29-05-2012, 01:57 PM
A NOVEL APPROACH OF LOAD FREQUENCY CONTROL IN MULTI AREA POWER SYSTEM
[attachment=23348]
Abstract:
The main objective of Load Frequency Control(LFC) is to regulate the power output of the electric generator within an area in response to changes in system frequency and tie-line loading. Thus the LFC helps in maintaining the scheduled system frequency and tie-line power interchange with the other areas within the prescribed limits. Most LFCs are primarily composed of an integral controller. The integrator gain is set to a level that the compromises between fast transient recovery and low overshoot in the dynamic response of the overall system. This type of controller is slow and does not allow the controller designer to take in to account possible changes in operating condition and non-linearity’s anthem generator unit. Moreover, it lacks in robustness. Therefore the simple neural networks can alleviate this difficulty. This paper presents the Artificial Neural Network (ANN) is applied to self tune the parameters of PID controller. Multi area system, have been considered for simulation of the proposed self tuning ANN based PID controller .The performance of the PID type controller with fixed gain, Conventional integral controller, and ANN based PID controller have been compared through MATLAB Simulation results carried out by 1% system disturbances both single area in multi area power system .Comparison of performance responses of integral controller & PID controller show that the neural network controller has quite satisfactory generalization capability, feasibility and reliability, as well as accuracy in both single and multi area system. The qualitative and quantitative comparisons have been carried out for Integral, PID and ANN controllers. The superiority of the performance of ANN over integral and PID controller is highlighted.
Keywords: Power system, Artificial Neural network, Back propagation algorithm, PID Controllers
I.INTRODUCTION
In electric power generation, system disturbances caused by load fluctuations result in changes to
the desired frequency value. Load Frequency Control (LFC) is a very important issue in power system operation and control for supplying sufficient and both good quality and reliable power. Power networks consist of a number of utilities interconnected together and power is exchanged between the utilities over the tie-lines by which they are connected. The net power flow on tie-lines is scheduled on a priori contract basis. It is therefore important to have some degree of control over the net power flow on the tie-lines. Load Frequency Control (LFC) allows individual utilities to interchange power to aid in overall security while allowing the power to be generated most economically. The variation in Load frequency is an index for normal operation of the power systems. When the load perturbation takes place, it will affect the frequency of other areas also. In order to control frequency of the power systems various controllers are used in different areas, but due to the non-linearity in system components and alternators, these conventional feedback controllers could not control the frequency quickly and efficiently.
2. PROBLEM FORMULATION
In order to keep the power system in normal operating state, a number of controllers are used in
Practice. As the demand deviates from its normal operating value the system state changes. Different types of controllers based on classical linear control theory have been developed in the past. Because of the inherent nonlinearities in system components and synchronous machines, neural network techniques are considered to build non-linear ANN controller with high degree of performance.
Most load frequency controllers are primarily composed of an integral controller. The integrator
gain is set to a level that compromise between fast transient recovery and low overshoot in the dynamic response of the overall system. This type of controller is slow and does not allow the controller designer to take into account possible non-linearity’s in the generator unit.
2.1 Objectives of LFC:
In order to regulate the power output of the electric generator within a prescribed area in response to changes in system frequency, tie line loading so as to maintain the scheduled system frequency and interchange with the other areas within the prescribed limits.
3. MODELING OF SINGLE AREA AND MULTI AREA POWER SYSTEMS
3.1Single Area System Modeling
In Single area system, generation and load demand of one domain is dealt. Any load change
Within the area has to be met by generators in that area alone through suitable governor action. Thus we can maintain the constant frequency operation irrespective of load change.
3.2 Generator Model
A single rotating machine is assumed to have a steady speed of ω and phase angle δ0. Due to
Various electrical or mechanical disturbances, the machine will be subjected to differences in mechanical and electrical torque, causing it to accelerate or decelerate. We are mainly interested in the deviations of speed, Δω, & and deviations in phase angle Δδ, from nominal.
This can be expressed in Laplace transform operator notation as
ΔPmech - ΔPelec = M s Δω (1.11)
Equation (1.11) can be represented as shown in figure
3.3 Load Model
The load on a power system comprises of a variety of electrical devices. Some of them are purely
Resistive. Some are motor loads with variable power frequency characteristics, and others exhibit quite different characteristics. Since motor loads are a dominant part of the electrical load, there is a need to model the effect of a change in frequency on the net load drawn by the system. The relationship between the changes in load due to the change in frequency is given by
ΔPL (freq) = D Δω (or)
D = ΔPL (freq) / Δω (1.12)
The net change in Pelec in figure ( 1.1 ) is
ΔPelec = ΔPL + D Δω
No frequency frequency
Sensitive load sensitive load
Change change
Incorporating this in the figure2,
3.4 Prime-Mover Model
The prime mover driving a generator unit may be a steam turbine or a hydro turbine. The models
for the prime mover must take account of the steam supply and boiler control system characteristics in the case of a steam turbine, or the penstock characteristics for a hydro turbine. Here only the simplest prime-mover model, the non reheat turbine, is considered. The model for a non reheat turbine shown in figure 1.3, relates the position of the valve that controls emission of steam into the turbine to the power output of the turbine.
