power system masters degree candidates who ever going to do doctorate degrees is useful this material

1. 20EEE659T - POWER SYSTEM
PLANNING AND RELIABILITY
UNIT 2

2. Power System Reliability
Definitions :
• Reliability is the probability of a device or system performing its function
adequately, for the period of time intended, under the operating conditions
intended.
• Reliability is the ability of the power delivery system to make continuously
available sufficient voltage, of satisfactory quality, to meet the consumers' needs.
• The term reliability is broad in meaning. In general, reliability designates the ability
of a system to perform its assigned function, where past experience helps to form
advance estimates of future performance.
• More appropriate measure of reliability is the availability of the device;
The availability of a repairable device is the proportion of time, during the
intended time of service, that the device is in, or ready for service.

3. Power System Reliability
• The function of an electric power system is to provide electricity to its
customers efficientlyand with a reasonable assurance of continuity and
quality.
• The task of achieving economic efficiency is assigned to system operators
or competitive markets, depending on the type of industry structure
adopted.
• On the other hand, the quality of the service is evaluated by the extent to
which the supply of electricity is available to customers at a usable voltage
and frequency.
• Therefore, the reliability of power supply is, related to the probability of
providing customers with continuous service and with a voltage and
frequency within prescribed ranges around the nominal values.

4. Performance Measures of Reliability
• Measures of outage duration
• Frequency of outages
• System availability
• Response time

5. Basic Notions of Power System
Reliability
Outage
• Describes the state of a component when it is not available
to perform its intended function due to some event directly
associated with that component.
• An outage may or may not cause an interruption of service
to consumers depending on system configuration.
Forced Outage
• An outage caused by emergency conditions directly
associated with a component that require the component
to be taken out of service immediately either automatically
or as soon as switching operations can be performed or an
outage caused by improper operation of equipment or
human error.

6. Cont.,
Scheduled Outage
• An outage that results when a component is
deliberately taken out of service at a selected
time, usually for purposes of construction,
preventive maintenance or repair.
Partial Outage
• Describes a component state where the capacity
of the component to perform its function is
reduced but not completely eliminated.

7. Cont.,
Transient Forced Outage
• A component outage whose cause is immediately self-
clearing so that the affected component can be
restored to service either automatically or as soon as a
switch or circuit breaker can be reclosed or a fuse
replaced.
Persistent Forced Outage
• A component outage whose cause is not immediately
self-clearing but must be corrected by eliminating the
hazard or by repairing or replacing the affected
component before it can be returned to service.

8. Cont.,
• Interruption
The loss of service to one or more consumers or
other facilities and is the result of one or more
component outages depending on system
configuration.
• Forced Interruption
An interruption caused by a forced outage.
• Scheduled Interruption
An interruption caused by a scheduled outage.

9. Cont.,
Momentary Interruption
• It has a duration limited to the period required to restore service by
automatic or supervisor-controlled switching operations or by
manual switching at locations where an operator is immediately
available.
• Such switching operations are typically completed in a few
minutes.
Temporary Interruption
• It has a duration limited to the period required to restore service by
manual switching at locations where an operator is not immediately
available.
• Such switching operations are typically completed within1–2 hours.
Sustained Interruption
• It is any interruption not classified as momentary or temporary.

11. Outage classification

12. Reliability indices

15. Concepts and methodologies
1. SYSTEM AVERAGE INTERRUPTION DURATION
INDEX (SAIDI)
• The most often used performance
measurement for a sustained interruption.
• This index measures the total duration of an
interruption for the average customer during a
given time period.
• SAIDI is normally calculated on either monthly
or yearly basis; however, it can also be
calculated daily, or for any other time period.

16. • Each interruption during the time period is multiplied
by the duration of the interruption to find the
customer-minutes of interruption.
• The customer-minutes of all interruptions are then
summed to determine the total customer-minutes.
• To find the SAIDI value, the customer-minutes are
divided by the total customers.
SAIDI = Σ(ri * Ni ) / NT
Where
• SAIDI -System Average Interruption Duration Index,
minutes.
• ri = Restoration time, minutes.
• Ni = Total number of customers interrupted
• NT= Total number of customers served

17. Tutorial of reliability indices - SAIDI
• Example 1 : What is the SAIDI for the 28th of
the month where five outages were
recorded?. The table shows each outage, the
duration of the outage, and the customer
hours. The utility has a total of 50,000
customers.

