lab manual 180906 aps-ii

Advanced Power System-II (180906)

B.E. Electrical (Semester‐8) Department of Electrical Engineering 1

G.H.PATEL COLLEGE OF ENGINEERING & TECHNOLOGY

VALLABH VIDYANAGAR388 120

DEPARTMENT OF ELECTRICAL ENGINEERING

LABORATORY MANUAL

BACHELOR OF ENGINEERING

SUBJECT CODE: 180906 SUBJECT NAME: ADVANCED POWER SYSTEM‐II



List of Experiment

1. Introduction to Power World Simulator and creating a new case.

2. To study the effect of generation outage and transmission line outage in power system using Power World Simulator.

3. To study and calculate the Linear Sensitivity Factors for contingency analysis using Power World Simulator.

4. To study the preventive and emergency control using Power World Simulator.

5. To study the state estimation of power system.

6. To study the effect of reactive power on voltage of the system.

7. To understand the method of voltage control by tap‐changing transformer using Power World Simulator.

8. To study voltage control using Capacitor bank connected at the receiving end‐bus.

9. Assignment on Load Forecasting Techniques.

10. Assignment on Power System Restructuring.



Experiment: 1 Date:___________

Aim: Introduction to Power World Simulator and creating a new case. Introduction: PowerWorld Simulator (PowerWorld) version 15 is a commercial‐grade power system analysis and simulation package that accompanies this text. The purposes of integrating PowerWorld with the text are to provide computer solutions to examples in the text, to extend the examples, to demonstrate topics covered in the text, to provide a software tool for more realistic design projects, and to provide the readers with experience using a commercial grade power system analysis package. Simulator is a full‐featured power flow analysis package capable of solving systems of up to 100,000 buses. It is a power system package that actually shows the flow of power in the system as flowing animations. Colored arrows on the transmission lines, loads, and generators are animated, with their movement, size, and direction proportional to the magnitude and direction of the power flow. All model parameters, functions, and tools are accessed easily through Simulator's graphical user interface (GUI), which offers unparalleled ease‐of‐use and, thus, a very modest learning curve. Simulator's GUI, which has long been its strongest selling point (because it is the product's most obvious advantage over its competitors), aids both in using the program and in interpreting its results. Using Simulator's one‐line displays and information dialogs, it is possible to build and modify a model graphically and to verify in a convenient way that the changes you have made are indeed correct. In Edit Mode, the package allows you to build new cases either from scratch or by starting with an existing power flow case. This module is fully integrated into the simulator. Along with the simple power system operations following advanced options are available in PowerWorld. Contingency Analysis – Automatically run through a list of 1000’s of contingency and create a list of system overloads and voltage problems seen during these contingencies. Also compare the results of two contingencies runs. Unbalanced Fault Analysis – Determine the A, B, and C phase currents and voltages after a fault in the system. Includes support for all unbalanced fault types as well as mutual impedances and fault impedances. Sensitivity Calculations – Determine the linear sensitivity of line flows and voltages to power injections, transfers or line outages/insertions. This includes the calculation of Power Transfer



Distribution Factors (PTDFs), Line Outage Distribution Factors (LODFs), Transmission Loading Relief Sensitivities (TLRs), and Generation Shift Factors (GSFs). You can also calculate Loss Sensitivities using the sensitivity tools. Optimal Power Flow (OPF) – Optimally dispatch your system to remove transmission line overloads, while also calculating spot prices (also known as locational marginal prices). OPF is available as an add‐on to Simulator. Available Transfer Capability Tool (ATC) – Calculate ATC values in seconds using linear analysis techniques. ATC is available as an add‐on to Simulator. PV and QV Curves Tool (PVQV) – Study voltage stability problems in your system using PVQV. PVQV is available as an add‐on to Simulator. Security Constrained Optimal Power Flow (SCOPF) – Optimally dispatch your system to remove transmission line overloads under the base case and under any contingency, while also calculating spot prices (also known as locational marginal prices). SCOPF is available as an addon to Simulator. Creating a new case: To begin, double‐click on the PowerWorld Simulator icon. This starts Simulator. Simulator is used to create new cases, modify existing cases, and (of course) simulate power systems. To create a new case, select New Case from PowerWorld icon in the upper left corner of the program. The screen background will turn white, the default background color for new PowerWorld one line diagram. One line diagrams are used in power system analysis to represent the actual three‐phase power system using a single line to represent each three‐phase device. Inserting a Bus: The most important component of the power system model is the bus. Buses are used to represent junction points in the power system where a number of devices are connected together. To insert a bus: Select Network > Bus from the Individual Insert ribbon group on the Draw ribbon tab.

