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Power System SecuritySyllabus:Introduction, factors affecting system security,
power system contingency analysis, and detection ofnetwork problems. Network sensitivity methods,
calculation of network sensitivity factor, connecting
generator dispatch by sensitivity methods, contingency
ranking.
INTRODUCTION
Security is an important aspect in the
successful operation of a power system.
System security involves many
precautions and practices suitably
designed, to keep the system operating,
when any of its components fail.
Apart from economizing the fuel costand minimizing emission of gases like
, , etc., the power
system should be operationally secure.
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An operationally secure power system
is one with low probability of system
collapse or equipment damage.
If the failures are cascaded, the system as
a whole or its major parts may
completely collapse.
This state of the system is normally
referred to as blackout.
All these aspects are dealt in the security
constrained power system optimization(SCO).
Since security and economy normally
have conflicting requirements, it is
inappropriate to treat them separately.They have to be dealt with together.
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Incorporating security function, the
utility company has to aim at economic
operation.
The energy management system (EMS)
has to operate the system at minimum
cost, with the guaranteed alleviation
(reduction) of emergency conditions.
The emergency condition will depend on
the severity of violations of operating
limits like, branch flows and bus voltage
limits etc,. The most severe violations
result from contingencies.
Therefore, an important part of security
study revolves around the powersystems ability to withstand the effects
of contingencies.
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A particular system state is said to be
secure only with reference to one or more
specific contingency cases and a given
set of quantities monitored for violation.
Most power systems are operated in such
a way that any single contingency will
not leave other components heavily
overloaded, so that cascading of failures
are avoided.
Most of the security related functions
deal with static snapshots of the power
system. They have to be executed at
intervals compatible with the rate of
change of system state.
This quasi-static approach is, to a large
extent, the only practical approach at
present, since dynamic analysis and
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optimization are considerably more
difficult and computationally more time
consuming.
System security comprises of three major
functions carried out in an energy control
centre. They are,
(i) system monitoring,
(ii) contingency analysis, and
(iii) corrective action analysis.
(i) System monitoring: System
monitoring supplies the power system
operators or power dispatchers with
pertinent up to date information on the
conditions of the power system on real
time basis as load and generation change.
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In every substation, telemetry systems
measure, monitor and transmit the data
like, voltages, currents, frequency,
current flows, generator outputs,
transformer tap positions, the status of
circuit breakers & switches in a
transmission network. Digital computers
then process the telemetered data and
place them in a data base form and
inform the operators in case of an
overload or out of limit voltage.Important data are also displayed on
large size monitors. Alarms or warnings
are also given if required.
State estimation techniques are normally
used to combine telemetered data to give
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the best estimate (in statistical sense) of
the current system condition or state.
Such systems often work with
supervisory control systems to help
operators to control, circuit breakers,
operate switches and taps remotely.
These systems together are called
SCADA (supervisory control and data
acquisition) systems.
(ii) Contingency analysis: This is the
second major security function. Modern
computers installed in power station have
contingency analysis programs stored in
them. These programs foresee the
possible system outages before they
occur and alert the operators to any
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potential overloads or serious voltage
violations.
For each outage to be studied, along with
the procedures to set up the load flow
data combined with a standard LF
program, a simplest form of contingency
analysis is employed.
This allows the system operators to
locate defensive operating states where
no single contingency event will generate
overloads and/or voltage violations.
Operating constraints which may be
employed in the ED (economic dispatch)
and UC (unit commitment) programs canbe evolved from this analysis. Thus
contingency analysis carries out
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emergency identification and what if
simulations.
(iii) Corrective action analysis: This is
the third major security function. This
enables the operator to change the
operation of the power system if a
contingency analysis program predicts a
serious problem in the event of the
occurrence of a certain outage.
Thus it provides preventive and post-
contingency control.
A simple example of corrective action is
the shifting of generation from one
station to another. This may result inchange in power flows and causes a
change in loading on overloaded lines.
