Note: Before starting the demo, open the Powergui block and notice that the 'Phasor simulation' has been checked. The phasor solution is much faster than the 'standard' detailed solution. In this solution method, the network differential equations are replaced by a set of algebraic equations at a fixed frequency, thus reducing dramatically the simulation time. This allows transient stability studies of multimachine systems, as illustrated below.

Circuit Description

A 1000 MW hydraulic generation plant (machine M1) is connected to a load center through a long 500 kV, 700 km transmission line. The load center is modelled by a 5000 MW resistive load . The load is fed by the remote 1000 MW plant and a local generation of 5000 MW (machine M2). The system has been initialized so that the line carries 950 MW which is close to its surge impedance loading (SIL = 977 MW) . In order to maintain system stabilty after faults, the transmission line is shunt compensated at its center by a 200-Mvar Static Var Compenstor (SVC). Notice that this SVC model is a phasor model valid only for transient stabilty solution. The SVC does not have a Power Oscillation Dampling (POD) unit. The two machines are equiped with a Hydraulic Turbine and Governor (HTG), Excitation system and Power System Stabilizer (PSS). These blocks are located in the two 'Turbine and Regulator' subsystems.Two types of stabilizers can be selected : a generic model using the acceleration power (Pa= difference between mechanical power Pm and output electrical power Peo) and a Multi-band stabilizer using the speed deviation (dw). The stabilizer type can be selected by specifying a value (0=No PSS 1=Pa PSS or 2= dw MB PSS) in the PSS constant block.

During this Demo you will apply faults on the 500 kV system and observe the impact of the PSS and SVC on system stability.

1. Load Flow and machine initialisation

In order to start the simulation in steady-state you must first initialize the synchronous machines and regulators for the desired load flow. Note that the system has already been initialized. If you are familiar with the Load Flow procedure you can skip this item and proceed to step 2. In the Powergui menu, select 'Load Flow and Machine Initialization'. A new window appears. The machine M1 'Bus type' should be already initialized as 'PV generator', indicating that the load flow will be performed with the machine controlling its active power and its terminal voltage. Machine M2 will be used as a swing bus for balancing the power. Check that the following parameters are specified for M1 and M2:

Then press the 'Update Load Flow' button. Once the load flow has been solved , the actual machine active and reactive powers, mechanical powers and field voltages will be displayed. If you look in the the hydraulic turbine and governor (HTG) and Excitation system contained in the two Regulator subsystems, you will notice that the initial mechanical power and field voltage have also been automatically initialized by the Load Flow. The reference mechanical powers and reference voltages for the two machines have also been updated in the two constant blocks connected at the HTG and excitation system inputs: Pref1=0.95 pu (950 MW), Vref1=1pu; Pref2=0.8091 pu (4046 MW), Vref2=1 pu.

Open the SVC dialog box and notice that the SVC is set to operate in 'Var control (fixed susceptance)' mode with Bref = 0. Setting Bref to zero is equivalent to putting the SVC out of service. Verify also that the two PSS (Pa type) are in service (value=1 in the PSS constant block) Start the simulation and observe signals on the 'Machines' scope. For this type of fault the system is stable without SVC. After fault clearing, the 0.8 Hz oscillation is quickly damped. This oscillation mode is typical of interarea oscillations in a large power system. First trace on the 'Machine' scope shows the rotor angle difference d_theta1_2 between the two machines. Power transfer is maximum when this angle reaches 90 degrees. This signal is a good indication of system stability. If d_theta1_2 exceeds 90 degrees for a too long period of time, the machines will loose synchronism and the system goes unstable. Second trace shows the machine speeds. Notice that machine 1 speed increases during the fault because during that period its electrical power is lower than its mechanical power.

By simulating over a long period of time (50 seconds) you will also notice that the machine speeds oscillate together at a low frequency (0.025 Hz) after fault clearing. The two PSS (Pa type) succeed to damp the 0.8 Hz mode but they are not efficient for damping the 0.025 Hz mode. If you select instead the Multi-Band PSS (value=2 in the PSS constant block) you will notice that this stabilizer type succeeds to damp both the 0.8 Hz mode and the 0.025 Hz mode.

You will now repeat the test with the two PSS out of service (value=0 in the PSS constant block). Restart simulation. Notice that the system is unstable without PSS. You can compare results with and without PSS by double clicking on the 2nd blue block on the right side. You can also compare the results obtained with the two solution methods 'Detailed' and 'Phasor' by double-clicking on the first blue block on the right side.

Note: This system is naturally unstable without PSS, even for small disturbances. For example, if you remove the fault (by deselecting phase A in the Fault Breaker) and apply a Pref step of 0.05 pu on machine 1, you will see the unstability slowly building up after a few seconds.

3. Three-phase fault - Impact of SVC - two PSS in service

You will now apply a 3-phase fault and observe the impact of the SVC for stabilizing the network during a severe contingency. Put the two PSS (Pa type) in service (value=1 in the PSS constant block. Reprogram the 'Fault Breaker' block in order to apply a 3-phase-to-ground fault. Verify that the SVC is in fixed susceptance mode with Bref = 0. Start the simulation. By looking at the d_theta1_2 signal, you should observe that the two machines quickly fall out of synchronism after fault clearing. In order not to pursue unnecessary simulation, the Simulink 'Stop' block is used to stop the simulation when the angle difference reaches 3*360degrees.

Now open the SVC block menu and change the SVC mode of operation to 'Voltage regulation'. The SVC will now try to support the voltage by injecting reactive power on the line when the voltage is lower than the reference voltage (1.009 pu). The chosen SVC reference voltage corresponds to the bus voltage with the SVC out of service. In steady state the SVC will therefore be 'floating' and waiting for voltage compensation when voltage departs from its reference set point.

Restart simulation and observe that the system is now stable with a 3-phase fault. You can compare results with and without SVC by double clicking on the 3rd blue block on the right side.