This prepares Simulator to insert a new bus. Left‐click on the one line background at the location where you want to place the new bus. This

invokes the Bus Option Dialog (pictured below), which is used to specify the name, orientation, shape, size, width, area, zone, and nominal voltage of the bus, as well as the load and shunt compensation connected to the bus .



Insert the necessary data in the dialogue box and then click ok. After the dialog box closes, the new bus appears on the one line at the location you specified. Inserting a Generator:

Generators may be inserted in a manner similar to inserting a bus:

Select Network > Generator from the Individual Insert ribbon group on the Draw ribbon

tab. Left‐click the bus on the one line diagram to which you want to attach the generator (for

this example, click on the slack bus – bus One.) The Generator Option Dialog (pictured below) will automatically open. The dialog is used to specify the new generator’s unit identifier, display size, orientation, MW output and limits, reactive power limits, set point voltage, and cost model.



Insert the necessary data in the dialogue box and then click ok. After the dialog box closes, the new generator will appear on the one line attached to the previously selected bus. The oneline diagram should resemble the image shown below.

Entering a Second Bus with Load

To enter the second bus:

Select Network > Bus from the Individual Insert ribbon group on the Draw ribbon tab.



Click on the one line diagram somewhere to the right of the first bus. In the Bus Options Dialog (pictured below) leave the bus number at the default value of 2, and enter the name ‘Two’ in the Bus Name field.

We will model a 200 MW, 100 Mvar load at the bus. Select the Attached Devices tab. Under the Load Summary Information heading enter ‘200’ in the Base MW field and ‘100’ in the Base Mvar field.

Click OK to accept all other default values, close the Bus Options Dialog, and insert the bus.

To draw the load on the one line diagram:

Select Network > Load from the Individual Insert ribbon group on the Draw ribbon tab. Left‐click in the center of this bus. The Load Options Dialog box (pictured below)

automatically opens. The Constant Power MW and Mvar fields confirm that the load is 200 MW and 100 Mvar. In addition to constant power loads, Simulator also allows the modeling of voltage dependent loads.

Select Up in the Orientation field under the Load Information tab to make the load point up. Verify that the anchored box is checked to force the load to move with the selected bus.

Click OK to accept the default values for all remaining fields, close the Load Options dialog, and insert the load. A circuit breaker symbol is automatically included with each load.

To move objects on the one line:

Left‐click on the desired object. Drag and drop the object to the new location by holding the

left mouse button down while moving the mouse. Note: you can also move all objects on



the one line simultaneously by left‐clicking on the diagram (not on a specific object) then dragging and dropping in the desired location.

To move bus 2, left click on bus 2 (not on the attached load). Drag the bus to a new location. Note that the load moves with the bus because it is anchored. You can change the location of attached devices connected to a bus, such as generators and loads, by the same procedure.

The one line diagram should now resemble the image shown below.

Inserting a Transmission Line

Transmission lines are used to connect buses together. To insert a transmission line:

Select Network > Transmission Line from the Individual Insert ribbon group on the Draw

ribbon tab. Left‐click at the point where you want the new line to originate. This point is usually

located on one of the proposed line’s terminal buses. For this example, originate the line at bus One.

Transmission lines and transformers are drawn as a series of line segments. Without holding down the mouse button, drag the mouse up. Notice that a line segment connected to the point of origin will follow your mouse movements. To terminate a line segment, click the left mouse button. Each time you click the mouse to terminate a line segment, a new vertex is defined for the line. To draw the next line segment, move the mouse to the desired location of the next vertex. Note: the vertices may later be moved or deleted to reshape the line. To create curved lines, hold the left mouse button down while dragging.

To terminate the final line segment and conclude drawing the line, double click the left mouse button at the desired termination point (bus Two for this example). The termination point is usually the transmission line’s other terminal bus.

The Transmission Line/Transformer Dialog automatically appears (shown below). The dialog should already contain a 1 in the From Bus Number field and a 2 in the To Bus Number Field. If not, you probably did not have the cursor directly on the bus when you were drawing the line. If this is the case, simply enter the correct bus numbers in the corresponding fields.