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Thus, the three functions, (i) system
monitoring, (ii) contingency analysis,
and (iii) corrective action analysis
together consist of a very complex set of
tools that help in the secured operation of
a power system.
Power System State
Classification /
Power System Static Security
Levels
A formal classification of power system
security levels to define relevant
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functions of the Energy Management
System (EMS) was developed initially.
Then, a more practical static security
level diagram by incorporating
correctively secure (Level 2) and
correctable emergency security levels
(Level 4) was developed. The figure
below shows such a practical static
security level diagram.
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Arrowed lines represent involuntarytransitions between Levels 1 to 5 due to
contingencies.
Levels 1 and 2 represent normal power
system operation.Level 1 has the ideal security but is too
conservative and costly. The power
system survives any of the credible
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contingencies without relying on any
post-contingency corrective action.
Level 2 is more economical, but depends
on post-contingency corrective
rescheduling to alleviate (reduce)violations without loss of load, within a
specified period of time. Post
contingency operating limits might be
different from their pre-contingency
values.
The removal of violations from Level 4
normally requires EMS directed
corrective rescheduling or remedialaction bringing the system to Level 3,
from where it can return to either Level 1
or 2 by further EMS directed preventive
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rescheduling depending upon the
desired operational security objectives.
Power System Operating
States
More than 99% of the time, the power
system is found in its normal state. The
system is said to be in normal state if,
(i)
all the loads are met,(ii) the frequency and bus voltage
magnitudes are within the
prescribed limits and
(iii) no components of the powersystem are overloaded.
Secure Normal State: The equality
between generation and demand is a
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fundamental prerequisite for system
normalcy and is indicated by the symbol
E. E refers to equality constraints i.e.,
the power balance and flow equations are
satisfied and frequency and voltage
constancy observed.
Certain inequality must also be observed
in the normal state.
The symbol I refer to inequality
constraints and imply that the system is
operating within rated limits of the
components i.e., generator and
transformer loads must not exceed the
rated values and transmission lines must
not be loaded above their thermal or
static stability limit.
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Insecure normal state: If a system
suffers from any event like, sudden
increase of load, its security level
reduces. Then the system would switch
to insecure normal state. The E and
I would still be satisfied.
However, with preventive control
strategy, the operator takes control
actions to return the system to its normal
state.
Emergency State: In the insecure
normal state, if some additional
disturbance occurs or in normal state a
major disturbance is encountered (e.g.,
tripping of tie line or loss of an additional
generator), then the system will enter to
emergency state.
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In this state the system remains intact,
i.e., E is still satisfied but I change to
, (e.g., overloads of system
components). The subscript v refers to
the constraint violation.
By means of corrective control (like
generator rescheduling) the operator
would try to relieve the transition due to
normal state overload situations. If
corrective control is not possible, then
emergency control (like, generator major
rescheduling / load shedding) is restored
to.
Cascade State: If the emergency control
fails, then a series of cascading events
may lead to the cascade (extreme) state.
Typically, the system would breakup into
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islands, each of which would be
operating at their own frequencies. Both
E and I would then changes to Ev
and Iv respectively and the system will
result in a blackout.
Restorative State: A series of
resynchronization controls are required
to restart generators and gradually
generators pickup the loads. This is a
long process and the state of the system
is called restorative state. The various
transitions due to disturbances, as well as
various control actions are shown in the
figure below.
In practice, the power system never
remains in the normal state due to
disturbances. Hence, preventive /
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corrective control actions are required to
bring back the system to the normal state.
(Various operating states and control actions of a power
system)
SECURITY ANALYSIS
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System security is monitored at the
energy control centre by carrying out two
major functions. They are,
(i) Security assessment whichgives the security level of the
system operating state.
(ii) Security control .whichdetermines the appropriate security
constrained scheduling required to
optimally attain the target security
level.
These security functions can be executed
in real time and study modes.
Real time application functions requirehigh computing speed and reliability.
