See Also
The Power System Model sub-tab is found on the Options page of the Transient Stability Analysis dialog. This contains options for how the actual transient stability numerical simulation is performed.
Common: Power System Values
Nominal System Frequency (Hz)
Set the nominal system frequency in hertz. The default is 60 Hz.
System MVA Base
MVA base for the system. The value cannot be changed here and is shown for informational purposes only. To change this value, go to the Power Flow Solution General page found under Simulator Options.
Initial System Frequency (Hz)
Normally, the assumed initial system frequency is the Nominal System Frequency. To set the initial condition's frequency differently change this value.
When Using Playin Models Set Initial Hz to First Value Added in Version 20.
Choose this check box to automatically set the initial system Frequency to the initial frequency from the PlayInGen model's frequency PlayIn signal.
Common: Network Equation Solution Options
Solution Tolerance (MVA)
Specify the convergence tolerance used in the transient stability's power flow algorithm. This option setting only affects the transient stability power flow algorithm and does not affect the power flow model.
Maximum Iterations
Specify the maximum number of iterations allowed in the transient stability's power flow algorithm. This option setting only affects the transient stability power flow algorithm and does not affect the power flow model.
Abort after number of failed solutions Added in Version 20.
When running a transient stability simulation, a particular network solution may have a hard time converging and result in oscillating near a solution but not actually achieve a solution to within the tolerance. It is not uncommon for the network solution to then be achieved easily on the next time step's network solution. This option defaults to a value of 10 meaning that the simulation will not abort until 10 consecutively failed network solutions.
Force Network Equation Update
Specify a time in seconds which forces a full network equation update every so many seconds. This option can be helpful to avoid small unit oscillations caused by small mismatches.
Use Voltage Extrapolation
When this option is checked, an estimate of the voltage at time step will use the voltage at the previous three time steps to estimate what the next voltage will be. This essentially models the voltage as a quadratic function of time based on the last three time steps and creates an estimate of what the next voltage will be. This greatly aids in the initial guess sof the network equation voltages at a time step and helps speed up the simulation.
Inner Loop Mismatch Scalar
PowerWorld Simulator uses a second order Runge-Kutta integration method. As a result network equation solutions are sometimes done at intermediate time steps as part of the integration method. Specifying a scalar here which is larger than 1.0 will allow those intermediate network equation solution to have a larger mismatch.
Common: Handling of Initial Limit Violations
The first step in a transient stability numerical simulation is to initialize the transient stability dynamic models based on the initial condition taken from the power flow solution. It is not uncommon for this initialization to result in many violations of limits specified in the dynamic models. This gives you three options for how to handle these initial limit violations. The options and what the do are as follows
1. Modify Limits and Run: choose this to have Simulator temporarily modify the limits that are violated during this transient stability simulation.
2. Abort: choose this to abort the numerical simulation completely if any state violations exist. In an ideal world, all these would be corrected before continuing, but you may not have information on how to correct either the stability model or the initial power flow solution.
3. Run without Changing Limits: choose this to run Simulator leaving the limits alone. This means that the states in simulation will immediately start moving at the initial time as the numerical simulation enforces these limits.
A list of limit violations is available on the Transient Stability Analysis: States/Manual Control
Common: Integration Method
Option to specify whether to use the Second Order Runga-Kutta Order 2 (RK2) integration time step or a simple Euler step.
Common: Infinite Bus Modeling
Select whether or not to use infinite buses. If using infinite buses, the power system slack bus(es) will be used as the infinite buses. If not using infinite buses, then an Angle Reference must be selected on the Result Options. At infinite buses the angle does not change. When using infinite buses, these are used as the angle reference.
Common: Frequency Measurement Options
Bus Frequency Measurement Time Constant (Sec.)
Bus frequency in a transient stability simulation is a value which is calculated by performing a special calculation similar to taking the derivative of the bus angle. This means there is a time-constant associated with calculating this frequency and this value can be specified here. Also note that Bus frequency is calculated at all buses during a transient stability simulation.