Save your case. Your one line should now look similar to the image below.

Similarly, you can insert circuit breakers, transformers and other device according to your system. Solving the Case:

To solve a case, you must be in run mode:

Click on Run Mode button in the Mode ribbon group. Note that if the case has validation

errors, a warning will appear. You will need to rectify the problems before you can enter Run Mode.



Press the Play button in the Power Flow Tools ribbon group on the Tools ribbon tab to begin the simulation. Alternatively, to perform a single Power Flow Solution, click the Single Solution Full Newton button in the Power Flow Tools ribbon group on the Tools ribbon tab. Your case should look similar to the case shown below. If it does, congratulations! You have completed building your first case.

Exercise:

Create the new case for simulation which consists of 3 buses with the generators on 2 buses and loads on two buses. Also connect the transformer in the transmission line between the buses. Tabulate the line flows and bus voltages by running the simulation. Also comment on the results.



Experiment: 2 Date: ___________

Aim: To study the effect of generation outage and transmission line outage in power system using PowerWorld Simulator. An overriding factor in the operation of a power system is the desire to maintain system security. System security involves practices designed to keep the system operating when components fail. For example, a generating unit may have to be taken off‐line because of auxiliary equipment failure. By maintaining proper amounts of spinning reserve, the remaining units on the system can make up the deficit without too low a frequency drop or need to shed any load. Similarly, a transmission line may be damaged by a storm and taken out by automatic relaying. If, in committing and dispatching generation, proper regard for transmission flows is maintained, the remaining transmission lines can take the increased loading and still remain within limit. Because the specific times at which initiating events that cause components to fail are unpredictable, the system must be operated at all times in such a way that the system will not be left in a dangerous condition should any credible initiating event occur. Since power system equipment is designed to be operated within certain limits, most pieces of equipment are protected by automatic devices that can cause equipment to be switched out of the system if these limits are violated. If any event occurs on a system that leaves it operating with limits violated, the event may be followed by a series of further actions that switch other equipment out of service. If this process of cascading failures continues, the entire system or large parts of it may completely collapse. This is usually referred to as a system blackout. An example of the type of event sequence that can cause a blackout might start with a single line being opened due to an insulation failure; the remaining transmission circuits in the system will take up the flow that was flowing on the now‐opened line. If one of the remaining lines is now too heavily loaded, it may open due to relay action, thereby causing even more load on the remaining lines. This type of process is often termed a cascading outage. Most power systems are operated such that any single initial failure event will not leave other components heavily overloaded, specifically to avoid cascading failures. Therefore, it is essential to observe the effects of line outage or generation outage on the remaining healthy components of the system. The study of line outage and generation outage cases is useful in deciding the appropriate control actions during the real contingency conditions and the system can be operated securely.



Procedure:

1) Create the 4‐bus system with loads on 3 buses and generation on 2 buses in PowerWorld Simulator.

2) Run the simulation for normal operating condition and prepare the summary of power flow data.

3) Generation Outage Case: Change the generation on any bus (either reduce the generation or disconnect the entire generation) without reducing the load.

4) Run the simulation and observe the power flow data.

5) Compare the two operating conditions (Pre‐outage and post‐outage cases).

6) Line Outage Case: Remove any one transmission line and run the simulation.

7) Observe the power flow data.

8) Compare the results with Pre‐outage data.

9) Comment on the effects of generation.




Aim: To study and calculate the Linear Sensitivity Factors for contingency analysis using PowerWorld Simulator. A security analysis programs run in a load dispatch entre very quickly to help the operators. The problem of studying thousands of possible outages becomes very difficult to solve if it is desired to present the results quickly. One of the easiest ways to provide a quick calculation of possible overloads is to use linear sensitivity factors. These factors show the approximate change in line flows for changes in generation on the network configuration and are derived from the DC load flow. These factors can be derived in a variety of ways and basically come down to two types:

