One of the issues in commissioning facilities as large as Hornsea is that if you want to do field validation of things like dynamic voltage regulator response (instead of just steady state performance), actually creating a sufficiently large disturbance to test it may not realistically be possible without impacting grid reliability. Hence the reliance on modelling. The presence of an underdamped SSO probably could have been identified in modelling, but there's no indication that National Grid requires SSO studies in design phase.
Also I'm not sure I agree that the SSO was there all along. The system configuration appears to be several STATCOMs at the HV interconnection substation plus the VAR capabilities of the individual wind turbines. There may be an interaction between these control systems that leads to SSO under certain conditions only while being effectively damped at other times.
As for the reclose time, it may have to do with circuit breaker duty cycles. We don't know what equipment they're using but if it's dated stuff, it's conceivable that it requires that level of delay before it's rated for another interrupting operation.
My dad worked in power generation from the 1960s to the 90s. My recollection is that the 20 second reclose has been comon for quite a while, so there's probably a lot of systems out there that assume that's what the fault clearance procedure will be.
Computer controlled artificial loads should exist large enough for any generator...
It should be a device that can be brought in on a truck, hooked up to the plant during commissioning, and the artificial load should be able to replay any conditions during grid incidents in the past, to check all the control systems work as designed.
A 1 Gigawatt artificial load that can work for 1 second could consist of 10 cubic meters of water (on a truck) and a few miles of nicrome wire... You'll also be needing some beefy switching silicon to simulate something more than a simple resistive load, but they exist already in any DC undersea power project.
So a 2% step change in voltage regulator setpoint for any individual WTG would be non oscillatory but in aggregate, or in interaction with the statcom it oscillates at 6.5 Hz?
When I’m setting the gains for any control loop I tend to prefer choosing lower gains that still meet the performance requirements rather than having high gains closer to the edge of stability. I would not leave a system behind that had 13 oscillations after a step.
All I'm saying is that the frequency-impedance characteristic of the local system changes depending on active power loading, other nearby generators in or out service, nearby reactors or capacitors in service, etc. So it's conceivably possible that the oscillatory behaviour was more effectively damped both in the modelling cases and in whatever field testing they did. Though if you read the grid code compliance testing report for Hornsea, it's not evident they actually did voltage step change field validation.
If this kind of oscillation was present under all conditions, it would be an oversight to not have caught it in the modelling stage. The level of modelling we have to do in some North American regions for a 50 MW wind farm would catch that kind of behaviour, let alone an 800 MW unit.
Indeed when there are large outages is when utilities often find out that the models
Don’t quite match reality. One example would be when 1200 MW of generation tripped in the WECC region and they found the effective droop of the system was about 8% instead of 5, and have since mandated that every generator over 10 Mva is tested every 5 years to ensure the equipment still matches the model.
Also I'm not sure I agree that the SSO was there all along. The system configuration appears to be several STATCOMs at the HV interconnection substation plus the VAR capabilities of the individual wind turbines. There may be an interaction between these control systems that leads to SSO under certain conditions only while being effectively damped at other times.
As for the reclose time, it may have to do with circuit breaker duty cycles. We don't know what equipment they're using but if it's dated stuff, it's conceivable that it requires that level of delay before it's rated for another interrupting operation.