18. • 28th, first outage at 9.53am, outage period was 90
minutes for 10 nos. customers.
• Therefore Customer hours = 10 x 1.5 hrs
= 15 hrs
Since SAIDI calculation is in minutes;
• Customer minutes = 356.80x 60 = 21,408
Therefore,
• SAIDI = 21,408 / 50,000
= 0.428 minutes
• This says that the average customer was out for 0.428
minutes on the 28th of the month.
• If the SAIDI is calculated for each day, the monthly
SAIDI is found by summing the daily values.

19. 2. CUSTOMER AVERAGE
INTERRUPTION DURATION INDEX
(CAIDI)
• Once an outage occurs the average time to restore
service is found from the Customer Average
Interruption Duration Index (CAIDI).
• CAIDI is calculated similar to SAIDI except that the
denominator is the number of customers interrupted
versus the total number of utility customers.
• CAIDI=Σ(ri*Ni)/Σ(Ni)
Where
• CAIDI -Customer Average Interruption Duration Index,
minutes.
• ri = Restoration time, minutes.
• Ni = Total number of customers interrupted

20. Tutorial of reliability indices - CAIDI
• Example 2 : What is the CAIDI for the 28th of
the month where five outages were
recorded?. The table shows each outage, the
duration of the outage, and the customer
hours. The utility has a total of 50,000
customers.

21. Solution
• The customer minutes are 21,408 and 1,014
customers were interrupted on the 28th.
Therefore,
• CAIDI=21,408/1014
=21.1minutes
• On average, any customer who experienced
an outage on the 28th was out of service for
21.1 minutes.

22. 3. SYSTEM AVERAGE INTERRUPTION
FREQUENCY INDEX (SAIFI)
• The average number of times that a system customer
experiences an outage during the year (or time period
under study).
• The SAIFI is found by dividing the total number of
customers interrupted by the total number of
customers served.
• Dimensionless index.
• SAIFI = Σ(Ni ) / NT
Where
• SAIFI -System Average Interruption Frequency Index
• Ni = Total number of customers interrupted
• NT= Total number of customers served

23. Tutorial of reliability indices - SAIFI
EXAMPLE 3: From the previous examples, on the
28th there were 1,104 customers interrupted
during 5 separate events and the total number of
customers served by the utility is 50,000.
Therefore,
• SAIFI=1014/50,000
=0.02
• This says that on the 28thof the month, the
customers at this utility had a 0.020 probability of
experiencing a power outage.

24. • SAIFI = SAIDI / CAIDI
With SAIDI of 0.428 minutes and a CAIDI of 21.1
minutes the SAIFI is;
• SAIFI = 0.428 / 21.1
= 0.02

25. 4. CUSTOMER AVERAGE
INTERRUPTION FREQUENCY INDEX
(CAIFI)
• The CAIFI measures the average number of
interruptions per customer interrupted per year.
• It is simply the number of interruptions that
occurred divided by the number of customers
affected by the interruptions.
• CAIFI = Σ( No ) / Σ( Ni )
Where
• CAIFI -Customer Average Interruption Frequency
Index
• No= Number of interruptions
• Ni = Total number of customers interrupted

26. Tutorial of reliability indices - CAIFI
• EXAMPLE 4 : From our previous examples, on the
28th there were 1,104 customers interrupted
during 5 separate events and the total number of
customers served by the utility is 50,000.
Therefore,
• CAIFI = 5 / 1014
= 0.005
• This says that the average number of
interruptions for a customer who was interrupted
is 0.005 times.

27. 5. CUSTOMER INTERRUPTED PER
INTERRUPTION INDEX (CIII)
• The Customer Interrupted per Interruption Index
(CIII) gives the average number of customers
interrupted during an outage.
• It is the reciprocal of the CAIFI.
• CIII = Σ( Ni ) / Σ( No )
Where
• CIII -Customer Interrupted per Interruption Index
• No = Number of interruptions
• Ni= Total number of customers interrupted

28. Tutorial of reliability indices - CIII
EXAMPLE 5 : From previous example, total of 1,104
customers were interrupted during five separate
events and the total number of customers served by
the utility is 50,000.
• Therefore,
• CIII=1014/5
=203customers
• This says that, on average, 203 customers were
interrupted on the 28th.
• Of course, on a detailed look at the outages on the
28th, it is clear that one outage contributed to the vast
majority of the customer outages.