3.5 Governor Model
Suppose a generating unit is operated with fixed mechanical power output from the turbine, the
result of any load change would be a speed change sufficient to cause the frequency-sensitive load to exactly compensate for the load change. This condition would allow system frequency to drift far outside acceptable limits. This is overcome by adding mechanism that senses the machine speed, and adjusts the input valve to change the mechanical power output to compensate for load changes and to restore frequency to nominal value. The earliest such mechanism used rotating “fly balls” to sense speed and to provide mechanical motion in response to speed changes. Modern governors use electronic means to sense speed changes and often use a combination of electronic, mechanic and hydraulic means to effect the required valve position changes. The simplest governor, is synchronous governor, adjusts the input valve to a point that brings frequency back to nominal value. If we simply connect the output of the speed-sensing mechanism to the valve through a direct linkage, it would never bring the frequency to nominal. To force the frequency error to zero, one must provide reset action. Reset action is accomplished by integrating the frequency (or speed) error, which is the difference between actual speed and desired or reference speed. Speed-governing mechanism with diagram shown in figure 1.6.1.5 The speed-measurement device’s output, ω, is compared with a reference, ωref , to produce an error signal, Δω.The error, Δω, is negated and then amplified by a gain KG and integrated to produce a control signal, ΔPvalve , which cause main steam supply valve to (ΔPvalve position) when Δω is negative. If, for example, the machine is running at reference speed and the electrical load increases, ω will fall below ωref andΔω will be negative. The action of the gain and integrator will be to open the steam valve, causing the turbine to increase its mechanical output, thereby increasing the electrical output of the generator and increasing the speedω. When ω exactly equals ωref, the steam valve the new position (further opened) to allow the turbine generator to meet the increased electrical load. The synchronous (constant speed) governor cannot be used if two or more generators are electrically connected to the same system since each generator would have to have precisely the same speed setting or they would fight each other, each trying to pull the system’s speed (or frequency) to its own setting. To run two or more generating units in parallel, the speed governors are provided with a feedback signal that causes the speed error to go to zero at different values of generator output.
The result of adding the feedback loop with gain R is a governor characteristic as shown in
figure5. The value of R determines the slope of the characteristic. That is, R determines
the change on the unit’s output for a given change in frequency.
[attachment=23348]
Abstract:
The main objective of Load Frequency Control(LFC) is to regulate the power output of the electric generator within an area in response to changes in system frequency and tie-line loading. Thus the LFC helps in maintaining the scheduled system frequency and tie-line power interchange with the other areas within the prescribed limits. Most LFCs are primarily composed of an integral controller. The integrator gain is set to a level that the compromises between fast transient recovery and low overshoot in the dynamic response of the overall system. This type of controller is slow and does not allow the controller designer to take in to account possible changes in operating condition and non-linearity’s anthem generator unit. Moreover, it lacks in robustness. Therefore the simple neural networks can alleviate this difficulty. This paper presents the Artificial Neural Network (ANN) is applied to self tune the parameters of PID controller. Multi area system, have been considered for simulation of the proposed self tuning ANN based PID controller .The performance of the PID type controller with fixed gain, Conventional integral controller, and ANN based PID controller have been compared through MATLAB Simulation results carried out by 1% system disturbances both single area in multi area power system .Comparison of performance responses of integral controller & PID controller show that the neural network controller has quite satisfactory generalization capability, feasibility and reliability, as well as accuracy in both single and multi area system. The qualitative and quantitative comparisons have been carried out for Integral, PID and ANN controllers. The superiority of the performance of ANN over integral and PID controller is highlighted.
Keywords: Power system, Artificial Neural network, Back propagation algorithm, PID Controllers
I.INTRODUCTION
In electric power generation, system disturbances caused by load fluctuations result in changes to
the desired frequency value. Load Frequency Control (LFC) is a very important issue in power system operation and control for supplying sufficient and both good quality and reliable power. Power networks consist of a number of utilities interconnected together and power is exchanged between the utilities over the tie-lines by which they are connected. The net power flow on tie-lines is scheduled on a priori contract basis. It is therefore important to have some degree of control over the net power flow on the tie-lines. Load Frequency Control (LFC) allows individual utilities to interchange power to aid in overall security while allowing the power to be generated most economically. The variation in Load frequency is an index for normal operation of the power systems. When the load perturbation takes place, it will affect the frequency of other areas also. In order to control frequency of the power systems various controllers are used in different areas, but due to the non-linearity in system components and alternators, these conventional feedback controllers could not control the frequency quickly and efficiently.
