this power point give u the know how to analyze the contingency and system security in power system and also shows partially the electric restoration

1. CHAPTER THREE
SYSTEM SECURITY CONTIGERCY ANALYSIS
and Emergency Restorations
BY FEKADE WALLE
DECEMBER 2017

2. CHAPTER FIVE
SYSTEM SECURITY AND CONTIGERCY ANALYSIS
5.1 INRODUCTION
In the past many widespread blackouts have occurred in
interconnected power systems. Therefore, it is necessary to
ensure that power systems should be operated most
economically such that power is delivered reliably. Reliable
operation implies that there is adequate power generation
and the same can be transmitted reliably to the loads. Most
power systems are designed with enough redundancy so
that they can withstand all major failure events. Here we
shall study the possible consequences and remedial actions
required by two main failure events: line-outages and
generating unit failures.

3. Cont’d
• 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

4. CONTD
• 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.

5. CONT’D
• 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.

6. CON’TD
• 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

7. CONT’D
• 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. Most large power
systems install equipment to allow operations
personnel to monitor and operate the system in a
reliable manner.

8. • Systems security can be broken down into
three major functions that are carried out in
an operations control center:
1 System monitoring.
2. Contingency analysis.
3. Security-constrained optimal power flow.

9. 1.System monitoring
• This provides the operators of the power system
with pertinent up-to-date information on the
conditions on the power system. Generally
speaking, it is the most important function of the
three.
• From the time that utilities went beyond systems of
one unit supplying a group of loads, effective
operation of the system required that critical
quantities will be measured and the values of the
measurements be transmitted to a central location.

10. • Such systems of measurement and data
transmission, called telemetry systems have
evolved to schemes that can monitor voltages,
currents, power flows, and the status of circuit
breakers, and switches in every substation in a
power system transmission network. In addition,
other critical information such as frequency,
generator unit outputs and transformer tap
positions can also be telemetered. With so much
information telemetered simultaneously, no
human operator could hope to check all of it in a
reasonable time frame.

11. • For this reason, digital computers are usually installed in
operations control centers to gather the telemetered data,
process them, and place them in a data base from which
operators can display information on large display
monitors. More importantly, the computer can check
incoming information against prestored limits and alarm
the operators in the event an overload or out-of-limit
voltage.
• State estimation is often used in such systems to combine
telemetered system data with system models to produce
the best estimate (in a statistical sense) of the current
power system conditions or state

12. • Such systems are usually combined with
supervisory control systems that allow
operators to control circuit breakers and
disconnect switches and transformer taps
remotely. Together, these systems are often
referred to as SCADA systems, standing for
supervisory control and data acquisition system.
The SCADA system allows a few operators to
monitor the generation and high-voltage
transmission systems and to take action to
correct overlords or out-of-limit voltages.

13. 2. contingency analysis
• The second major security function is contingency
analysis. The results of this type of analysis allow
systems to be operated defensively. Many of the
problems that occur on a power system can cause
serious trouble within such a quick time period that the
operator could not take action fast enough. This is often
the case with cascading failures. Because of this aspect
of systems operation, modern operations computers are
equipped with contingency analysis programs that
model possible systems troubles before they arise

14. • These programs are based on a model of the power system and
are used to study outage events and alarm the operators to any
potential overlords or out-of-limit voltages. For example, the
simplest form of contingency analysis can be put together with
a standard power-flow program together with procedures to set
up the power flow data for each outage to be studied by the
power-flow program.
• Several variations of this type of contingency analysis scheme
involve fast solution methods, automatic contingency event
selection, and automatic initializing of the contingency power
flows using actual system data and state estimation procedures.

15. 3. Security-constrained Optimal Power
Flow.
• The third major security function is security-
constrained optimal power flow. In this
function, a contingency analysis is combined
with an optimal power flow which seeks to
make changes to the optimal dispatch of
generation, as well as other adjustments, so
that when a security analysis is run, no
contingencies result in violations.

16. Power System Operating States.
• To show how this can be done, we shall divide the power system
into four operating states.
• Optimal dispatch: this is the state that the power system is in prior
to any contingency. It is optimal with respect to economic operation,
but it may not be secure.
• Post contingency: is the state of the power system after a
contingency has occurred. We shall assume here that this condition
has a security violation (line or transformer beyond its flow limit, or
a bus voltage outside the limit).