29. Power system structure

30. Reliability based planning in power
systems
1. RELIABILITY PLANNING
1.1 SYSTEM RELIABILITY
• Modern society expects that the supply of electricity should be
continuously available on demand.
• Sometimes reliabilities fails due to Random system failures which
are generally beyond the control of power system engineers.
• The probability of consumers being disconnected, however, can be
reduced by increased investment on power systems by providing
high quality equipment or redundancy and better maintenance.
• The reliability of supply to consumers is judged from the frequency
of interruptions, the duration of each interruption and the value a
consumer places on the supply of electricity at the time that service
is not Provided.
• The value to consumers is determined by the benefits which they
can derive from using it.

31. Uncertainty
• The problem of uncertainty consists in devising a system sufficiently
robust to withstand the impacts.
• At the present time the amplitude and the number of the possible
impacts is such that the cost of a robust system becomes
prohibitive, if one wants to face most of the uncertainty factors.
• Flexibility within the system development. From the planner's point
of view a flexible system is a system which will be able to be
adapted quickly to any external change. This is achieved either
because the planner made provisions to change over to diverse
fuels or diverse power generation or because he decided to install
equipment which makes better use of the existing system.
In recent years the need for flexibility has become particularly
apparent because both planners and operators had to cope with
more and more significant trends,
1. Industry structure trends - deregulation, privatization and vertical
disaggregation, wheeling for non utility generation, transmission
access for consumers for power purchases from other utilities.
2. 2. Financial trends – capital availability and cost uncertainty, rate
base incentives and constraints, stockholder risks and uncertain
rates of return, construction expenditure recovery risks.

32. 3. Technical trends - load management and conservation, generation
technology and licensing issues, transmission technology and ROW
issues.
4. Environment and health issues – emissions limits, power frequency
and electromagnetic field constraints, radioactive waste
storage/disposal, endangered species.
• Flexibility appears with the improvement in the ability of the power
system to adapt itself quickly to new circumstances.
• Security affects the operation and the structure of the system. The
system security is defined here as its ability to avoid or limit-major
outages which entails the collapse of entire parts of the system.

33. 1.2 SYSTEM ADEQUACY AND SECURITY
• A simple yet reasonable subdivision of power system reliability,
both deterministic and probabilistic, is the two basic aspects of
system security and system adequacy.
• Adequacy is generally defined as the capability of the system to
meet the system demand within major component ratings and in
the presence of scheduled and unscheduled outages of
generation, transmission and distribution facilities.
• Security is generally defined as the capability of the system to
withstand disturbances arising from faults and unscheduled
removal of equipment without further loss of facilities or
cascading. Adequacy therefore, relates to the existence of
sufficient facilities within the system, i.e., it relates to static
system conditions whereas security relates to dynamic system
conditions.
• The task of power system planning is to configure an electric power
system with a compromise between the requirements perceived by
consumers for adequacy and security to achieve continuity and
quality of supply, and to keep in mind the economics of the power
system in terms of operating and capital costs, so that the benefit
of higher levels of adequacy and security are realized by the
consumer.

34. 1.3 RELIABILITY PLANNING
• The basic function of an electric power system is to meet
electricity requirements, with adequate quality and
reliability and in an economical manner.
• There is an emerging recognition that the traditional
practice of providing all users with a uniform and a good
level of service reliability merits a re-examination. Given
the changes in the electric utility industry's cost structure in
recent years, there is a growing feeling that investments
related !o the provision of electric service reliability should
be more explicitly evaluated with reference to their cost
and benefit implications.
• Cost-benefit analysis provides the basis for answering the
fundamental economic question in reliability planning-how
much reliability is adequate? A key related question is how
and where should a utility spend its 'reliability rupees'.
• Because of the changes in technology, consumer needs and
lifestyles, economic factors, etc., reliability preferences can
also shift over time. This may require periodical revision at
the reliability standards. As the reliability standards
changes from time to time.

