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IMD program is a parameter estimation tool for induction motors. Most of the time, the information you obtain from induction motor manufacturers are rated torque, maximum torque, starting current or locked-rotor current and/or power factor. Equivalent circuit parameters for the motor oftentimes are not published in the motor nameplate or technical data sheets.

What IMD does is to estimate the motor circuit parameters from the torque-current or speed-torque characteristics. You may need to do a little bit of tuning to obtain the motor-circuit parameters that matches the speed-torque characteristic curve.

thank you @perolofl. I have seen the text above on many modeling guidelines/documents but the phrase "30 MWh for 4 hours" is not corrected.

The text below is from the Model User Guide for Renewable Energy System Models:

Consider a simple example of how the reec_c model might be parameterized to represent a BESS. Assume we have a BESS that is rated at 40 MVA, with an energy rating of 30 MWh for 4 hours. Also, let us assume that when in operation the BESS is required by the vendor to always be in a state of charge between 20% to 80%, with the same charging rate (i.e. 4 hours). Then, SOCmax = 0.8 SOCmin = 0.2 The total energy of the device = 30×4 = 120 MWh, thus in operation it can go from 0.8×120 (96 MWh) to 0.2×120 (24 MWh), which means that the maximum output would be (96 – 24)/4 = 18 MWh for 4 hours. Therefore, T = ((18/30) × (60×60×4)) / (0.8 – 0.2) = 14,400 Pmax = 18/30 = 0.6 Pmin = - Pmax = -0.6 Imax = 40/30 = 1.33 The model MVA = 30 MVA. All other parameters would be set per the OEM data.

Questions: 1. Is the model MVA = 30 MVA to be placed in the MBase of the generator in the power flow? 2. Do I need to place the Pmax/Pmin also in REPCAU1 or only in REECCU1? 3. The text "energy rating of 30 MWh for 4 hours" is a little bit confusing since it mentions that the total energy is 30x4 = 120 MWh. The value 120 MWh would be possible only if 30 is in terms of MW not in MWh. Am I missing something here?

It's been a while when i performed an interconnection study.

I am running dynamic simulations and I want to know if a generator trips (any generator that is not under study). Is this information available in the log file? What dynamic simulation setting should be enabled before running the simulations?

Yes but the generator has no response. i tried BAT_CHANGE_GREF and BAT_INCREMENT_GREF. I also tried changing the Pref (VAR(L)) during simulation.

Thank you. What governor model can be used where the change of Gref is allowed? I am using WPIDHY but it does not have a Gref parameter.

Thank you. You mentioned negative Pmech. So this means a governor model should also be present? I tried this approach (Pgen = 0, generator online in load flow) and changed the Pgen to a certain negative value during dynamic simulation. I guess there was an error when I did that method.

The motor models presented here are for induction machines. I don't think they can be used to simulate pump storage motor starting.

Is it possible to simulate the motor starting dynamics when a pump storage is operated in pumping mode? Is there a PSS/E dynamic model that can be used to simulate this phenomenon?

Can someone help me understand the results of the optimal power flow, specifically the Summary Table for the Tap Changing Transformers?

The tap changing transformers are held at fixed position in the OPF settings but I'm not sure why the voltage at each bus changes

Summary Table for Tap Changing Transformers:

From Bus kV Area Zone Voltage Ratio Minimum MW Flow Sensitivity To Bus kV Area Zone Voltage Change Maximum MV Flow Tap Volt

652 BUS 652 1602 1.02675 1.02500 F 0.90000 -3.910 1.00817 659 BUS 659 699 0.99487 1.10000 0.724

655 BUS 652 1678 1.04511 1.00000 F 0.90000 1.870 -79.80223 700 BUS 652 1678 1.04999u 1.10000 -0.964 -76.70278

Does anyone know a reference/literature where I can find the mathematical expressions of the generic dynamic models such as REGCAU1, REECAU1, and REPCAU1? The block diagrams are only available in most literatures.

The idea behind this question is to demonstrate manually the calculations associated to these generic models.

You need to increase the dispatch of other generators connected to Type 2 Buses. The swing generator represents a physical machine so you have to honor its Pmax/Pmin limits when solving the power flow.