Minimum PU voltage for relay frequency measurement Added in Version 19, November 24, 2015
Some transient stability models involve using bus frequency as signal that determines whether to trip a device. Load relays or generator relays for instance. In some extreme situations at very low voltages, the calculation of bus frequency using a time constant can give very low or very high frequency values which would not be seen by a real relay. In a real relay device there is always a voltage threshold below which these types of relays be blocked from operating. This is because frequency in relays in calculated by looking at the zero crossing of a the AC wave form. The counting of zero crossings becomes unreliable at low voltage. This option (which defaults to 0.3 per unit) will change how relays perceive frequency when the per unit voltage is below this threshold. If the voltage falls below this threshold the relay will behave as though it is seeing the nominal frequency.
Calculate Bus ROCOF (Rate of Change of Frequency) Added in Version 20
Check this box to also calculate the derivative of the bus frequency.
Common: Negative Load Models for Generators without Models
Specify as either a constant impedance or a constant current. This determines how the generator is modeled during the simulation if the generator does not have any machine model specified.
Common: Island Synchronization Added in Version 20
Transient stability simulations do not fully model the closing of a transmission line that connects two separately synchronized electrical islands. In order to properly model this numerically, one must assume that the presently the phase angles on either side of the AC branch being closed in are nearly matched and that the frequencies of both islands are nearly matched. In a real system, an system operator may need to change generator governor set points to bring the system frequencies to a common value, but in a numerical simulation this may be cumbersome. Assuming that the bus voltage angles are brought back close to one another is an easier task as really the angle in the system are really only important as compared to other angles. It is appropriately to rotate all angles in the system by the same degrees. These decisions lead to 2 options.
Angle Options and Value Added in Version 20
This is the choice about how to change the angles in separate electrical islands before closing in an AC branch.
1. Set to Degree Value: This option means that the angle difference across the AC line will be set to the Degree Value specified. This is done by rotating all the angles in one electrical island to achieve this.
2. Set if > Degree Value: This option is similar to the first, but we will only rotate bus angles if the existing angle difference is larger than the Degree Value specified.
3. No Change. This option means no change will be made.
Frequency Options and Value Added in Version 20
This is the choice about how to change the frequencies in separate electrical islands before closing in an AC branch.
1. Set to Hz Value: This option means that the frequency difference across the AC line will be set to the Hz Value specified. It is provided as a convenience for a numerical simulation tool, but you should realize that this has no physical meaning and is achieved numerically by instantaneously changing the machine speed state of all synchronous machines in the electrical island and also changing the calculated frequency of all buses in the island. This is not physically possible, but can be useful in a simulation tool.
2. Set if > Hz Value: This option is similar to the first, but we will only change the frequencies if the existing frequency difference is larger than the Hz Value specified.
3. No Change. This option means no change will be made.
Common: Simulate New Island Requirements
As branches change status during a transient stability simulation, new islands can be created. These options will determine if a newly created island continues to be simulated. If the newly created island does not have at least a specified number of buses AND a specified number of gnerators then it will not be numerically simulated. When an island is not simulated it means that all buses in the newly created island are assumed to be dead with a 0.0 voltage at all buses and all dynamic models ignored.
Bus Count >= Added in July 10, 2023 patch of Version 23
Specify a minimum number of buses
Generator Count >= Added in July 10, 2023 patch of Version 23
Specify a minimum number of generators.
Common: Geomagnetic Induced Current Options
Include GIC Effects
Check this box to include GIC effects (Mvar losses caused by GIC) in the transient stability simulation.
Just Calculated GIC with No Network Solution Added in Version 20
Check this option to use the transient stability simulation tool as a convenient tool for running a time-series of GIC DC network calculations. This means that the traditional transient stability simulation will not be done at all, but instead at each time-step the GIC DC currents will be calculated but no further calculations will be done.
Load Modeling: Default Load Model
Specify what load model to use by default in the transient stability simulation when the load does not have a load model characteristic defined. Normally it is best to define a load characteristic model specifically (it is even possible to define a load characteristic model which applies to the entire case), but if one is not specified this default will be used.
Load Modeling: Minimum Per Unit Voltages for
When modeling loads as Constant Power Models or Constant Current Models, the load will start to fall off by a particular function if the voltage falls below the specified value. The values specified here are the same as the values for minimum voltages specified on the Power Flow Solution Advanced Options page found under Simulator Options. Clicking the Change button will open the Power Flow Solution Advanced Options page.
