Module 6 : Preventive, Emergency and Restorative Control
Lecture 27 : Normal and Alert State in a Power System
Objectives
In this lecture you will learn the following
Different states in a power system
Schematic of Security Assesment Procedure
Preventive Re-scheduling of generation
A Power System in the Normal State
Once a system operator has the static estimate of all the system variables (voltage, current phase angular
differences), he may wish to check whether the state can be characterised as a normal, alert, or emergency
state.
While dynamic state information may also available, a system operator may not be able to directly utilize it
since the time frame to do so may be limited (for example loss of synchronism may take place within seconds
and even if an operator sees it happening, he may not be able to take corrective action). Therefore dynamic
measurements can be made use of mainly by automatic control or protection strategies.
For the time being we restrict our discussion to static state estimation.
If all the equipment 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.
By a potential contingency we do not mean that the contingency has occured, but has a finite chance of
occuring. The classification of secure and insecure is done by simulating (mimicking) contingencies on a
computer.
Normal and 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
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 contigency can impact the transient behaviour. For example, the
contingency could be due to a single phase to ground fault which results in protective action (circuit
b) 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 centres at present.
It is important to carefully choose the element whose outage is to be simulated since the number of elements in
a power system are too numerous for all of them to be considered one by one. Usually a set of critical elements
are chosen by some rough screening based on an operator's experience and the security analyses are carried out
for the outage of these elements.
, 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.
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 simulateneously ensuring security.
This is done using a security constrained optimal power flow program (discussed in the previous module).
Schematic of Security Assessment Procedure
A schematic of the procedure discussed in the previous slide is shown below.
An Example
Two Generators supply a load at bus 'C' via
transmission lines. It is assumed for
simplicity that voltages at all buses are
equal to the nominal value (1.0 pu). Also,
we assume that sin(ddiff) = ddiff and
cos(ddiff) = 1, where ddiff is the phase
angle difference between the voltages at
any 2 buses. This simplifies the circuit
Lecture 27 : Normal and Alert State in a Power System
Objectives
In this lecture you will learn the following
Different states in a power system
Schematic of Security Assesment Procedure
Preventive Re-scheduling of generation
A Power System in the Normal State
Once a system operator has the static estimate of all the system variables (voltage, current phase angular
differences), he may wish to check whether the state can be characterised as a normal, alert, or emergency
state.
While dynamic state information may also available, a system operator may not be able to directly utilize it
since the time frame to do so may be limited (for example loss of synchronism may take place within seconds
and even if an operator sees it happening, he may not be able to take corrective action). Therefore dynamic
measurements can be made use of mainly by automatic control or protection strategies.
For the time being we restrict our discussion to static state estimation.
If all the equipment 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.
By a potential contingency we do not mean that the contingency has occured, but has a finite chance of
occuring. The classification of secure and insecure is done by simulating (mimicking) contingencies on a
computer.
Normal and 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
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 contigency can impact the transient behaviour. For example, the
contingency could be due to a single phase to ground fault which results in protective action (circuit
b) 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 centres at present.
It is important to carefully choose the element whose outage is to be simulated since the number of elements in
a power system are too numerous for all of them to be considered one by one. Usually a set of critical elements
are chosen by some rough screening based on an operator's experience and the security analyses are carried out
for the outage of these elements.
, 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.
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 simulateneously ensuring security.
This is done using a security constrained optimal power flow program (discussed in the previous module).
Schematic of Security Assessment Procedure
A schematic of the procedure discussed in the previous slide is shown below.
An Example
Two Generators supply a load at bus 'C' via
transmission lines. It is assumed for
simplicity that voltages at all buses are
equal to the nominal value (1.0 pu). Also,
we assume that sin(ddiff) = ddiff and
cos(ddiff) = 1, where ddiff is the phase
angle difference between the voltages at
any 2 buses. This simplifies the circuit