1) Generation shift factors 2) Line outage distribution factors

(1) Generation shift factors: The generation shift factors are designated αli and have the following definition: Where, l = Line index i = Bus index Δfl = Change in MW flow in line l when change in generation takes place at ith bus ΔPGi = Change in generation at bus i It is assumed in this definition that the change in generation, ΔPGi , is exactly compensated by an opposite change in generation at the reference bus, and that all other generators remain fixed. The αli factor then represents the sensitivity of the flow on line l to a change in generation at bus i. The generation shift sensitivity factors are linear estimates of the change in flow with a change in power at a bus. Therefore, the effects of simultaneous changes on several generating buses can be calculated using superposition. (2) Line Outage Distribution Factors: The line outage distribution factors are used in a similar manner, only they apply to the testing for overloads when transmission circuits are lost. By definition, the line outage distribution factor has the following meaning:

lli

Gi

f

P

,l

l i oi

fd

f



Where, dl,i = line outage distribution factor when monitoring line l after an outage on line i Δfl = change in MW flow on line l f0i = original flow on line i before it was opened If one knows the power on line l and line i, the flow on line l with line i out can be determined using "d" factors. By pre‐calculating the line outage distribution factors, a very fast procedure can be set up to test all lines in the network for overload for the outage of a particular line. Furthermore, this procedure can be repeated for the outage of each line in turn, with overloads reported to the operations personnel in the form of alarm messages. Procedure:



3) Generation Shift Factor: Change the generation on any bus (either reduce the generation or disconnect the entire generation) without reducing the load.

4) Run the simulation and observe the power flow data.

5) Calculate the Generation Shift Factors using the above equations.

6) Line Outage Distribution Factor: Remove any one transmission line and run the simulation.

7) Observe the power flow data.

8) Calculate the Line Outage Distribution Factors using above equations.

9) Comment on the system by considering the values of linear sensitivity factors.

Assignment:

1. What do you mean by power system security? Explain its three major functions.

2. What is contingency analysis? Discuss the steps involved in it.

3. Discuss the sensitivity factors used in security analysis.




Aim: To study the Preventive and Emergency control using PowerWorld Simulator. If all the equipments in the system are within their respective limits, then a system could be in the normal or alert state. If a system can withstand potential contingencies (like a fault followed by line tripping or a generator trip) without equipment limits being violated or without losing stability, then we say that the system is in a normal or "secure state". A network configuration or loading state which can withstand an element outage without loss off supply to any load is called "n‐1" secure. Otherwise we classify the system as being "insecure", i.e., in the alert state. To distinguish between a normal state and an alert state, a system operator carries out the following studies using the network configuration, load and generation values obtained from a static state estimation procedure: Static Security analysis: This involves checking for equipment limit violations, if one of the elements of the network/load/generation configuration existing at that point of time were to be tripped due to some contingency. Note that this element is not actually tripped by an operator, but only simulated using a computer program (essentially a load‐flow study which computes the steady state power flows in transmission lines, generator real and reactive power output, and voltages at various nodes for such a tripping). Dynamic Security analysis: This involves checking the stability of the system, if one of the elements of the network/load/generation configuration existing at that point of time were to be tripped due to some contingency. The exact nature of the contingency can impact the transient behavior. For example, the contingency could be due to a single phase to ground fault which results in protective action (circuit breakers disconnecting the faulted element) within, say, 0.1s. Note again, that this element is not actually tripped by an operator, but only simulated using a computer transient analysis program (which essentially does a numerical integration of the differential equations which describe the system). A computer program which checks for angular stability requires a significantly large amount of computation time. Therefore, it is not implemented in most load dispatch centers at present. If the security analysis shows that the system is secure, it is classified as a normal state. If the state is normal, then a system operator may wish to do some minor changes in real and reactive scheduling (from an economic perspective), if such flexibility exists. However any such change should not bring the system out of the secure state.



