Pasnos's profile - activity

Whether transmission voltages will rise or decrease is a matter of the voltage control mode in which you set the RE plants. In case they operate predetermined power factor you should not allow reactive power changes at the renewable terminal buses.

If on the other hand you model the renewable plants as PV buses with specific reactive power limits, then voltage will be controlled by the plant, thereby reactive power will be injected or absorbed depending on the bus voltages of the neighbor area.

What I think you need to do is that you should set a specific power factor on each renewable plant. This will treat the particular bus not as a PV, but rather as a PQ and voltages will result from the load flow calculations..

Loads play an important role on this analysis. Nonetheless, as you may have modelled them as constant P,Q, the PV analysis will proceed with incremental power changes (load or generation) in the area that you will have determined in the dfax files (thereby stressing the system towards a specific determined direction) until the point of no further solution, due to load flow equations limits. What jconto mentions is correct. You have to select to save all the incremental load flow cases in the PV analysis and retrieve the sav file just before the collapse. This corresponds to the limiting case (nose curve point). If you want to go further (down the nose curve) you will have to change the modelling of the loads, i.e. proceed with a relaxation of constant current or constant impedance load modelling. Nonetheless, these operating points do not correspond to more active power consumption, but rather to unstable operating points.

that's what I've thought as well. There is no need to execute anything particular.. At least, that's what I've been doing all these years long..!

In case you retrieve the state variable from the API, why don't you calculate it in an 'a posteriori' pattern, after the value of the state variable is available? You could calculate it as a divided difference, since the time step is known.

If you want to calculate the apparent power factor at some transmission line then you can simply extract the sending active and reactive power of the transmission line psspy.brnflo(FromBusNr,ToBusNr,ID and then just divide them

I am not sure I understand the question. Do you want to calculate some type of apparent power factor at some transmission line?

try to reduce the imposed stress of the fault and see if the problem persists:

1)reduce the duration of the fault 2)increase the impedance of the fault, so that the Isc magnitude is decreased (just temporarily to find the cause of the crash) 3)Reduce the time-step of the simulation 4)Increase the tolerance of the convergence (again, only temporarily)

And just to be a little more specific, you will have to 1)Open sav, convert it, load the dyr 2)Start recording 3)Select the tab Dynamics -> Simulation -> Perform exciter simulation 4) Select the generator bus whose exciter attached dynamic model you want to test and select a step increase of the Vreference value. The output of the exciter system is written on the specified .out file you have mentioned.

Agree with what perolofl has mentioned, also take into account that the plotted bus frequency is the time derivative of the generator internal rotor angle. If you have applied a solid three-phase fault, the active power output will be 0, while the mechanical power (or Torque in pu) will continue to be more or less constant during the first instants after the fault. This creates a Torque surplus and according to the generator power swing equation the rotor will start accelerating, giving rise to Δω as well as Δδ. As long as Δω increases,i.e. as long as the governor continues feeding the Torque surplus, you will be noticing a frequency rise.

Right after the fault clearance, and since Δδ has increased during the fault application, the generator (if still interconnected) will experience a wild active power output change, since the much larger δ (being integrated during the whole fault application acceleration interval) will impose a much larger active power output (much greater than what the governor applied Torque was) giving rise to a Torque deficit and subsequent deceleration interval, which creates a transient power swing.

If you perform LLG, or LG, not all voltages go down to zero and thus the generator continues to supply active power. The active power supplied during the fault might even grow, if the voltage reduction was less than the current increase, although the current increase will mostly be reactive, but still the generator will continue supplying active power giving rise to lower frequency increase.

better solve all initial conditions issues, so that STRT activity is fine, before proceeding with RUN

Change the Vscheduled of each Wind Farm plant to a value close to the Load Flow solution you would get if you didn't integrate any renewables. In that sense you're not pushing the inverters to generate exsessive reactive power and all wind generators should be within their capability limits

+1. It is only due to the implementation of the temperature control. If you look carefully, if the exhaust temperature is lower than the limit Tc, then the integrator continuously integrates and hits the wind up limit. So there should actually be a Dstate <> 0 if no temperature limit is hit