* Multiple contingencies occurred simultaneously (loss of generation from two major generators and lost of distributed generation totalling 1,400 MW) resulting in a drop in system frequency to 49.1 Hz
* Standby generation (frequency response reserve) was deployed, totaling 1,000 MW or the largest single generation contingency and began to arrest the system frequency decline
* Just as system frequency began to recover, a third contingency occurred resulting in the loss of a further 210 MW of generation. This caused system frequency to decline again to 48.8 Hz
* Load shedding kicked in as designed and dropped 5% of load to stabilize the system
The largest loss of generation was from Hornsea offshore wind farm. The wind farm should have rode through the system disturbance, but instead its control and protection systems rapidly curtailed active power generation in response to an undamped oscillation in the response of its voltage regulator through the disturbance.
Basically, the internal voltage of the Hornsea wind farm collector system dropped due to the voltage regulator oscillations (from 35 kV nominal to 20 kV), while active power generation remained the same. Power = current * voltage, so an overcurrent condition occurred and protection systems operated to prevent overload of the wind turbine generators.
Subsynchronous oscillations (SSO), i.e. oscillations at below power frequency (50 Hz), are a known issue in power system controls that can lead to unstable or unexpected consequences during system disturbances. The reduction in system inertia caused by the replacement of large synchronous machines with asynchronous generators as wind and solar replace conventional generators exacerbates the possibility of problematic SSO because there is less damping.
Nowadays, in North America, very specific modelling is done in design stage to identify the possibility for such behaviour and ensure that if present it is adequately damped. Some system operators, such as ERCOT (Texas), require this for new wind projects. I imagine that this major occurrence will led to revisions to modelling and grid code testing standards in the UK to protect against future incidents.
All in all, kudos to Ofgem, National Grid and all other participants for producing a thorough, public technical report in just about one month.
Sort of: what matters is that it was not an AC synchronous generator, like traditional thermal power plants. Wind and solar systems these days have fully digital AC-AC conversion systems which take the variable frequency multi phase output of the wind turbine(s) and turn it into standard three phase.
Turbine-generator systems have nice, simple behaviour in reponse to frequency drop: they act to maintain the frequency by transferring more energy from the shaft rotation to the generator. In the long run this slows the turbine down or triggers a throttle response, but over the few second period we're talking about the shaft speed is basically constant due to its own inertia.
The wind farm "saw" the rapid fluctuations in connection voltage, tried to compensate, and instead went into oscillation. This appears to have been a software bug:
> "During the incident, the
turbine controllers reacted incorrectly due to an insufficiently damped electrical resonance in the subsynchronous frequency range, so that the local Hornsea voltage dropped and the turbines shut
themselves down.
Orsted have since updated the control system software for the wind turbines and have observed that
the behaviour of the turbines now demonstrates a stable control system that will withstand any future
events in line with Grid Code and CUSC requirements"
(Oscillation damping is "control theory 101", but in a complex system like this it's not so easy!)
Good news is that, while more renewables do potentially have this kind of vulnerability, battery systems are the perfect counter. Some are already being deployed for "fast frequency response". Being a DC-AC system, they can deploy power with any frequency and phase angle required to compensate for problems.
> Oscillation damping is "control theory 101", but in a complex system like this it's not so easy
This is a nice understatement.
My first gig (summer after freshman year) I worked with D. Van Ness, who had an inquiry from he Bonneville Power Administration to determine why their frequency was oscillating (yes, the frequency). This oscillation would rapidly get worse until something tripped and the whole network in the Northwest would go down.
He modeled the system with a state vector and interconnect matrix. The matrix was 500x500 and the path to understanding it was to find Eigenvectors and Eigenvalues of this system. If there any poles to the right of the y-axis, you have an oscillator. Over time, they changed enough to get it stable.
And you make some good points about the synchronization available if everything is a classic generator, and these other power sources are not.
And this was many years ago, so the power systems of today are likely much harder to model.