2. PROBLEM FORMULATION
In order to keep the power system in normal operating state, a number of controllers are used in
Practice. As the demand deviates from its normal operating value the system state changes. Different types of controllers based on classical linear control theory have been developed in the past. Because of the inherent nonlinearities in system components and synchronous machines, neural network techniques are considered to build non-linear ANN controller with high degree of performance.
Most load frequency controllers are primarily composed of an integral controller. The integrator
gain is set to a level that compromise between fast transient recovery and low overshoot in the dynamic response of the overall system. This type of controller is slow and does not allow the controller designer to take into account possible non-linearity’s in the generator unit.
2.1 Objectives of LFC:
In order to regulate the power output of the electric generator within a prescribed area in response to changes in system frequency, tie line loading so as to maintain the scheduled system frequency and interchange with the other areas within the prescribed limits.
3. MODELING OF SINGLE AREA AND MULTI AREA POWER SYSTEMS
3.1Single Area System Modeling
In Single area system, generation and load demand of one domain is dealt. Any load change
Within the area has to be met by generators in that area alone through suitable governor action. Thus we can maintain the constant frequency operation irrespective of load change.
3.2 Generator Model
A single rotating machine is assumed to have a steady speed of ω and phase angle δ0. Due to
Various electrical or mechanical disturbances, the machine will be subjected to differences in mechanical and electrical torque, causing it to accelerate or decelerate. We are mainly interested in the deviations of speed, Δω, & and deviations in phase angle Δδ, from nominal.
This can be expressed in Laplace transform operator notation as
ΔPmech - ΔPelec = M s Δω (1.11)
Equation (1.11) can be represented as shown in figure
3.3 Load Model
The load on a power system comprises of a variety of electrical devices. Some of them are purely
Resistive. Some are motor loads with variable power frequency characteristics, and others exhibit quite different characteristics. Since motor loads are a dominant part of the electrical load, there is a need to model the effect of a change in frequency on the net load drawn by the system. The relationship between the changes in load due to the change in frequency is given by
ΔPL (freq) = D Δω (or)
D = ΔPL (freq) / Δω (1.12)
The net change in Pelec in figure ( 1.1 ) is
ΔPelec = ΔPL + D Δω
No frequency frequency
Sensitive load sensitive load
Change change
Incorporating this in the figure2,
3.4 Prime-Mover Model
The prime mover driving a generator unit may be a steam turbine or a hydro turbine. The models
for the prime mover must take account of the steam supply and boiler control system characteristics in the case of a steam turbine, or the penstock characteristics for a hydro turbine. Here only the simplest prime-mover model, the non reheat turbine, is considered. The model for a non reheat turbine shown in figure 1.3, relates the position of the valve that controls emission of steam into the turbine to the power output of the turbine.
3.5 Governor Model
Suppose a generating unit is operated with fixed mechanical power output from the turbine, the
result of any load change would be a speed change sufficient to cause the frequency-sensitive load to exactly compensate for the load change. This condition would allow system frequency to drift far outside acceptable limits. This is overcome by adding mechanism that senses the machine speed, and adjusts the input valve to change the mechanical power output to compensate for load changes and to restore frequency to nominal value. The earliest such mechanism used rotating “fly balls” to sense speed and to provide mechanical motion in response to speed changes. Modern governors use electronic means to sense speed changes and often use a combination of electronic, mechanic and hydraulic means to effect the required valve position changes. The simplest governor, is synchronous governor, adjusts the input valve to a point that brings frequency back to nominal value. If we simply connect the output of the speed-sensing mechanism to the valve through a direct linkage, it would never bring the frequency to nominal. To force the frequency error to zero, one must provide reset action. Reset action is accomplished by integrating the frequency (or speed) error, which is the difference between actual speed and desired or reference speed. Speed-governing mechanism with diagram shown in figure 1.6.1.5 The speed-measurement device’s output, ω, is compared with a reference, ωref , to produce an error signal, Δω.The error, Δω, is negated and then amplified by a gain KG and integrated to produce a control signal, ΔPvalve , which cause main steam supply valve to (ΔPvalve position) when Δω is negative. If, for example, the machine is running at reference speed and the electrical load increases, ω will fall below ωref andΔω will be negative. The action of the gain and integrator will be to open the steam valve, causing the turbine to increase its mechanical output, thereby increasing the electrical output of the generator and increasing the speedω. When ω exactly equals ωref, the steam valve the new position (further opened) to allow the turbine generator to meet the increased electrical load. The synchronous (constant speed) governor cannot be used if two or more generators are electrically connected to the same system since each generator would have to have precisely the same speed setting or they would fight each other, each trying to pull the system’s speed (or frequency) to its own setting. To run two or more generating units in parallel, the speed governors are provided with a feedback signal that causes the speed error to go to zero at different values of generator output.
The result of adding the feedback loop with gain R is a governor characteristic as shown in
figure5. The value of R determines the slope of the characteristic. That is, R determines
the change on the unit’s output for a given change in frequency.