The static security level of a power
system is characterized by the presence
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of emergency operating conditions (limit
violations) in its actual (pre-contingency)
or potential (post-contingency) operating
states.
System security assessment is the process
by which any such violations are
detected.
System security assessment further
involves two functions.
(i) system monitoring and(ii) contingency analysis.System monitoring provides the operator
with pertinent up to date information on
the current conditions of the powersystem. In its simplest form, this just
detects violations in the actual system
operating state.
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Contingency analysis is much more
demanding and normally performed in
three distinct states
i. contingency definition,ii.
contingency selection and
iii. contingency evaluation.
Contingency definition: This gives the
list of contingencies to be processedwhose probability of occurrence is high.
This list, which is usually large, is in
terms of network changes. i.e., branch
and/or injection outages. Thesecontingencies are ranked in rough order
of severity employing contingency
selection algorithms to shorten the list.
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Not much accuracy is required in the
results. Therefore an approximate (linear)
system model where results are obtained
at high speed is used.
Contingency evaluation is then
performed (using AC power flow) on the
successive individual cases in decreasing
order of severity. The evaluation process
is continued up to the point where no
post-contingency violations are
encountered.
Hence, the purpose of contingency
analysis is to identify the list of
contingencies that, if occur, would create
violations in system operating states.
They are ranked in the order of severity.
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Security control: It is the secondmajor security function. It allows the
operator to change the power system
operation, if the contingency analysis
program predicts a serious problemindicating that certain outage may occur.
Normally the security control is achieved
through Security Constrained
Optimization (SCO) program.
Modeling for Contingency
Analysis
Limits on line flows and bus voltages are
of most interest in contingency analysis.
Since these are soft limits, developing
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limited accuracy models and solutions
are justified.
The most fundamental approximate load
flow model is the NR model shown
below.
The normally preferred DC load flow
model in its incremental version is shown
below.
This model assumes voltages to remain
constant after contingencies. However,
this is not true for weak systems. The
utility has to pre-specify whether it wants
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to monitor post-contingency steady
state conditions immediately after the
outage (system inertial response) or after
the automatic controls (governor, AGC,
ED) have responded. Depending upon
this decision, different participation
factors are used to allocate the MW
generation among the remaining units.
The reactive problem tends to be more
nonlinear and voltages are also
influenced by active power flows.
FDLF is normally the best for this
purpose since its Jacobian matrix isconstant and single line outages can be
modeled using the matrix inversion
lemma.
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The model often used is
Contingency Selection
There are two main approaches for
selection.
Direct Methods
These involve screening and directranking of contingency cases. They
monitor the appropriate post-contingent
quantities (flows, voltages). The severity
measure is often a performance index.Indirect Methods
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These give the values of the contingency
case severity indices for ranking, without
calculating the monitored contingent
quantities directly.
Simulation of line outage is more
complex than a generator outage, since
line outage results in a change in system
configurations. The inverse matrix
modification lemma (IMML) or
compensation method is used
throughout the contingency analysis
field. The IMML helps in calculating the
effects of network changes due to
contingencies, without reconstructing
and re-factorizing or inverting the base
case network matrix. It is also possible to
achieve computational economy by
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getting only local solutions by
calculating the inverse elements in the
vicinity of the contingencies. The
question is how far one should go. Some
form of sensitivity analysis may be used.
The problem of studying hundreds of
possible outages becomes very difficult
to solve if it is desired to present the
results quickly so that corrective actions
can be taken. One of the simplest ways of
obtaining a quick calculation of possible
overloads is to use network sensitivity
factors. These factors show the
approximate change in line flows for
changes in generation on the network
configuration and are derived from DC
load flow.
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They are of two types.
1. Generation shift distribution factors
2. Line outage distribution factors
In a practical situation when a
contingency causing emergency occurs,
control action to alleviate (reduce) limitviolations is always taken, if such a
capability exists and a protective system
permits time to do so.