35. Figs showing the Reliability versus Cost.

36. • In contrast, the total cost minimization approach seeks to establish the
trade-off that is conceptually depicted in Figure below. The total cost of
supplying electricity is the sum of system cost and consumer outage costs.
The lowest point on the total cost curve defines the optimal balancing of
system costs and consumer costs and determines the optimal reliability
level, reserve margin, LOLP,EUE.
• From an implementation standpoint, the following analysis is required
under this method. For each of several preselected reserve margins, an
optimum resource mix is first determined. Next, for each such resource mix,
production costing, revenue requirements and reliability calculations are
performed to estimate total costs as (revenue requirements) + (EUE)
(outage cost in Rs/kWh)
• The lowest point on this curve defines the optimum reserve requirement
which can also be calibrated to an optimal EUE (Expected Unserved Energy)
standard or some normalization of EUE such as loss-of-energy probability
(LOEP).Especially in situations where the present generation fuel mix is non-
optimal, the total cost minimization approach will indicate a higher
reliability level because some generating plant will be added to reduce fuel
costs.

37. CEA reliability planning criteria
• The Central Electricity Authority (CEA) uses the following reliability criteria on
deterministic and probabilistic basis.
For Lines
Loading under normal operating conditions with nearly 20% margin for lines. For
example 400 kV S/C line: 360-800 MW, 220 kV S/C line: 160-200 MW, 132 kV S/C
line: 50-70 MW.
For Generation
The transmission system configurations for which the transmission planning
studies are carried out depending on the generation scenarios worked out by the
CEA. The peaking capacities and energy generation capabilities, availabilities of
power plant on which the power & energy balance studies are based, would be
determined on the basis of the following norms,
• Thermal and Nuclear Plants - The norms for availability of peaking capability is
given by Rated capacity - (Maintenance @5% + Partial outage rate @15% +
Forced outage rate @17% + Auxiliary consumption @1O% + Spinning reserve
@5%)
• This norm is not realistic and total reserved margin should not be more than 20
per cent.
• Hydro plants - Norms for deciding overall peaking capacities of hydro units would
be as under, Rated capacity - (Maintenance @3% + Forced outage rate @9.5% +
Auxiliary consumption @0.5%).
• The peaking capacities and energy generation capabilities of hydro stations shall
be determined taking the hydrological conditions, requirements of water for
irrigation purposes, etc., into consideration.
• Generation expansion - LOLP = 1%, 2%, 5%.

38. Reliability evaluation
The power system reliability studies are conducted for two purposes,
1. Long-term reliability evaluations may be performed to assist in
long range system planning.
2. Short-term reliability predictions may be undertaken to assist in
day-to-day operating decisions including system security.
Improvement in system reliability can be effected by using either
better components or a system design incorporating more
redundancy. The main steps in reliability studies are,
1. Define the system-list the components and collect the necessary
component failure data from field surveys available.
2. Define the criteria for system failure.
3. List the assumptions to be used.
4. Developing the system model.
5. Perform failure effects analysis and compute the system reliability
indices.
6. Analyze and evaluate the results.

39. 2. SYSTEM OPERATION PLANNING
2.1 OPERATIONS
• Operational planning covers the whole period ranging from the
implementation stage of system development plans to the point
when system operation engineers at area, state, regional and
national load dispatch deal with the dispatch of power.
• It is the matching of generation output with aggregated consumer
demand, subject to requirements of economy and security. It covers
the maintenance of generation, transmission and distribution
facilities.
• Certain 0perational problems have to be considered at the long-
term planning. For example, the Indian power system regional grids
are small in capacity and size, and thus, there is a limitation on
installation of large sized generation units in the grid.
• Operation planners plan to minimize operating costs within
constraints while ensuring an acceptable level of system reliability.
Various decisions are required at appropriate times related to
operating policies, operating procedures, maintenance planning,
fueling, hydraulic utilization, transaction planning etc. The overall
operation is shown in the below figure

