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Inertia’s new frontier

As the amount of traditional inertia on our grid systems decreases with the shift to inverter-based resources like wind and solar photovoltaics (PV), system operators are increasingly seeking carbon-free alternatives for stabilising frequency

New rapid response technologies mean less inertia is required


STABILISING FORCE
Rotating masses in power plants provide grids with inertia to cushion sudden changes in frequency ALL ABOUT SPEED
The more quickly you are able to react to changes in frequency, the less inertia is needed KEY QUOTE
Today we can run smaller systems fully based on power electronics so they can simulate the behaviour of synchronous generators and respond just as quickly


Since June 2021, two repurposed turbines at a former gas-fired power station in Deeside, Wales, have been providing inertia and other services to Great Britain’s power system. Now fuelled by electricity rather than by gas, the turbines are helping to increase the stability of the grid and paving the way for the addition of more renewable energy capacity. In power systems, inertia has traditionally been provided by the rotating parts of large conventional gas, coal, nuclear and hydroelectric generators all spinning at the same frequency as the grid—roughly 50 Hertz in Europe and 60 Hertz in the US—and known as synchronous generators. When a large power plant drops offline, the rotating masses at the remaining power plants release kinetic energy, temporarily making up for the lost generator, slowing down the change in frequency and giving grid operators a bit more time to restore balance in electricity supply and demand. Asynchronous generators like solar photovoltaics (PV), wind and battery storage use inverters and power electronics to interface with the grid and so lack the inherent inertia of conventional generation. All else being equal, a reduction in the number of synchronous generators online will lead to faster changes in grid frequency in the event of a sudden drop in generation, increasing the likelihood of under-frequency load shedding, blackouts and damage to electrical equipment. GREEN INERTIA Deeside’s gas turbines were among assets awarded a total of £328 million in six-year, zero-megawatt contracts for green” inertia and other grid stability services by National Grid Electric System Operator (ESO), the UKs transmission system operator, in 2020 as part of the first phase of its Stability Pathfinder programme. The contracts are part of a toolkit that will enable the ESO to reliably operate the grid with 100% carbon-free energy in 2025 whenever possible. In Scotland, the Cruachan pumped hydroelectric storage plant was also awarded a contract in that first round. The remaining contracts, including that for the Deeside facility, involve synchronous condensers—rotating machines long-used for voltage support—that are combined with flywheels to boost the inertia. National Grid ESO says this new method of securing inertia is both cleaner and cheaper than that previously employed, which has generally consisted of paying wind farm operators to curtail output and natural gas plants to ramp up. LESS INERTIA Smaller, isolated grids with high shares of renewable energy have had to deal with the issue of declining inertia levels first. Alongside the UK, grid operators in Ireland, Australia and the states of Hawaii and Texas in the United States are among those at the forefront in seeking solutions for low-inertia situations. Larger grids have more inertia, but they don’t need more inertia,” says Paul Denholm of the National Renewable Energy Laboratory (NREL), the US Department of Energy’s research institute for renewable energy and energy efficiency. In April 2022, Irish grid operator EirGrid announced it had increased the limit for variable renewable generation on the grid to 75% from a previous 70% and from 50% in 2011. It will now begin work on increasing the figure to 95% by 2030 in order to achieve Ireland’s renewable energy target. Starting in 2023, EirGrid intends to begin securing its own low-carbon inertia sources through a competitive procurement process, with the first contracts expected to go into effect in 2026. Meanwhile, in Texas the instantaneous penetration of wind and solar power generation has reached 69% of electricity demand. The Electric Reliability Council of Texas (ERCOT), the state’s independent system operator, has been monitoring inertia in its control room since 2016 and is prepared to step in by increasing synchronous generators online and curtailing renewables if needed whenever inertia approaches the critical level, which is currently quantified at 100 gigawatt-seconds (GW•s), notes Julia Matevosyan, formerly with ERCOT and now at Energy Systems Integration Group (ESIG), a non-profit organisation. Inertia may vary throughout the day and year. In Texas it is generally lowest at night-time in the spring or autumn, when wind production is high and power demand is low. The