Growth Impact

Grid integration in a 100S-60W scenario

The share of renewable energy sources, primarily wind and solar, is poised to grow significantly in the Indian power system. The government has set a target of 175 GW of installed renewable capacity by 2022, including 60 GW of wind and 100 GW of solar, up from an installed capacity of 29 GW wind and 9 GW solar at the beginning of 2017. Whether the target is achievable or not will be determined by market and policy-led forces; however, a key question that arises is what would be the operational impact of meeting these targets and what actions can be taken for effective integration of renewables. At low levels, integrating wind and solar energy into the grid can be achieved relatively easily. But at higher levels, wind and solar generation can present some challenges to grid operations because of the additional variability and uncertainty it brings to the power system.

To answer this question, the Power System Operation Corporation, the National Renewable Energy Laboratory and the Lawrence Berkeley National Laboratory carried out a study under a programme called Greening the Grid, a joint initiative by India’s Ministry of Power and the US Agency for International Development. The results can be used to make informed policy and regulatory decisions that support system flexibility and renewable investment. The following is a brief summary of the study and its recommendations…

How India’s power system would operate with 100 GW solar and 60 GW wind

  • Power system balancing with 100 GW of solar and 60 GW of wind is achievable at 15-minute operational timescales with minimal renewable energy curtailment. This capacity would generate 370 TWh of power annually, accounting for 22 per cent share of total electricity consumption in India, reaching an instantaneous peak of 54 per cent across the country. The annual renewable energy curtailment (assuming sufficient in-state transmission) would be 1.4 per cent, consistent with experiences in other countries with the same level of renewable penetration.
  •  The study adopted five renewable energy growth scenarios, each of which defines one possible future electric power system with projections of electricity demand (load), generation and transmission. These are the No New RE, 20S-50W, 100S-60W, 60S-100W and 150S-100W scenarios. In the 100S-60W scenario, the fuel requirements for coal and gas would fall 20 per cent and 32 per cent respectively, and CO2 emissions would fall 21 per cent (280 million tonnes) as compared to the No New RE scenario. As a result, plant load factors for coal would decrease from 63 per cent to 50 per cent with nearly 20 GW that is never economical to start.
  • Changes to operational practices can reduce the operating costs of a power system and bring down renewable curtailment, but are not essential for integrating 160 GW of renewable energy. Scheduling and despatch that is optimised at the regional level rather than at the state level can increase the efficiency of thermal power plant operations and reduce annual operating costs by 2.8 per cent, or Rs 63 billion (approximately $980 million). In addition to improving access to least-cost generation, coordination amongst states helps reduce the number of coal plants at part load, providing a greater operational range to the remaining committed coal plants to lower their generation output when renewable energy generation is high. National coordination further increases cost savings to about 3.5 per cent and reduces curtailment of renewable power to 0.9 per cent.
  • Reducing the minimum generation level of large thermal plants is the biggest driver for reducing renewable energy curtailment. Thus, decreasing the minimum generation level of all coal plants, from 70 per cent at present to 55 per cent of rated capacity (in line with the Central Electricity Regulatory Commission regulations), would reduce renewable energy curtailment from 3.5 per cent to 1.4 per cent and annual operating costs by 0.9 per cent, or Rs 20 billion. Reducing the minimum generation level further to 40 per cent would reduce renewable energy curtailment to 0.76 per cent, with negligible decreases in annual operating costs. Meanwhile, if only centrally owned plants achieve a 55 per cent minimum generation level while state-controlled plants remain at 70 per cent, renewable curtailment would be 2.4 per cent.
  • The peak system-wide one-hour up-ramp would increase 27 per cent as compared to a system with no new renewables, to almost 32 GW, up from 25 GW. This ramp rate can be met if all generating stations exploit their inherent ramping capability. Aggregated nationally, for 56 hours of the year, system-wide up-ramps exceed 25 GW per hour, greater than any ramp requirement in the No New RE scenario, and peak at almost 32 GW per hour. The current generation fleet is shown to successfully respond to these ramp events within the operating assumptions. No significant change was seen in either the production cost or renewable energy curtailment when coal generation ramp rates were made less flexible in the simulations, although this study assumes a similar load shape for 2022 as that prevailing today. A significant change in the load shape could affect the net load ramp rate. Five-minute scheduling and despatch has been demonstrated elsewhere to better handle ramping, if required at a later stage.
  • Copper plate sensitivity delivers 4.7 per cent savings and 0.13 per cent renewable energy curtailment. The copper plate here represents a transmission system with no constraints or barriers to scheduling. Although this is not a physically plausible scenario, it provides insights into the maximum achievable savings if all transmission and market constraints are relaxed. Such a scenario reduces renewable energy curtailment to 0.13 per cent and production costs by 4.7 per cent. In comparison, scheduling and despatch optimised at the regional level and with transmission constraints deliver over half of these savings. Nationally coordinated despatch combined with an additional 25 per cent interregional transmission capacity delivers 84 per cent of the savings compared to the idealised copper plate.
  • Batteries insignificantly impact emissions and the total cost of generation. They do reduce curtailment from 1.4 per cent to 1.1 per cent, but the value of this curtailment is offset by the batteries’ efficiency losses during operation. In the 100S-60W scenario, 2.5 GW of batteries (75 per cent efficient) reduce renewable energy curtailment by 1.2 TWh annually but lose 2 TWh annually due to inefficiencies. Also, their impact on the total cost of generation is insignificant because there is little change in the overall generation mix. Batteries could be economically desirable for renewable energy integration for grid services that are outside the scope of the study (for example, frequency regulation, capacity value and local transmission congestion).
  • Retiring 46 GW of coal capacity (20 per cent of the total installed coal capacity) does not adversely affect system flexibility, assuming adequate in-state transmission. Retiring coal plants that operate at less than 15 per cent of their capacity annually has almost no effect on system operations.