Thank you for your response.

I have a sample script shown below. I am seeing issues where when i ran the script it shows an error "v.dyr file in use" after completing one loop of simulation. When the error happens, the simulation continues but it doesn't read the dyr file during activity dyre.

What could be the possible resolution to avoid this scenario?

def vrt_run(self):
    for cnv, snp in zip(os.listdir(self.cnv), os.listdir(self.snp)):
        cnv = cnv[:-4]
        snp = snp[:-4]
        psspy.progress_output(2, self.log +"\\"+ cnv + "_" + snp + "_" + "vrt" + ".pdev")
        psspy.prompt_output(2, self.log + "\\" + cnv + "_" + snp + "_" + "vrt" + ".pdev")
        if os.listdir(self.dll)==[]:
            print "No dll files found inside the folder!"
        else:
            for dll in os.listdir(self.dll):
                psspy.addmodellibrary(self.dll + "\\" + dll)
        try:
            psspy.rstr(self.snp + "\\" + snp + ".snp")
        except:
            print "Error while opening the file", snp
            sys.exit(0)  
        try:
            psspy.case(self.cnv + "\\" + cnv + ".cnv")
        except:
            print "Error while opening the file", cnv
            sys.exit(0)
        psspy.ordr(0)
        psspy.fact()
        psspy.tysl(0)
        psspy.plmod_remove(780000, '1', 1)
        psspy.dyre_add([], os.getcwd() + "\\" + "v.dyr", "", "")
        psspy.tysl(0)
        psspy.snap([-1,-1,-1,-1,-1],os.getcwd() + "\\" + cnv + "v" + ".snp")
        psspy.strt(1,self.out + "\\" + cnv + "_" + snp + "_" + "vrt" + ".out")
        psspy.run(1,15,120,3,0)
        psspy.progress_outpu

Use PLBVFU1 model. This is a dynamic model that allows voltage and frequency signals to be varied. The model is attached to a slack bus generator and a frequency signal is an input to the model.

The renewable generator should respond to the changes in the frequency applied at the point of interconnection through the playback model. The response of the renewable generator is dependent on: dispatch level, frequency flag, and droop characteristics.

A couple of questions: 1. Did you use a PLBVFU1 model at the system slack to perform the voltage step test? 2. Was your generator connected to an excitation system?

When I perform step response tests, I use PLBVFU1 model for the system slack bus and provide step input playback signals (e.g., voltage and frequency). I will let the generator and plant control models respond and from there do the necessary parameter adjustments in order to obtain the desired response and output levels.

If you are simulating a manufacturer-specific inverter, you cannot proceed to tune these parameters without consulting them. Typically, generic dynamic models from inverter manufacturers have these parameters already configured; you may need to update Project-specific settings such as Pmax, Pmin, Qmax, Qmin.

These are load characteristics that allow the user to represent the load as constant current (IPload, IQload) and constant admittance (YPload, YQload). The total load at the bus may be represented as a mixture of constant power, constant current, and constant admittance. When performing time-domain simulations, it is preferred to convert constant power load into constant current and constant admittance characteristics to capture the voltage-dependency of loads.

You need to put the saturated values of subtransient, transient and synchronous reactance of the generators in the sequence data (*.seq) file.

The unsaturated subtransient reactance cannot be used for short-circuit calculations.

In PSS/E, the power flow model is linked with the dynamic model. The PSS/E checks for the value of Xsource in the power flow to see if it is the same as the X" in the generator dynamic model.

The Xsource in the generator power flow model is the unsaturated subtransient reactance in p.u. Please refer to PAGV1.pdf for more information about the generator model.

Negative resistance and reactance can be seen when: a. there are series capacitors modeled as branches b. equivalencing is done on a larger power system network model.

Negative R/X is more likely a data problem unless you have the two items mentioned above.

Your network model needs a sequence data file in *.seq format prior to unbalanced fault simulation. Please check Program Operation Manual (POM.pdf) or Program Application Guide Volume 1 (PAGV1.pdf) for more information about developing the sequence data file.

The settings you specified are voltage and frequency protection settings. The inverter or machine will trip when the parameter monitored exceeds/fall below the threshold while satisfying the time delay setting.