Preventive Control: If the system is not secure (alert), then the operator has to try to steer it into the secure state by real or reactive power re‐scheduling (Preventive Control ). However, note that this re‐scheduling is done to improve security and may result in higher cost if cheaper generators are asked to "back down" their generated power while costlier ones are ramped up. Therefore, even if preventive control is to be done, it should be done in a way which will minimize any cost increase while simultaneously ensuring security. Emergency Control: If a system operator infers from the operating data that a system is in an alert state, then he takes preventive control actions to bring the system back to a normal state. However, it is possible that the system operator is unable to act in time before a contingency actually occurs. A grid may even operate insecurely (in an alert state) due to a high cost of preventive control or due to inadequate reserve margins. However this situation is undesirable since it may lead to blackouts (if emergency control actions fail) which can cause great economic loss. The classification of a system state as a normal or alert state is based on simulating some disturbances. Often, even though the system has been classified as being in a normal state, several improbable disturbances, which would not have been analyzed for doing this classification, take place. Therefore the system can transit from a perceived alert state to an emergency state if no preventive controls are exercised and a contingency occurs, or may directly transit to an emergency state from a perceived normal state if an unanticipated sequence of several contingencies occurs. If the system does go into an emergency state some equipment limits are exceeded which may cause further tripping of equipment, thereby worsening the situation and may cause a complete blackout. Emergency control actions (manual or automatic) are required to retrieve the situation. If there is a thermal overload of an equipment then there is some time to act and quick "heroic action" from a system operator would be needed. However in most cases one has to rely on automatic controls to quickly respond to such a situation. Some emergency control actions are:

Generator / Load tripping or fast reduction of generated or load power.

Control of voltage and power flow control devices



Procedure:



3) Select the parameters such that any line is near to overload.

4) Take the Preventive control and try to restore the system in normal operating state.

5) Set the data such that system enters in to emergency state.

6) Take the Emergency control and try to restore the system in normal operating state.

7) Write your observation/conclusion.

Assignment:

1. Explain power system operating states with diagram.

2. Explain preventive and emergency control in brief.

3. What is black‐out? Explain the steps taken for the restoration of power system after black‐

out.




Aim: To study the state estimation of power system. State estimation is the process of assigning a value to an unknown system state variable based on measurements from that system according to some criteria. Usually, the process involves imperfect measurements that are redundant and the process of estimating the system states is based on a statistical criterion that estimates the true value of the state variables to minimize or maximize the selected criterion. A commonly used and familiar criterion is that of minimizing the sum of the squares of the differences between the estimated and “true” (i.e. measured) values of a function. In a power system, the state variables are the voltage magnitudes and relative phase angles at the system nodes. Measurements are required in order to estimate the system performance in real time for both system security control and constraints on economic dispatch. The inputs to an estimator are imperfect power system measurements of voltage magnitudes and power, VAR, or ampere‐flow quantities. The estimator is designed to produce the “best estimate” of the system voltage and phase angles, recognizing that there are errors in the measured quantities and that there may be redundant measurements. The output data are then used in system control centers in the implementation of the security‐constrained dispatch and control of the system. Many problems are encountered in monitoring a transmission system. These problems come primarily from the nature of the measurement transducers and from communications problems in transmitting the measured values back to the operations control center. Transducers from power system measurements, like any measurement device, will be subject to errors. If the errors are small, they may go undetected and can cause misinterpretation by those reading the measured values. In addition, transducers may have gross measurement errors that render their output useless. An example of such a gross error might involve having the transducer connected up backward; thus, giving the negative of the value being measured. Finally, the telemetry equipment often experiences periods when communications channels are completely out; thus, depriving the system operator of any information about some part of the power system network. It is for these reasons that power system state estimation techniques have been developed. A state estimator, as we will see shortly, can “smooth out” small random errors in meter readings, detect and identify gross measurement errors, and “fill in” meter readings that have failed due to communications failures. Least Square Estimation: The Basic Solution The problem of power system state estimation is a special case of estimation of a random vector x from the numerical values of another related random vector y.



In such cases, the method of least‐squared‐error estimation may be utilized. Assume that, x is a vector of n random variables x1, x2,…….,xn. y is a vector of m (>n) random variables y1, y2,…….,ym. Both are related as

[ ]y h x r ………………………..(1)

Where, H is a known matrix of dimension m x n r is a zero mean random variable of the same dimension as y. The vector x represents the variables to be estimated, while the vector y represents the variables whose numerical values are available. Equation (1) suggests that the measurement vector y is linearly related to the unknown vector x and in addition is corrupted by the vector r (error vector). The problem is to obtain the best possible value of the vector x from the given values of the vector y. Since the variable r is assumed to be zero mean,

.y H x …………………………..(2)

The load flow methods can be used to estimate the mean values of the bus voltages. One possible way of obtaining the best possible estimate of the vector x from y lies in the use of the method of least square estimation (LSE). Assume that

x = the desired estimate of x so that ŷ given by following equation represents the estimate of y.

y H x …………………………….(3) The error ŷ of the estimation of y is then given by

y y y …………………………(4) The estimate x̂ is defined to be the LSE if it is computed by minimizing the estimation index J given by



'J y y ………………………..…(5)

From Equations (1) and (4)

' '' '' 'J y y y H x x H y x H H x …………(6) For minimizing ( )x

J f we must satisfy the following condition.