The security control function (which isnormally achieved by SCO) responds to
each insecure contingency case, usually
in decreasing order of severity by
1. Rescheduling the pre-contingencyoperating state to alleviate the
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emergency resulting from the
contingency, and/or
2. Developing a post-contingencycontrol strategy that will eliminate
the emergency, or
3. Taking no action, on the basis thatpost-contingency emergency is
small and/or probability of its
occurrence is very low.
A specific security control function, then,
is designed to
1. Operate in real time or study mode.2. Schedule active or reactive power
controls or both
3. Achieve a defined security level4. Minimize a defined operational
objective.
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So far, only a small proportion of
network on optimal power flow has taken
into account the security constraints.
The most successful applications are to
the security constrained MW dispatch
OPF sub-problem.
The contingency constrained
voltage/VAR rescheduling problem still
remains to be solved to a satisfactory
degree.
The total number of contingency
constraints imposed on SCO is
enormous. The SCO or contingency
constrained OPF problem is solved withor without first optimizing with respect
to the base case (pre-contingency)
constraints.
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The general procedure adopted is as
follows.
1. Contingency analysis is carried outand cases with violations or near
violations are identified.
2. The SCO problem is then solved.3. The rescheduling in Step 1 might
have created new violations and
therefore Step 1 should be repeated
till no violations exist.
Hence, SCO represents a potentially
massive additional computing effort.
There is still great potential for further
improvement in power system security
control.
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Better problem formulations, theory,
computer solution methods and
implementation techniques are required.
CONTINGENCY ANALYSIS
In the past many widespread blackouts
have occurred in interconnected power
systems.
Therefore, it is necessary to ensure thatpower systems should be operated most
economically such that power is
delivered reliably.
Reliable operation implies that there isadequate power generation and the same
can be transmitted reliably to the loads.
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Most power systems are designed with
enough redundancy (flexibility) so that
they can withstand all major failure
events.
Here, the possible consequences of the
two main failure events and the remedial
actions required for them are explained.
The events are,
1. line outages and2. generating unit failures.
To explain the problem briefly, consider
the five bus system with its load flow
results shown below.
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AC line f low for sample 5 bus system
A power flow of 24.7 MW and 3.6
MVAR on the line from bus 2 to bus 3can be seen.
At present, only the MW loading of the
line is considered.
Simulation of line outage is more
complex than a generator outage, since
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line outage results in a change in system
configurations.
Examine what will happen if the line
from bus 2 to bus 4 were to open. The
resulting line flows and voltages are
shown in line diagram below.
Post-outage AC Load F low (L ine between 2and 4 is open)
It may be noted that the flow on the line
2 to 3 has increased to 37.5 MW and that
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most of the other line flows are also
changed. It may also be noted that bus
voltage magnitudes also get affected,
particularly at bus 4, the change is almost
2% less from 1.0236 to 1.0068 pu.
Suppose the line from bus 2 to bus 5
were to open. Now the maximum change
(almost 10%) in voltage is seen at bus 5.
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Post-outage AC Load F low (L ine between 2
and 5 is open)
Line diagram below is an example of
generator outage and is selected to
explain the fact that generator outages
can also result in changes in line flows
and bus voltages.
Post-outage AC Load Flow (Generator 2
outage, lost generation is picked up by
generator 1)
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In the above case, all the generation lost
from bus 2 is picked up on the generator
at bus 1. Had there been more than 2
generators in the sample system say at
bus 3 also, it was possible that the loss of
generation on bus 2 is made up by an
increase in generation at buses 1 and 3.
The differences in line flows and bus
voltages would show how the lost
generation is shared by the remaining
units is quite significant.
It is important to know which line or unit
outages will render line flows or voltages
to cross the limits.
To find the effects of outages,
contingency analysis techniques are
employed. Contingency analysis models,
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single failure events i.e., one line outages
or one unit outages) or multiple
equipment failure events (failure of
multiple unit or lines or their
combination) one after another until all
credible outages are considered.
For each outage, all lines and voltages in
the network are checked against their
respective limits.