40. Fig showing the lead time for
operational planning.

41. 2.2 REAL TIME OPERATION
2.2.1 State Estimation
• The state of technology of actually existing real time computers allow network data
collection for the period at one to two minutes. after each state estimation, all data
identified as bad for erroneous and non-telemetered values are replaced by
calculated values becoming available to the operator of the programs.
• The network estimation assumed to be the most important functions for the real
time secure operation, include all the principles and computer programs devoted
to the permanent assessment of security factors for actual or simulated network
configurations.
• In the real time program, the comparison of variables in telemetered values to
fixed limits is the first step of maximum system loading evaluation.
• Let n be the number of buses of the network, thus overload checking belongs to
“n security" assessment. With an ac load flow calculation, the complete n security
can be checked, while changing the values of some data (measurements or
indications) which allows the operator to anticipate the evaluation of eventual
future situations.
• Many power systems today have been designed in such a way that the random
failure of the transmission's item or generating unit with the heaviest load does not
affect reliability of other equipment, at the same time preserving the quality of
supply.
• The contingency analysis is based on this criterion starting from it toad flow
calculation. The program simulates outages and determines the load transferred on
the remaining items of the network. A display of violated constraints informs the
operator of the risks occurring in the new operating conditions.

42. 2.2.2 Automatic Generation Control
• Automatic Generation Control function (AGC) is on-line computer
control and is generally executed everyone to ten seconds. AGC
tracks system load and generation level of each committed unit. In
the interconnected power systems, this function also meets an
additional objective namely the maintaining of the net interchange
contracts in force at each instant.
• The tie lines are generally connected into the transmission network
at locations where their specific power flow must be established by
adjusting or shifting the power output of generators in order to
achieve a desired flow value.
• To maintain a net interchange of power with its area neighbours, an
AGC uses real power flow measurements of all tie lines emanating
from the area and subtracts the scheduled interchange to calculate
an error value.
• The net power interchange (together with a gain B (MW/0.1Hz)
called the frequency bias) as a multiplier on the frequency deviation
is called the area control error (ACE)and is given by

43. 2.2.3 Economic Load Dispatch
• It is on-line computer control generally performed everyone two minutes
to supply the existing system load demand from each committed units in
the most economical manner in terms of minimal fuel cost and minimal
losses. Even pollution control can be a feature of economic dispatch
operation.
2.2.4 Stability
• Power systems are becoming increasingly complex because of
interconnections and faster dynamic response of plant, particularly if
equipped with solid state controllers. Also, heavier loading on the existing
circuits to cope with increasing energy transfers without constructing new
lines has made the system operate closer to its transient stability limits.
• New techniques for the on-line evaluation of stability criterion and for
detecting in real time operation through many recent techniques &
methods are available.
• Fast transient stability methods are categorized under three main groups
(i) Direct and hybrid methods based on energy functions,
(ii) New computing hardware including parallel processors,
(iii)Artificial intelligence approaches (pattern recognition and expert system).

44. GENERATION INDICES
• The indices used to measure generation
reliability which are probabilistic estimates of
the ability of a particular generation
configuration to supply the load demand.
• The indices are sensitive to basic factors like
unit size and unit availability.

45. Cont.,
Risk of Supply Shortages
A failure in a generating unit results in the unit
being removed from service in order to be repaired or
replaced, this event is known as an outage.
• A forced outage is an outage that results from
emergency conditions, requiring that the component
be taken out of service immediately.
• A scheduled outage is an outage that results when a
component is deliberately taken out of service, usually
for purposes of preventive maintenance or repair.

46. Cont.,
Generating unit states

47. Generation Reliability Evaluation
• The basic elements used to evaluate
generation adequacy are shown in Fig.1.
• The system is deemed to operate successfully
as long as there is sufficient generation
capacity to supply the load.
Fig 1. Elements of generator reliability evaluation

48. Generation system reliability assessment indices

49. GENERATION INDICES
1.Loss of Load Probability (LOLP)
• A loss of load will occur whenever the system load exceeds the generating
capacity in service.
• Loss of Load Probability (LOLP) is a projected value of how much time, in
the long run, the load on a power system is expected to be greater than the
capacity of the available generating resources.
• The overall probability that the load demand will not be met is called the
Loss-of-Load Probability or LOLP.
• LOLP is defined as the probability of the effective system capacity not
meeting the load demand;
LOLP = P ( X > R)
Where
• X=System outage capacity
• R=C–L=System Reserve Capacity
• C=System Effective Capacity
• L=Maximum Load

50. 2.Loss of Energy Probability (LOEP)
The value obtained will have a unit of MWh / year and is
also known as the Loss of Energy Expectation (LOEE) since it is
an expected value rather than a probability.
• The ratio of the expected energy not served during some long
period of observation to the total energy demand during the
same period.