17. CONT’D
• Secure dispatch : is the state of the system with no contingency
outages, but with corrections to the operating parameters to
account for security
violations.
• Secure post-contingency: is the state of the system when the
contingency is applied to the base-operating condition—with
corrections. We shall illustrate the above with an example.
Suppose the trivial power system consisting of two generators, a
load, and a double circuit Line, is to be operated with both
generators supplying the load as shown below (ignore losses):

18. OPTIMAL DISPATCH
250MW
250MW
500MW
700MW

19. POST CONTIGENCY STATE
500MW
500MW

20. 3.2 SECURITY RELATED FUNCTIONS
• First we shall define certain quantities related to
power system security.
• Normal State: A power system is in normal state
if all the system loads are being met, no
equipment such as generators, transformers and
transmission lines etc. is overloaded, all bus
voltages and system frequency are within
specified limits, and the phase angle across any
two connected buses is not too large (usually less
than 45 degrees for stability considerations).

21. • If Security management(SM) finds the system to
be in an emergency or near emergency· state,
corrective action via "emergency control" may be
extended manually or automatically depending
upon the severity of the emergency. If it is not
very critical, corrective action may be achieved by
shifting generation from units in trouble to other
available units. Severe steady state emergencies
may require immediate load shedding. This can
be done manually by supervisory control or
automatically by the computer. If the overload is
very slight, the operator may decide to ride it
out, as the system loading may be decreasing or
there may be ample time for field maneuvers to
relieve the overload.

23. • If the system is in emergency state, control is
achieved almost completely by manual action. The
restoration requires an orderly, coordinated
procedure of bringing up generation, putting the
transmission back together and picking up load--all
in steps and at such a pace that dynamic
imbalances in generation versus loud and
constrictions in transmission capability would not
occur to take the system back down again. To carry
out this process, the operator would use the
security monitoring function to keep track of what
the system is doing in terms of status, power

24. • If the power system is found to be in the normal
state by the SM procedure, the "security
analysis" (SA) function is invoked to check on its
security level. SA consists of a "contingency
evaluation" program, which basically answers
the question "what if a next contingency out of a
set of possible contingencies takes place?" If the
system stays in a normal state even after the
contingency occurs, then it is in a "secure" state.

25. • However, if the system goes into an emergency
or restorative state if the contingency did
actually occur, then it is in "insecure" state.
Preventive action may require strengthening the
transmission network by putting more lines in
service, adding generation, or changing the
power flows by appropriate switching or putting
the operator in an "alert" state to shed some
loads if the contingency did occur. The last
measure is to minimize the damage to the
power system.

26. 3.3 CONTINGENCY ANALYSIS
The contingencies may be grouped into two
broad categories:
(a) power outage and
(b)network outage.
• The power outage includes:
(i) Loss of generating unit.
(ii) Sudden change in load which may cause
stability or oscillation problems.
(iii) Sudden change of power flow in an intertie,
which implies sudden gain of generation for one
area and loss of generation in the other area.

27. • The most serious case from the point of view
of steady state security is the loss of
generation. The real power lost is distributed
to a number of regulating generators
according to an assigned set of distribution
factors. However, if the generation is not
available, then load shedding will have to be
performed and the power system is in
insecure state.
The network outage includes:
(i) Outage of a transmission line.
(ii) Outage of a transformer.

28. The system operatoris interested to know ifa network outage willlead to emergency or
restorativestate implying that the presentstate isinsecure.
It is obvious that since the contingency analysis is performed in real time, the procedure
must be computationally fast. For this purpose an adaptation of the fast decoupled
method and matrix inversiontechnique is used. Recall equations and given below
-------------------------3.1&3.2 respectively

29. • Experiments have shown that it is adequate to
remove the series susceptence of the transmission
line or transformer from [B'] and [B"]. Shunt
susceptence either due to line charging or off
nominal transformer representation need not be
removed from [B' ] and [B" ] • All outages must, of
course, be reflected correctly in the calculation of (
P/V and Q/V).
• Let (3.1) or (3.2) be represented with base care
(present state) or
•

30. • for which a solution can be obtained by finding [B0]-l
(or equivalently by factors of [B0]). As pointed out
earlier, the outage of a transmission line or
transformer can be reflected in [B0 ] by the series
susceptence only. If the element between buses p
and q is removed, then at most, two elements are
modified in row p and two in row q of [B0]. The
outage matrix is then
---------3.5
• where b = line or transformer series susceptence, [M]
= row vector which is null except for Mp = a & Mq =-
1, where a = off nominal turns ratio referred to the
bus p for a transformer and a = 1 for transmission
line.