The flow chart below illustrates the
method for carrying out a contingency
analysis.
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One of the important problems is the
selection of all credible outages.
Execution time to analyze several
thousand outages is typically 1 min. An
approximate model such as DC load flow
may be used to get speedy solution. If
voltage is also required, then full AC
load flow analysis has to be carried out.
SENSITIVITY FACTORS
A security analysis program is run in a
load dispatch centre of power system.
The program is run very quickly to help
the system operators. Speedy analysis
can be done by developing an
approximate system model and using a
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computer having multiple processors or
vector processors. The system may be
adequately described. An equivalent
should be used for neighboring systems
connected through tie-lines.
All non-violation cases are eliminated
and complete exact program is run for
critical cases only. This can be done by
using techniques such as contingency
selection or contingency screening or
contingency ranking.
Thus, it will be easy to warn the system
operators in advance and alert them to
take corrective action if one or more
outages result in serious overloads or any
violations.
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One of the simplest ways to present a
quick calculation of possible overloads is
to employ linear network sensitivity
factors. These factors give the
approximate change in line flows for
changes in generation in the system and
can be calculated from the DC load flow.
Sensitivity factors are mainly of two
types.
1. Generation shift factors2. Line outage distribution factors
Use of these factors is described below.
1. The generation shift factors
These are denoted by and are definedas
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where,
= Change in MW power flow on line
when a change in generation,
takes place at the
bus.Here, it is assumed that is fully
compensated by an equal and opposite
change in generation at the slack
(reference) bus, with all other generatorsremaining fixed at their original power
generations. The factor then gives the
sensitivity of the line flow to a
change in generation at
bus.
Now, let a large generating unit outage
occurs and assume that all the lost
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generation would be supplied by the
slack bus generation. Then,
and the new power flow on each line
could be calculated using a pre-
calculated set of factors as givenbelow.
The values of line flows obtained from
this equation can be compared to theirlimits and those violating their limit can
be informed to the operator for necessary
control action.
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The generation shift sensitivity factors
are linear estimates of the change in line
flow with a change in power at a bus.
Thus, the effects of simultaneous
changes on a given number of generating
buses can be computed using the
principle of superposition.
Assume that the loss of the generator
is to be made up by governor action on
all generators of the interconnected
system and pick up in proportion to their
maximum MW ratings.
Thus, the proportion of generation pick
up from unit k (k i) would be
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where,
= maximum MW rating for
generator
= proportionality factor for pick up
on unit when unit fails.
Now, for checking the line flow, the
flow equation is,
In the equation, it is assumed that no unit
will violate its maximum limit. For unit
limit violation, algorithm can easily be
modified.
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Line outage distribution
factorsThe line outage distribution factors can
be used for checking if the line overloads
when some of the other lines are lost.
The line outage distribution factor is
defined as,
where,
= line outage distribution factor
when monitoring line after an outage
of line.
= change in MW flow on line.
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= pre-contingency line flow on
line.If pre-contingency line flows on lines 1
and i, the power flow on line l with line i
can be found out employing d factors.
Here,
= pre-contingency or pre-outage flows on lines l and i
respectively,
= power flow on
line with
lineout.
Thus one can check quickly by pre-
calculating d factors for all the lines for
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overloading for the outage of a particular
line. This can be repeated for the outage
of each line one by one and overloads
can be found out for corrective action.
Note that a line flow can be positive or
negative. Hence, f should be checked
against as well as . Line
flows can be found out using telemetry
systems or with state estimation
techniques.If the network undergoes any significant
structural change, the sensitivity factors
must be updated.
Example: Find the generation shiftfactors and the line outage distribution
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factors for the five bus sample network
discussed earlier.
Solution:
Table 1. The [x] matrix for the five bus
sample system. Bus 1 is reference.
Table 2. The generation shift distributionfactors.
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Table 3. The line outage distribution
factors.
