (RLDC) would be covered. However, currently RLDCs do not demand declared capability from these generating stations. Some IPPs have part-PPA (power purchase agreement) and part-merchant contracts. The tariff for these generators has to be agreed upon a priori for secondary control participation of these generators. The declared capability and schedule have to be obtained from these generators for reserve estimation.
Drawing from the RRAS experience, POSOCO has proposed that the AGC may also be brought under ancillary services. The main difference between the existing fast tertiary control and the proposed secondary control is that an elaborate technical set-up at the NLDC and plant level would be needed for AGC. The time frame for the operation of RRAS is in the range of a few time blocks (³15 minutes) and that of AGC would be in the range of a few minutes. Tertiary control is at present being implemented on all thermal ISGSs whose tariff is determined or adopted by the CERC and to add other regional entity generators into the ambit, scheduling software has to be changed and other protocols have to be established. To add a generator to the AGC, necessary hardware/software infrastructure is needed at the plant level as well as the EMS at the NLDC. Both products are required for better system operation.
Key requirements for implementing AGC
POSOCO lists five mandatory requirements for regional entities to be equipped under secondary control. These are as follows:
- The regional entity will bear the cost of secondary control hardware at the plant end, including the cost of the FO cable from the plant control room to the nearest communication node.
- The regional entity will share declared capability and schedule like ISGS on a day-ahead basis with the RLDCs.
- The payment for the energy and incentive will be as decided by the CERC.
- The generating units will have working control systems for the turbine, boiler and governor. The governor response plots/graphs of past incidents are required to be submitted to the RLDC.
- A wideband communication node within a radius of 30-40 km of the plant would be required to communicate with the nearest RLDC.
In India, the AGC software at the NLDC would essentially be the equivalent of five separate AGC software running at the same control centre, which would be a first of its kind globally. In terms of manpower requirements at the NLDC, an eight-member team must be trained in SCADA, AGC software operation and system operation for managing real-time AGC operations. Additionally, six personnel are required – two each for accounting and settlement, and monitoring AGC performance; handling AGC cybersecurity/IT issues; and undertaking major software changes, adding new generators and performing post-despatch analysis.
The EMS is under upgradation and is expected to be in place by 2019-20. This includes both AGC software and hardware. Overall, by 2020-21, India will be ready with full-fledged AGC to take on the challenge of high renewable energy penetration.
AGC project cost and payment for reserves
The cost of equipment at the plant level (all 150 regional entity stations including hydro and nuclear identified by POSOCO) for implementing AGC would be of the order of Rs 5 million-Rs 10 million per plant, depending on the fibre optic cabling within the plant.
There is no explicit opportunity cost payment for AGC as the beneficiaries pay the fixed costs for these plants. Only mark-up costs in paise per kWh could be paid to the generators under the AGC, based on the five-minute average MWh regulation as derived from the AGC server at the NLDC.
POSOCO estimates the payments for secondary regulation through AGC on account of mark-up in the range of Rs 3.8 million to Rs 20 million per day at the rate of 50 paise per kWh. This is based on its calculations for July 1, 2017 when frequency remained in the 49.9 Hz-50.05 Hz band for nearly 85 per cent of the time and an average frequency of 50 Hz with standard deviation of less than 0.05 Hz.
The payment was calculated in two ways. In the first method, an all-India system is considered as a single balancing area and corrected only for frequency, considering 8,000 MW per Hz FRC. The cost works out to Rs 3.8 million per day (with 4,208 MWh regulation up and 3,289 MWh regulation down through AGC). In the second method, where each region is considered as a balancing area, the mark-up payment is Rs 20 million per day.
It is expected that since both regulation up and regulation down would be required on a daily basis, the net energy should be close to zero on an annual basis. However, the payments on account of mark-up would depend mainly on the forecast errors for load as well as renewable energy resources, besides any contingency in respect of conventional generation.
If a lot of reserve energy gets consumed (continuous regulation up signal by AGC), it is a direct signal that base case scheduling has to be revised in that particular region and, if needed, the units under reserve shutdown (RSD) must be brought online where reserve energy is being consumed. Conversely, if the AGC signal is always regulation down, the base case scheduling has to be revised in that particular region and, if needed, units can be taken under RSD.
The way forward
On November 21, 2017, the CERC held a hearing on NLDC’s petition for commissioning of the AGC pilot project between NLDC and NTPC Dadri Stage II. The regulator is expected to publish the related order shortly for operationalising the pilot as well as giving direction on full-scale implementation. Once implemented, AGC would enhance grid stability, especially given the large-scale renewable energy coming on board. Although undertaking AGC would have cost implications for power plant developers owing to the setting up of necessary infrastructure, this could be fully recovered within a year through AGC regulation services, assuming that most of the power plants are covered through the FO network of the central transmission utility. POSOCO recommends that renewable energy as well as pumped storage plants should also be wired for AGC. This would be useful for regulation in cases of extreme despatch scenarios when secondary reserves run out and/or in emergencies if renewable energy has to be curtailed.
Going forward, AGC can be extended to the intra-state level as well as to cross-border interconnections. Differential compensation can also be considered based on the performance of generators (fast ramping and ability to track AGC signals). Regulatory intervention is required for mandatory provision of primary response and gradual phasing out of RGMO. A related petition is pending with the CERC. Notwithstanding the implementation challenges, the application of AGC is a landmark development in India’s power system operation. The pilot project is the first step in this direction and full-scale execution is expected over the next two to three years.