As renewable power displaces more and more coal, gas, and nuclear generation, electricity grids are losing the conventional power plants whose rotating masses have traditionally helped smooth over glitches in grid voltage and frequency. One solution is to keep old generators spinning in sync with the grid, even as the steam and gas turbines that once drove them are mothballed. Another emerging option will get a hearing next week at the 15th International Workshop on Large-Scale Integration of Wind Power in Vienna: synthetic inertia.
Synthetic inertia is achieved by reprogramming power inverters attached to wind turbines so that they emulate the behavior of synchronized spinning masses.
Montréal-based Hydro-Québec TransÉnergie, which was the first grid operator to mandate this capability from wind farms, will be sharing some of its first data on how Québec’s grid is responding to disruptive events such as powerline and power plant outages. “We have had a couple of events quite recently and have been able to see how much the inertia from the wind power plants was working,” says Noël Aubut, professional engineer for transmission system planning at Hydro-Québec.
The short answer is good, but not good enough to support massive wind power growth. Québec has about 3,300-MW of wind power today, but Canada’s wind industry is calling for 8,000-megawatts more by 2025. Turbine manufacturers are upping their synthetic inertia technology to pave the way.
Synthetic inertia is the latest step in a longstanding technology trend, according to Aubut, that has already transformed renewable generators from potential liabilities to power grid stability into substantial contributors to it. The first step, he says, was equipping renewables to remain solid and thus “not harm the grid” during times of grid instability. Modern wind and solar plants are designed to “ride-through” severe faults, such as short-circuit events that drop grid voltage to zero.
Recent ride-through trouble in Australia appears to be an anomaly. Nine Australian wind farms did shut down during a series of storm-induced faults, that blacked-out the state of South Australia in September, and Australia’s prime minister attacked renewable energy as a threat to energy security. However, an investigation by the Australian Energy Market Operator blamed errant wind farm control settings, and it says some operators have corrected them.
In fact, most wind and solar farms can do much more than just stick around during trouble. For example, most utility-scale installations—and even some residential rooftop solar systems—are designed to combat voltage sags on power grids. Their electronic inverters can detect brownouts and generate reactive power (AC whose current wave leads its voltage wave) to raise the grid voltage.
Synthetic inertia is about responded to crashing AC frequency, usually after the loss of a big power plant. When a big generator goes offline, it leaves the grid under-supplied. That will cause the AC frequency to fall.
Conventional power plants respond naturally and instantly to frequency dips because the momentum of their spinning turbines, synched to the grid, resist deceleration. This slows the frequency drop, buying precious seconds during which power reserves are mobilized to fill the supply gap.
Aubut says Hydro-Québec began setting requirements for synthetic inertia in 2005. Québec’s grid is, electrically speaking, North America’s smallest AC zone, with peak power demand under 40,000 MW. Losing a big power plant causes a steeper frequency drop on smaller grids, and more wind power threatened to limit the Québec operator’s defenses.
In 2005 the utility amended its grid code, requiring wind farms to pull their weight: it mandated that new wind turbines be capable of delivering a power boost equal to 6 percent of their rated capacity during low-frequency events. Manufacturers responded with synthetic inertia designs, and the first were installed in 2011. Today, inertia-compliant turbines from Germany’s Senvion Wind Energy Solutions and ENERCON account for two-thirds of Quebec’s wind capacity.
To emulate the inertial behavior of massive rotating equipment, a renewable generator must somehow find extra power quick. Québec’s wind turbines do so through a collaboration between the turbines’ solid-state power electronics and their moving parts. “When the wind turbines see an imbalance between load and generation that causes a frequency deviation on the system they’re able to … extract some kinetic energy that is stored in the rotating masses of the wind turbines,” explains Aubut.
During a December 2015 transformer failure that took more than 1,600-MW of power generation offline, synthetic inertia kicked in 126 MW of extra power to arrest the resulting frequency drop. Quebec’s AC frequency bottomed out at 59.1 hertz – well below its 60-hertz standard – but Aubut and his colleagues estimate that it would have dropped a further 0.1-0.2-hz without the synthetic inertia. And they estimate that this was roughly the same contribution that conventional power plants would have provided.
“If we had had only synchronous generation instead of wind with the same event and operating conditions, we’d have had about the same deviation,” says Aubut.
The trouble, says Aubut, is what happens after the frequency drop. In all but the strongest wind conditions providing synthetic inertia will slow a wind turbine’s rotor. Re-accelerating to optimal speed thereafter absorbs some of the wind power that the turbine can export to the grid. Data from ENERCON shows power reductions of up to 60 percent in some turbines.
This energy recovery phase delays the grid’s frequency recovery. After Québec’s December 2015 transformer event, for example, the system frequency flat-lined for several seconds at 59.4 Hz before additional power reserves could push it back to 60. Under different conditions, says Aubut, that post-inertia recovery could have actually caused a “double-dip” in system frequency, increasing the risk of triggering protective relays at substations and causing blackouts.
Hydro-Québec is revising its synthetic inertia to minimize the risk of a double-dip. It plans to limit power reduction during recovery to no more than 20 percent of a wind turbine’s capacity. Turbine manufacturers are already testing second-generation synthetic inertia systems that comply with the new standard.
ENERCON presented an upgraded synthetic inertia control scheme at last year’s Wind Integration Workshop. Whereas the first generation of ENERCON Inertia Emulation revved rotors back to their optimal speed as quickly as possible, the new scheme uses power estimation and closed-loop control to enable smooth and tunable re-acceleration.
Markus Fischer, ENERCON’s Montreal-based regional manager for grid integration, says the upgraded scheme showed “promising results” in tests on full scale turbines and commercial rollout is “expected to happen in the near future.” Retrofitting its first generation machines, he says, will require no added hardware.
Synthetic inertia requirements, meanwhile, may be spreading. Grid operators in Ontario and Brazil have already joined Hydro-Québec’s lead, and Fischer says the first harmonized grid code for European generators, which entered into force earlier this year, “opens the doors to European system operators to ask for inertial response from wind.”
This post was created for Energywise, IEEE Spectrum’s blog about the future of energy, climate, and the smart grid