You put this nicely:
> They act to maintain the frequency by transferring more energy from the shaft rotation to the generato
Another way to think of this is that in a system with more than one generator, a phase difference anywhere in the hookup causes power to flow in direct proportion to the difference in phase angle. In other words, the slow generator becomes a motor.
Yes, the SSO issue in the northwest US power system is a textbook case of this, although in that case IIRC the main issue was control interactions between the power system stabilizers* oscillating together and actually exchanging quite a bit of energy over long distances at a low frequency because those very low frequencies were not effectively damped (or in some cases, negatively damped). At the time, the tools available for large scale power system modelling were very rudimentary compared to what we have today.
In general I don't see it as a renewable vs. conventional issue. SSO/SSR/SSCI have been around since the 1960s when PSS started to be deployed in synchronous generator excitation control systems. Rather it reflects the greater complexity in modelling involved high speed digital controls vs. physical, inertial responses that are expressed very effectively by well-known equations. As we layer on more and more controls, we don't only have to model what is going on at power frequency (50 or 60 Hz) but also at harmonic frequencies and sub-synchronous frequencies. Renewable generators just happen to depend much more heavily on complex control systems for power conversion, mimicking synchronous generator response characteristics and to marry all the components of a large renewable plant together.
At the same time, we have far more powerful tools for power system simulation today that can effectively mitigate this risk, as long as engineers realize the risk is there.
That is the thing about such a highly dynamic system. "Let's just add this dampening right here." Then, we have a system that is very slow to recover.
This is all made more complex by the fact that many of the components of these systems have really non-linear behavior. Like a dam spill that hits a hard boundary.
Without knowing much about the specifics of regulating wind generation, I'd say it adds some complexity, and we don't have the same number of decades of experience of operating it at scale that we do for some other generation techniques.
So I don't see that wind (in the sense of weather patterns) was a contributing factor, but that complexity of regulation probably did contribute.
But then again, as the Little Barford CCGT station showed, it's still perfectly possible to have unexpected failure modes on more conventional generating equipment. (Little Barford enter service in 1996, and is presumably fairly typical of the kind of CCGT stations that were built in large numbers in the UK through the 90s.)
Not directly from my reading; but it was a very windy day so it was contributing quite a lot, so when it failed it made a bigger impact than normal. They also take about sources that provide 'inertia' - and I don't understand if a wind farm counts or not; I don't think it does
* Multiple contingencies occurred simultaneously (loss of generation from two major generators and lost of distributed generation totalling 1,400 MW) resulting in a drop in system frequency to 49.1 Hz
* Standby generation (frequency response reserve) was deployed, totaling 1,000 MW or the largest single generation contingency and began to arrest the system frequency decline
* Just as system frequency began to recover, a third contingency occurred resulting in the loss of a further 210 MW of generation. This caused system frequency to decline again to 48.8 Hz
* Load shedding kicked in as designed and dropped 5% of load to stabilize the system
The largest loss of generation was from Hornsea offshore wind farm. The wind farm should have rode through the system disturbance, but instead its control and protection systems rapidly curtailed active power generation in response to an undamped oscillation in the response of its voltage regulator through the disturbance.
Basically, the internal voltage of the Hornsea wind farm collector system dropped due to the voltage regulator oscillations (from 35 kV nominal to 20 kV), while active power generation remained the same. Power = current * voltage, so an overcurrent condition occurred and protection systems operated to prevent overload of the wind turbine generators.
Subsynchronous oscillations (SSO), i.e. oscillations at below power frequency (50 Hz), are a known issue in power system controls that can lead to unstable or unexpected consequences during system disturbances. The reduction in system inertia caused by the replacement of large synchronous machines with asynchronous generators as wind and solar replace conventional generators exacerbates the possibility of problematic SSO because there is less damping.
Nowadays, in North America, very specific modelling is done in design stage to identify the possibility for such behaviour and ensure that if present it is adequately damped. Some system operators, such as ERCOT (Texas), require this for new wind projects. I imagine that this major occurrence will led to revisions to modelling and grid code testing standards in the UK to protect against future incidents.
All in all, kudos to Ofgem, National Grid and all other participants for producing a thorough, public technical report in just about one month.