amount of inertia needed on a system is a function of the potential loss of the largest online power source. In Texas, this is equivalent to the 2805 megawatts (MW) of capacity provided by its two operating nuclear power plants. In the UK, it is represented by the North Sea Link, the country’s 1400 MW undersea interconnector with Norway. GRID-FORMING VS GRID-FOLLOWING National Grid ESO is looking ahead to 2035, when it must be able to reliability operate on 100% carbon-free energy all the time. In April 2022 it assigned a second round of ten-year contracts worth £323 million to provide green inertia and improve short circuit levels (SCL)—the amount of current that flows on the system in a fault—at sites in Scotland, where wind capacity is increasing sharply and nuclear power is set to be decommissioned. The contracts will go into effect in 2024 and were split evenly between synchronous condensers with flywheels and grid-forming inverters with battery storage. The ESO expects to make its assessment of bids for a third round of inertia and other stability services covering England and Wales before the end of 2022. We are technologically agnostic and it all comes down to what delivers,” says Julian Leslie of National Grid ESO. As opposed to traditional grid-following inverters, which sense and follow” the frequency and voltage signal on the grid, grid-forming inverters can help to establish and maintain frequency and voltage. Inverter-based resources, such as wind and solar projects, with grid-forming inverters have black start capabilities and contribute to the stability of the grid. [They can] act and feel like a conventional power plant,” says Leslie. While grid-forming inverters are widely used on microgrids, they have yet to be implemented in larger power systems. Following the loss of a major power generator on the grid, the response of grid-forming inverters is nearly instantaneous”, providing additional active power in about five milliseconds, says Matevosyan of ESIG. While this response is not inertia in the traditional sense, it is equivalent to the inertial response from synchronous machines in terms of the impact on the grid, she adds. URGENT CHALLENGE Today we can run smaller systems fully based on power electronics so they can simulate the behaviour of synchronous generators and respond just as quickly. Usually, these are owned and operated by one owner, while public power systems are much bigger and have multiple actors,” states Jochen Kreusel of Hitachi Energy, a Swiss-based electrical infrastructure provider. The European Union’s 40% renewables target for 2030 will require about 65% of the bloc’s electricity generated by renewable sources. Kreusel believes that one of the most urgent challenges, if these ambitious targets are to be achieved, is to establish the common standards and network codes for the development of grid-forming inverters to operate on a large-scale basis. It was done once for existing power plants and now it needs to be done for the world of electronics. What is different now is that power generation is much more distributed,” he says. In the UK, the award of contracts for grid-forming inverters comes after minimum standards were defined in the grid code. Leslie says National Grid ESO solved the chicken-and-egg problem” involving requirements and capabilities by working closely with industry players over a period of five years. [Initially,] they didn’t know what we needed and we didn’t know what they could provide.” Leslie expects that the establishment of grid code specifications will bring in more competition and players. FULLY RENEWABLE Hawaii aims to generate 100% of its power from renewable energy by 2045. To help achieve that goal, the vertically-integrated utility Hawaiian Electric has begun procuring grid-forming battery storage, which it notes is a more advanced technology than grid-forming inverters in combination with wind or solar PV. Hawaiian Electric has also indicated it could explore the use of synchronous condensers as a supporting technology. One major project in the state involves Kapolei Energy Storage facility (KES), a joint venture between Hawaiian Electric and utility-scale storage developer Plus Power that is currently under construction. The capacity of the facility will stand at 185 megawatts-565 megawatt-hours and will comprise 158 storage units provided by US-based technology firm Tesla. With both grid-following and grid-forming functionalities, including black start capabilities, KES will make it possible to decommission Hawaii’s last remaining coal plant. The Australian Energy Market Operator (AEMO) is studying how it could procure inertia. In Southern Australia, AEMO is turning to both synchronous condensers and grid-forming batteries as it prepares for a system without any fossil fuel-based power plants. The installation of four synchronous condensers has allowed it to cut the need for gas-fired generation significantly while a number of battery projects boast grid-forming capabilities. Initial