Load Modeling: When to use Complex Load Models
There are several global filters which are used to indicate when complex load characteristics that represent a composite of various other load types should be ignored. (Examples of these types of loads are CLOD, CMPLDW, CMLD, MOTORW and CompLoad). These filters also apply to the distribution equivalent model. If the load record meets any of these filters then the distribution equivalent will be ignored and the complex load model will not be used and the default load model will be used instead.
Minimum Load P (MW) Added in Version 19, September 14, 2016 patch
A complex load characteristic model and distribution equivalent model will not be used if the load is less than this power.
Minimum Load P/Q (MW) Added in Version 19, September 14, 2016 patch
A complex load characteristic model and distribution equivalent model will not be used if the ratio of real power to reactive power is less than this value. Default value is 0.25 which would mean that the real power of the load is 4 times smaller than the reactive power of the load.
Minimum Initial per unit voltage Added in Version 20
A complex lload characteristic model and distribution equivalent model will not be used if the initial voltage at the transmission level bus is less than this value.
Load Modeling: Distribution Equivalent Model Options
Min Nom kV for Transformer Added in Version 20
Any distribution equivalent model that is assigned to a load which is connected to a bus with a nominal voltage below this value will automatically ignore the Xxf term of the transformer. Essentially for that particular load the Xxf value will be assumed to be 0.0.
Compatibility Options: Exciter Saturation Model
Option to specify the type of saturation function to use for an exciter model. Choices are Quadratic (GE Approach), Scaled Quadratic, or Exponential. When loading a PSLF DYD file it defaults to the Quadratic exciter saturation function. When loading a PSS/E DYR file it defaults to the Scaled Quadratic exciter saturation function. When loading a IPF SWI file it defaults to the Exponential exciter saturation function.
Compatibility Options: Exciter Automatic Parameters
Allow implementation of option to determine how Ke is determined, either using the GE approach [setting Vr=0] by selecting Vr = Zero Approach, or the PSSE approach (of equal to Vrmax/10 by selecting Vr > Zero Approach.
Compatibility Options: Machine Saturation for S12 < S10
Selecting Flip Values will Flip the values when this condition (S12 < S10) is met. Selecting Ignore Saturation will ignore the saturation when the condition (S12 < S10) is met.
Compatibility Options: Saturation when One SE is Zero
Selecting Treat as Always Zero will give the Saturation a zero value. Selecting Normal Curve Fit will try to give the Saturation the value by doing a curve fitting.
Compatibility Options: MotorW Modeling
The PSLF MotorW induction motor model, which is also used inside the CMPLDW and CMPLDWNF model, but does not use a standard induction motor model with 7 input parameters.
Instead MotorW only provides 6 input parameters (it omits the leakage reactance) and it uses different dynamic equations. For the case of a single cage motor, the equations of MOTORW are the same as other induction motors, but for the case of a double-cage motor the models are different. In order to match the results seen in PSLF you must set this option to PSLF. If you choose Full Model, then the leakage reactance is assumed to be equal to 0.8*Xpp. If you want to specify a particular leakage reactance than use a different load model.
Compatibility Options: Governor Fast Valving
A few specific governor models such as TGOV3 include an effect called Fast Valving. This option specifies at what time the fast valving option is initiated. After choosing when you would like it to initiate you then specify either a frequency deviation in rad/sec or a time in second as the parameter Fast Valving Parameter (rad/sec or sec).
Compatibility Options: Ignore Speed Effects in Generator Swing Equation
The generator swing equation includes a term divides the Mechanical Power by the per unit speed of the generator. Checking this box will ignore this speed effect. Normally you should not ignore this effect.
Compatibility Options: Include Undocumented Governor PI Limits
Selecting this option will enforce non-windup limit for the governors regarding of the parameters settings in the governor. This includes the following governors: HYPID, GPWSCC, PIDGOV, HYG3
Compatibility Options: Include dynamics of 3 terminal Pacific DC Intertie or Intermountain DC if appropriate MTDC records exists
Selecting this option will inlude the modeling of the dymaics of 3 terminal Pacific DC Intertie or Intermountain DC models.