The line flows calculated by the
sensitivity methods, are reasonably close
to the values calculated by the full AC
load flows. However, the calculations
carried out by sensitivity methods are
faster than those made by full AC load
flow methods. Therefore they are used
for real time monitoring and control of
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power systems. However, where reactive
power flows are mainly required, a full
AC load flow method (NR / FDLF) is
preferred for contingency analysis.
The simplest AC security analysis
procedure merely needs to run an AC
load flow analysis for each possible unit,
line and transformer outage. One
normally does ranking or short listing of
most likely bad cases which are likely to
result in an overload or voltage limit
violation and other cases need not be
analyzed. Any good PI (performance
index) can be selected and is used for
ranking. One such PI is
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For large n, PI will be a small number if
all line flows are within limit and will be
large if one or more lines are overloaded.
For n = 1 exact calculations can be done
for PI. PI table can be ordered from
largest value to least. Suitable number of
candidates then can be chosen for further
analysis.
If voltages are to be included, then the
following PI can be employed.
Here, is the difference betweenthe voltage magnitudes as obtained at the
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end of the 1P1Q FDLF algorithm.
is the value fixed by the utility.Largest value of PI is placed at the top.
The security analysis may now be started
for the desired number of cases down the
ranking list.
8.7 POWER SYSTEM SECURITY
By power system security, we understand a qualified
absence of risk of disruption of continued system
operation. Security may be defined from a control point of
view as the probability of the system's operating point
remaining in a viable state space, given the probabilities
of changes in the system (contingencies) and its
environment (weather, customer demands, etc.).
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Security can be defined in terms of how it is monitored or
measured, as the ability of a system to withstand without
serious consequences any one of a preselected list of
credible disturbances (contingencies). Conversely,insecurity at any point in time can be defined as the level
of risk of disruption of a system's continued operation.
Power systems are interconnected for improved economy
and availability of supplies across extensive areas. Small
individual systems would be individually more at risk, but
widespread disruptions would not be possible.
On the other hand, interconnections make widespread
disruptions possible.
Operation of interconnected power systems demands
nearly precise synchronism in the rotational speed of
many thousands of large interconnectedgenerating units, even as they are controlled to
continuously follow significant
changes in customer demand. There is considerable
rotational energy involved,
and the result of any cascading loss of synchronism
among major systemelements or subsystems can be disastrous.
Regardless of changes in system load
or sudden disconnection of equipment from the
system, synchronized operation
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requires proper functioning of machine governors,
and that operating conditions
of all equipment remain within physical capabilities.
The risk of cascading outages still exists, despite
improvements made
since the 1965 northeast blackout in the United
States. Many factors increase
the risks involved in interconnected system
operation:
Wide swings in the costs of fuels result in
significant changes in
the geographic patterns of generation relative to
load. This leads to
transmission of electric energy over longer distances
in patterns
other than those for which the transmission networks
had been
originally designed.
Rising costs due to inflation and increasing
environmental
concerns constrain any relief through further
transmission
construction. Thus, transmission, as well as
generation, must be
operated closer to design limits, with smaller safety
(security)
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margins.
Relaxation of energy regulation to permit sales of
electric energy
by independent power producers, together with
increasing pressure
for essentially uncontrolled access to the bulk power
transmission
network.
Development of the Concept of SecurityPrior to the 1965 Northeast blackout, system
security was part of
reliability assured at the system planning stage by
providing a strong system that
could ride out any credible disturbances without
serious disruption. It is no
longer economically feasible to design systems to
this standard. At that time,
power system operators made sure that sufficient
spinning reserve was on line to
cover unexpected load increases or potential loss of
generation and to examine
the impact of removing a line or other apparatus formaintenance. Whenever
possible, the operator attempted to maintain a
desirable voltage profile by
balancing VARs in the system.
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Security monitoring is perceived as that of
monitoring, through
contingency analysis, the conditional transition of
the system into an emergency
state.
Two Perspectives of Security AssessmentThere is a need to clarify the roles of security
assessment in the