desktop studies for grid formation and grid reference show [the South Australia] system could be theoretically capable of holding together’ without synchronous generators,” AEMO wrote in a presentation to shareholders in March 2022. MEASURING INERTIA Measuring the level of inertia on a power grid was once an unnecessary task given the prevalence of synchronous generators but with levels decreasing, it has become more important to grid operators. Alongside securing new inertia sources National Grid ESO has also been fine-tuning the way it measures inertia. The ESO has invested £7.5 million in an ultracapacitor built by Reactive Technologies, a UK clean technology company. Deployed in Teesside, it will directly measure inertia by sending pulses of power throughout the grid and mapping any deviations in inertia and frequency levels. Elsewhere, the ESO has also invested in an inertia measuring and forecasting tool developed by GE Grid Solutions, the transmission subsidiary of US conglomerate GE, which is being deployed across the whole grid and will also provide real-time indications on inertia levels. These measurement systems will capture the contribution to inertia not only from generation but also from loads such as industrial motors, helping to increase their precision. Inertia from loads pales to that from power generation, notes NRELs Denholm, but is also decreasing. ALL ABOUT SPEED Many system operators already have tools in place to reduce the need for inertia in the first place before stepping in to find replacements. Inertia is all about speed,” says Denholm. The more inertia you have, the more time you have to react. The more quickly you are able to react, the less inertia you need.” With grid-forming inverters not yet widespread, fast frequency response is the first line of defence against decreasing levels of inertia and something that power electronics-based generation can do better than synchronous generators, says Matevosyan. While synchronous generators can respond as soon as the frequency change is detected it normally takes 15 to 20 seconds to reach full response. With power electronics-based generation, frequency response is a function of controls and the full response can be quick as one-quarter of a second,” Matevosyan adds. Inverter-based resources can provide fast frequency response by operating below maximum output, allowing them leeway to rapidly increase production when frequency declines are detected. This is similar to conventional generators providing primary frequency response, which also must also operate below full production in order to be able to have space to ramp up. Load management can also be a source of fast frequency response. In the ERCOT system, for instance, when frequency goes below certain levels, industrial power users that have signed up to provide this service are automatically disconnected. ROTATING MASS While wind turbines are rotating machines and have inertia, the turbine speed is decoupled from the grid frequency and inertia cannot be provided in the traditional sense. However, modern wind turbines can be designed to provide fast frequency response services to the grid by temporarily increasing active power beyond the available power from the wind. Control systems sense and respond to changes in frequency by extracting kinetic energy stores in the rotating parts of turbines, that is the blades and generator rotor. As is the case with inertia for synchronous generators, however, the release of kinetic energy slows down the turbines, which then require a recovery period to get back to full speed. When it comes to exploiting the inertia of wind turbines, Canadian grid operator Hydro-Quebec has led the way, changing its grid code in 2006 to require new wind turbines to provide what it calls synthetic inertia” resulting in the installation of the first compliant turbines in 2011. In Ireland, wind turbines with inertia emulation can receive contracts to provide both fast frequency response and primary operating reserve. IMPORTANT FOR EVERYONE National Grid ESO is also working to lower its inertia requirements through fast frequency response, dynamic containment—a fast-acting post-fault service to contain frequency deviations—and other measures. It is aiming to bring inertia requirement from a current 140 gigavolt ampere seconds (GVAs) to below 100 GVAs. Leslie believes the ESO is well-positioned to meet future low-inertia challenges, as it now has both conventional ways of responding to declines in inertia alongside grid-forming inverter specifications in its grid code. Other countries may soon need to leapfrog advances made in the UK and other frontrunners. We are an island and our frequency is much more volatile than in mainland Europe, so we have a harder challenge to make sure the system is safe and secure,” says Leslie, but even the large intercontinental grids will have to decarbonise and they will have to think of inertia as well.” •


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Heather O’Brian