Once again, I come back with my questions about negative damping… I am using the DTU 10 MW Turbine (dtu-10mw-rwt.vindenergi.dtu.dk) in a coupled model between FAST and OrcaFlex. The platform is a classic semi-submersible (Pitch Period = 20s). I tried several control properties :
the control files issued from dtu-10mw website,
the control file issued from “Basic DTU Wind Energy controller” (Hansen, Morten Hartvig; Henriksen, Lars Christian),
the control file issued from dtu-10mw website with the low-pass filter from ServoDyn,
the control file issued from dtu-10mw website with the KI gains from the OC3 Project (desperate attempt).
I have negative damping in each case.
I am surprised about these results because I thought the DTU control system was taking into account the floating aspect.
So here is my question: do you think that I am doing this wrong, or is it a classic issue (and are you used to tune your control systems when creating a new model)?
Hello, I can’t open your link, and I am not familiar with DTU 10 MW Turbine, but as far as I know, the smallest controller response natural frequency must be lower than the smallest support-structure natural frequency to avoid the negative damping.
For example, you used the PI gains of OC3 with spar platform, and you applied it to DTU 10 MW Turbine with semi-submersible. These two platforms may have a different natural frequency, you have to tune the controller gains to ensure the smallest controller response natural frequency lower than the smallest support-structure natural frequency.
Hi all
I have a question regarding the basic simulation of the 10MW semi-sub system based on the 10MW DTU reference wind turbine
Firstly it shows that for the DTU reference model at a steady-state wind speed of 9m/s that the rotor speed should have a value of 7.225RPM
As shown in the figure attached, the rotor speed settles at a higher speed of around 7.6RPM
The generator is controlled using the K*omega^2 technique (where K was found by dividing the rated power by the rated rotor speed - the rated rotor speed^2 where the rotor speed is expressed in rad/s)
Also in this simulation I applied a constant wind speed (9m/s) and set the wave model to be still water
Also I changed the drivetrain to direct drive (by increasing the generator inertia by a factor of the gearbox ratio squared - as suggested by Jason)
Based on this information, can you see why there is a difference between the DTU state value and the steady-state wind speed I observed
Thank you very much for any feedback you can provide
Kind regards,
Cameron
Hi Cameron,
It sounds like something may be up with your calculation of k for komega^2, so you are getting a slightly wrong torque value. I forget exactly what region 2.5 looks like on the DTU10MW, but I don’t think the komega^2 trajectory lines up perfectly with rated wind speed. It might be best to cross-reference the value of K you are calculating with one calculated more rigorously (e.g. Bossanyi, 2000) or to the value from the DTU 10MW report (0.100131E+08 [kNm/(rad/s)^2).
I’m not personally familiar with the effect of changing the drivetrain to direct drive, but seemingly this would also change the value of K as well, as the efficiency would change.
Finally, just to remove any variables, disabling the platform and tower DOFs will help verify the proper torque, blade pitch, etc.
Thanks for your response, it has been very helpful
I took your advice and used the K value of 0.100131E+08 [kNm/(rad/s)^2]
This value however resulted in the power being too low and the rotor speed being too high
For example at a wind speed of 11m/s the rotor speed was around 9.3RPM and the power settled around 9.3MW)
I calculated the K value based on the data provided by table 3.3 of the 10MW DTU reference wind turbine
Firstly the reference Torque was found using the rotor speed and mechanical power data for a wind speed of 11m/s (based on the equation T = P/omega (rotor speed in rad/s)
T* = P/omega = (9698.310^3)/0.925 = 10484648.65Nm
The K value was then found rearranging the equation T = Komega^2
K = 12253789.51[Nm/(rad/s)^2]
Using this method when the platform and tower degree of freedoms are disabled, the system produces the correct level of power and rotor speed (when these degrees of freedom are disabled) for wind speeds of 8m/s and above
The problem is that for a wind speed of 7m/s the rotor speed settles at a value of around 5.5RPM(which is below the minimum rotor speed limit of 6RPM) but produces the correct amount of power specified at that wind speed
In this simulation I mainly tested it at the point where the blade pitch is zero and as such eliminates that from the equation and I calculate the mechanical power based of the actual electromagnetic torque (T = K*omega^2) multiplied by the the rotor speed.
I have not computed this inertia myself, but if you are simulating the DTU 10-MW reference wind turbine using the ElastoDyn module of OpenFAST, ElastoDyn will compute the rotor inertia and report in the ElastoDyn summary file (when SumPrint = TRUE).