 

Different pathways to meeting the renewable energy targets and beyond

  • A wind-dominated system would have a higher renewable energy penetration rate and require less thermal fleet flexibility. Compared to the official renewable energy targets, a scenario with more wind (100 GW wind, 60 GW solar) would help achieve a higher annual renewable energy penetration rate (26 per cent compared to 22 per cent) due to the higher capacity factors of wind, reduce CO2 emissions by an additional 6.1 per cent, and entail lower renewable energy curtailment (1 per cent compared to 1.4 per cent). Owing to its relatively less variable net load profile, the higher wind scenario would create fewer conditions requiring thermal plant flexibility.
  • A 250 GW renewable energy system could achieve India’s Nationally Determined Contribution target, but a 16 per cent annual renewable energy curtailment in the southern region would likely signal the need for modified strategies. To identify a more viable pathway towards 250 GW, additional studies can be undertaken to evaluate the trade-off between increasing system flexibility and locating more renewable energy capacity in other regions.
  • Potential planning and policy actions would support renewable energy integration.
  • Coordination of renewable energy generation and transmission at the state level would ensure sufficient in-state transmission.
  • Creation of regulatory or policy guidelines to support institutionalisation of cost-optimised capacity expansion planning. Creation and maintenance of a nationwide model that helps optimise generation and transmission build-outs, which can then be used to make informed investment decisions and renewable energy policies.
  • Evaluating options for enhanced coordination of scheduling and despatch amongst states and regions.
  • Establishing comprehensive regulations at the central and state levels regarding the flexibility of conventional generators, including the minimum generation level, ramp rate, and minimum uptime and downtime.
  • Developing a new tariff structure that moves away from focusing on energy delivery. Agreements can specify various performance criteria, such as ramping, specified start-up and shutdown times, minimum generation levels, along with notification times and performance objectives that achieve the flexibility goals.
  • Revising policy/regulatory-level guidelines to utilise the full capability of hydro and pumped hydro stations. Suitable incentive mechanisms can encourage the operation of hydro and pumped hydro depending on system requirements.
  • Using the regulatory platform for order despatch based on production costs, supplementary software may be required to identify economic scheduling and despatch that consider the combined effects of conventional and renewable variable costs, and transmission congestion and losses, among other factors.
  • Creating model power purchase agreements for renewable energy that move away from must-run status and employ alternative approaches to limit financial risks, such as annual caps on curtailed hours.
  • Detailed, model-based planning, including capacity expansion and production cost modelling would help in achieving more ambitious renewable energy levels. Regulatory guidelines may be issued to make it mandatory for stakeholders to provide data required to perform such studies.
  • Equipping all states with the latest, state-of-the-art load forecasting facilities. In addition, equipping renewable energy-rich states with state-of-the-art renewable energy forecasting tools. Further, building capacity of all system operators in order to develop their in-house capability to create and customise such tools in the future.

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