0x

grad J …………………….(7)

It is easy to check that Eq.(7) leads to the following condition.

' ' 0H H x H y ………………….(8) This equation is called the “normal equation” and may be solved for the LSE of the vector

' 1 '( )x H H H y …………………….(9) Weighted Least Square Estimation (WLSE) Ordinary LSE is obtained by minimizing the index function that puts equal weightage to the errors of estimation of all components of the vector y. It is often desirable to put different weightage on the different components of y since some of the measurements may be more reliable and accurate than the others and these should be given more importance. To achieve this, we define the estimation index as

'J yW y ……………………………(10)

Where, W is a real symmetric weighting matrix of dimension m x m. (diagonal matrix). It is easy to extend the method of LSE to the weighted form of J & to derive the following form of the normal equation.

' ' 0H WH x H Wy ……………………….(10)

This leads to the desired weighted least squares estimate.

' 1 '( ) .x H WH H Wy ……………………..(11)



Exercise:

1) Considering the following data, obtain the LSE of variable x.

11

10

01

H ,

98.6

02.3

01.9

y

Find out WLSE by considering the weight matrix

1.000

010

001.0

W

,

Comment on the results obtained for x.

2) The measurement set and system model matrix is given as

9.01 0.625 0.125

3.02 0.125 0.625 and H=

6.98 0.375 0.125

5.01 0.125 0.375

y

Let us assign the weights w1=w2=100 and w3=w4=50. Compute the weighted LSE.

3) Prepare the MATLAB program for LSE and WLSE. Find out the values of x for above problems using the program.

Assignment:

1. What is state estimation? Explain the significance of state estimation for power system.

2. Explain the basic solution of Least Squared Estimation. What is the limitation of LSE?

3. Discuss the Weighted Least Squared Estimation in brief.




Aim: To study the effect of reactive power on voltage of the system using Powerworld Simulator. The voltage regulation may be defined as the per unit change in the sending end voltage magnitude for a specific variation in the receiving end voltage from no load to full load, and is caused by the drop in voltage due to passage of load current through the impedance. Thus the voltage regulation in p.u. for a simple transmission system shown below is given by

E VV

V

………………………….(1)

The vector diagram for this system is shown below.

From above vector diagram, the voltage regulation is given by

.V E V I Z ………(2) Where, I is the line current having the line impedance Z(=R+jX). Let us assume that V is the reference vector, Therefore,



*S P jQ

IV V

………………….(3) [S=V.I*]

Putting the values of I and Z in Equation (2),

( )

( ) ( )

P jQV R jX

VRP XQ XP RQ

V jV V

…………………………(4)

' ''V V j V ………………………..(5)

Where, ' ( )RP XQV

V

'' ( )XP RQV

V

Equation (5) reveals ΔV has two components 'V and ''V , out of which 'V is in phase with V

and has been represented by the geometric line ‘ab’, while ''V is in quadrature with V and represented by the line ‘bc’ in vector diagram. It may be noted that the magnitude and phase of V, relative to sending end voltage E, are governed by the magnitude and phase of line current I. This also indicates that the voltage regulation depends on both real and reactive power of the load connected at the receiving end. A minor alteration in the form of Equation (2) yields the voltage equation for a loss‐less line as

V E IX ………………..(6) Assuming the line to be loss‐less, the power at the sending end equals to that at receiving end. Hence Is, the sending end current (being equal to line current I when distributed line capacitance is neglected) is given by

( )s

P jQI I

E

…………………(7)

From Equation (6) and (7)

P jQV E j X

E



X XV E Q j P

E E ……………(8)

Equation (8) reveals that the real power P produces little effect on receiving end voltage phasor, since the drop associated with this change is in quadrature with the reference voltage. However, a change in reactive power load Q appreciably affects the receiving end voltage phasor since the drop associated with this change is in phase with the reference voltage. So, it can be concluded that the receiving end voltage is extremely sensitive to any change in reactive power status at the receiving end. Procedure:

1) Create a four bus system in PowerWorld Simulator.

2) Simulate the system for steady load (active and reactive) condition.