31. • Depending upon the type of connected buses, only one row
either p or q might be present in [B'] or [B"] in which case either
Mp or Mq above are zeros or appropriate. If both the connected
buses are P-V or slack, then [B" ] requires no modification.
• From (3.5), [B1] -l is given by
• [B1]-l = {[Bo] + b [M] T [M]} –l-----------------------------------------3.6
• It can be shown that
• [B1]-l = [Bo]-l - c [x] [M] [Bo]-l----------------------------------------3.7
• where
• C = (1/b + [M] [X]-l and [X] = [Bo]-l [M]T --------------------------3.8
• The solution vector [E1] for the outage problem is
• [E1] = [B1]-l R ----------------------------------------------------------3.9
• In view of (3.4) and (3.7), we can write (3.9) as
• [E1] = [Ea] - c [x] [M] [Ea]

32. • Thus for each outage of a series branch, two
vectors [X'] and [X''] must be calculated each
requiring [B'o]-l and [B' 'o]-l which are already
available from the base case solution.
• The method The method outlined above can also
be used for multiple outages, when the above
procedure is applied recursively. The solution
vector [E] is corrected successively as the effect of
each branch outage is introduced one at a time.
Although this method avoids the reinversion of
[B], it i~ faster for at the most three simultaneous-
outaged branches.

33. • The base-case power flow results for Example of
Figure 3.4 and indicate a flow of 43.8 MW and
60.7 MVAR on the line from bus 3 to bus 6. The
limit on this line can be expressed in MW or in
MVA. For the purpose of this discussion, assume
that we are only interested in the MW loading on
the line. Now let us ask what will happen if the
transmission line from bus 3 to bus 5 were to
open. The resulting flows and voltages are shown
in Figure 3.5. Note that the flow on the line from
bus 3 to bus 6 has increased to 54.9 MW and that
most of the other transmission lines also
experienced changes in flow.

34. • Note also that the bus voltage magnitudes
changed. particularly at bus 5, which is now almost
5% below nominal. Figures 3.6 and 3.7 are
examples of generator outages and serve to
illustrate the fact that generation outages can also
result in changes in flows and voltages on a
transmission network. In the example shown in
Figure 3.6, all the generation lost from bus 3 is
picked up on the generator at bus 1. Figure 3.7
shows the case when the Loss of generation on bus
3 is made up by an increase in generation at buses
1 and 2. Clearly, the differences in flows and
voltages show that how the lost generation is
picked up by the remaining units is important.

35. • If the system being modeled is part of a large
interconnected network, the lost generation
will be picked up by a large number of
generating units outside the system’s
immediate control area. When this happens,
the pickup in generation is seen as an increase
in flow over the tie lines to the neighboring
systems. To model this, we can build a
network model of our own system plus an
equivalent network of our neighbor’s system
and place the swing bus or contingency
analysis techniques are used.

36. • Contingency analysis procedures model single
failure events (i.e., one-line outage or one-
generator outage) or multiple equipment failure
events (i.e., two transmission lines, one
transmission line plus one generator, etc.), one
after another in sequence until “all credible
outages” have been studied. For each outage
tested, the contingency analysis procedure
checks all lines and voltages in the network
against their respective limits. The simplest form
of such a contingency analysis technique is shown
in Figure 3.7.

37. Figure 3.5 Six-bus network line outage case: line from bus 3 to bus 5
opened.

40. • The most difficult methodological problem to cope
with in contingency analysis is the speed of
solution of the model used. The most difficult
logical problem is the selection of “all credible
outages.” If each outage case studied were to
solve in 1 sec and several thousand outages were
of concern, it would take close to I h before all
cases could be reported. This would be useful if
the system conditions did not change over that
period of time. However, power systems are
constantly undergoing changes and the operators
usually need to know if the present operation of
the system is safe, without waiting too long for the
answer.

41. Figure 3.6 Six-bus network generator outage case. Outage of generator on bus 3;
lost generation picked up on generator 1.

42. • One way to gain speed of solution in a
contingency analysis procedure is to Outage of
generator on bus 3: lost generation picked up on
generator I and generator 2. use an approximate
model of the power system. For many systems,
the use of DC load flow models provides
adequate capability. In such systems, the voltage
magnitudes may not be of great concern and the
DC load flow provides sufficient accuracy with
respect to the megawatt flows. For other
systems, voltage is a concern and full AC load
flow analysis is required.

43. Figure . 3.8 Contingency analysis procedure.