3) Note down various parameters (P,Q, V) at the load buses.

4) Change the active power demand of load and note down all the parameters.

5) Change the reactive power demand of the load and note down all the parameters.

6) Tabulate the results and draw the conclusion.

Assignment:

1. Derive expression for voltage regulation of a transmission line and show its relation with

reactive power.

2. For a 2‐bus system with a transmission line, derive expression for voltage regulation. Draw

corresponding phasor diagram and with the help of it show that there is strong

relationship between reactive power and the voltage drop along the line.




Aim: To understand the method of voltage control by tap‐changing transformer using PowerWorld Simulator By changing the transformation ratio, the voltage in the secondary side of any bus can be varied. Power transformers, being used extensively for the control of transmission and sub‐transmission voltage of a network utilizing this principle, may be either manual or automatic. The latter, usually called ‘On Load Tap Changers’ (OLTC) are usually arranged to regulate the bus voltage in order to keep the operating voltage of the regulated bus within acceptable limits. By changing the transformation ratio, the voltage in the secondary side of any bus can be varied and thus voltage control can be obtained. This constitutes the most popular and widespread form of voltage control at all voltage levels. The secondary voltage is maintained at or very near to nominal value by the operation of the tap changer, when the voltage of primary transmission system is reduced. This is feasible provided the system is not on the state of extreme shortage of reactive power. However, if load demand becomes excessively heavy, the secondary voltage may become unstable even with tap changing; the instability of the voltage is being basically due to reactive power shortage. Procedure:

Open Power World Simulator Software.

Simulate the system as shown in the figure according the problem statement.

Adjust the Transformer taps in discrete steps.

Click on arrows next to the transformer’s tap manually adjust the tap by one step.

Draw your own conclusion

Circuit Diagram:



Observation table: LTC Control Status = Manual Generator

VS (KV)

Transformer Vr (KV)

Load Transformer Tap position

MW

MVAr

VPrim. (KV)

VSec. (KV)

MW MVAr

Assignment:

1. What is voltage stability? Explain different types of voltage stability.

2. Discuss factors affecting voltage stability.




Aim: To study voltage control using Capacitor bank connected at the receiving end‐bus. The connection of shunt capacitors is the simplest and most widely used form of compensation. The installation of shunt capacitors at load bus provides shunt compensation. Due this, the voltage profile at the receiving end is improved as the part of reactive power demand of the load is met by the capacitor bank. However, care must be taken while designing the shunt compensator in the form of capacitor bank. Problem Statement: A 12MW/6MVAR load is supplied at 20kV through a feeder with an impedance of (a) 1 + j 2. The load is compensated with a capacitor bank whose output reactive power can be varied in 0.5 MVAR steps between 0 and 10 MVAR. Find out the feeder losses and other parameters. Circuit Diagram:

Procedure:

Open Power World Simulator Software. Simulate the system as shown in the figure according the problem statement. Set the line impedance to 1 +j 2 ohms and increase the load demand in steps of 1MW

from 5MW to 10MW.

Observe and record the change in values of sending end parameters and receiving end parameters.

Set the load at 5MW and change the reactive power supply from capacitor bank in steps of 1MVAR from 1 to 5 MVAR.



Observe and record the change in values of sending end parameters and receiving end parameters.

Repeat the procedure for line impedance 0.5 + j1 and 2 + j 4 ohms. Tabulate your results for all the cases. Make your own conclusion about the voltage and reactive power.

Assignment:

1. What is reactive power compensation? Explain reactive power compensation of redial

transmission line for; (1) On no load and (2) Heavy loading condition.

2. What is voltage collapse? State main factors contributing the voltage collapse.



Assignment: 1 Date: ___________

Aim: Assignment on Load Forecasting Techniques.

1) Write a short note on load forecasting.

2) Write a short note on load forecasting methodology.

3) Explain load forecasting methodology and estimation of average and trend terms.

4) Explain reactive load forecast.



Assignment: 2 Date: ___________

Aim: Assignment on Power System Restructuring.

1) Describe structure of vertically integrated utility in brief.

2) Explain the reasons for restructuring.

3) Describe structure of deregulated (restructured) power industry.

4) Write a short note on Indian scenario of power industry and electricity act 2003.

5) Write a short note on different entities in deregulated environment.

lab manual 180906 aps-ii

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