Power System Reliability: adequacy-long
term planning, procurement security,
planning criteria, states of power system
PSTI Bengaluru
16th June 2011
Outline of presentation
• Power system reliability
– Adequacy and security
•
•
•
•
Concepts and terminologies
Load forecasting-long term
Generation planning and procurement security
Transmission planning criteria
– States of power system
Reliability--definitions
• A measure of the ability of a system, generally given as
numerical indices, to deliver power to all points of
utilisation within acceptable standards and in amounts
desired. Power system reliability (comprising generation
and transmission & distribution facilities) can be
described by two basic functional attributes: adequacy
and security. (Cigré definition)
• Reliability is the probability of a device or a system
performing its function adequately, for the period of time
intended, under the operating conditions intended. (IEEE
PES definition)
Reliability
Reliability
Adequacy
Security
• Adequacy relates to the existence of sufficient facilities within
the system to satisfy the consumer load demand at all times.
• Security relates to the ability to withstand sudden disturbances
Definitions……contd/• Adequacy:
A measure of the ability of the power system to
supply the aggregate electric power and energy
requirements
of
the
customers
within
components ratings and voltage limits, taking
into account planned and unplanned outages of
system components. Adequacy measures the
capability of the power system to supply the load
in all the steady states in which the power
system may exist considering standards
conditions. (Cigré definition)
Analysis of reliability….hierarchial levels
1.
Generation only (Level 1)
2.
Generation + Transmission (Level 2)
3.
Generation + Transmission+ Distribution (Level 3)
Analysis involving level 3 are not generally done due to
enormity of the problem.
Most of the probabilistic techniques for reliability
assessment are with respect to adequacy assessment.
Reliability of a system
• A system composed of large number of
components connected in series and
parallel.
• Each component would have its own
reliability.
• Reliability of the system would depend on
the reliability of individual component.
– A chain’s strength would be governed by the
weakest link.
Reliability Indices (1)
•
SAIFI =System Average Interruption Frequency Index (int/yr. cust)= Total
number of customer interruptions / Total number of customers served
•
SAIDI = System Average Interruption Duration Index (h/yr. cust) = Customer
interruption durations / Total number of customers served
•
CAIFI = Customer Average Interruption Frequency Index (int./yr. cust) = Total
number of customer interruptions / Total number of customers interrupted
•
CAIDI = Customer Average Interruption Duration Index (h/y. cust.) =
Customer interruption durations/ Total number of customer interruptions =
SAIDI/SAIFI
•
CTAIDI = Customer Total Average Interruption Duration Index (h/ y. cust)=
Customer interruption durations / Total number of customers interrupted
Reliability Indices (2)
• ENS = Energy Not Supplied = (kwh/y.) = Total energy not
supplied = UE = Unserved Energy
• AENS = Average Energy Not Supplied = (kwh/y. Cust.) =
Total energy not supplied / Total number of customers
served
• LOLP = Loss of Load Probability =The probability that the
total production in system cannot meet the load demand
Reliability Indices (3)
• Protection system
– Selectability: should operate for the conditions intended and
should not for which not intended.
– Dependability: Number of correct operation devided by number of
incorrect operations
• Other Equipments, high reliability would mean
– In repeated operations – probability that the out would be within a
narrow range.
– Low variance or standard deviation of output
Loss of Load Probability (LOLP)
Optimal value of reliability
Optimal value of reliability (2)
• The costs of the producer = CR
• The costs of the consumers = CIC
• CIC = Customer Interruption Costs
(= VOLL = Value of Lost Load)
• At the optimum : ∆CR = - ∆ CIC (= -∆ VOLL)
Time scale involved
in security analysis
Source: IEEE tutorial
2006 Delhi, Mohd. Shahidehpour
Definitions……contd/Security:
A measure of power system ability to withstand
sudden disturbances such as electric short
circuits or unanticipated losses of system
components or load conditions together with
operating constraints. Another aspect of security
is system integrity, which is the ability to
maintain interconnected operation. Integrity
relates to the preservation of interconnected
system operation, or avoidance of uncontrolled
separation, in the presence of specified severe
disturbances. (Cigré definition)
Power System stability
Power System Stability
Angle stability
Voltage stability
Mid term
Long term
Small signal stability Transient stability
Study period upto
10 secs
Ability to remain in
operating equilibrium
Equilibrium between
opposing forces
Large disturbance Small disturbance
Study period upto
several minutes
Study period upto
tens of minutes
Power System stability (contd/-)
Small signal Stability
Oscillatory instability
Insufficient damping torque
Unstable control action
Local plant modes
Inter area modes
Non-oscillatory instability
Insufficient synchronizing torque
Control modes
Torsional modes
Load forecasting------long term
• Electric Power Survey (EPS) reports are brought out by CEA once in
five (5) years.
• Last report (17th ) released in March 2007 containing year wise
projections up to 2011-12 and perspective projections at the end of
2016-17 and 2021-22
• 18th EPS committee constituted in Jan 2010 and scheduled to give
its report by October 2011. (year wise projections up to 2016-17 and
perspective projections at the end of 2021-22 and 2026-27.)
Electric Power Survey (contd/-)
• Annual forecasts released up to 11th EPS in 1982.
Thereafter EPS period coincided with Five Year Plan
(12th EPS released in 1985).
• 17th EPS considered the objectives enshrined in the
National Electricity Policy.
Electric Power Survey (contd/-)
High deviation in peak load estimates for the last two years!!
Electric Power Survey (contd/-)
• Partial End Use Method (PEUM) adopted by CEA for
load forecasts.
– Electricity utilization in different sectors estimated.
– All agricultural loads and industry/non-industry loads > 1 MW
– Railway traction demand also covered.
• Alternate forecast based on econometric model done
during 17th EPS under the guidance of Prof D N Rao,
JNU. Projections found on lower side and discarded.
Guidelines/objectives for 18th EPS
1. Analyses projections of 17th EPS vis-à-vis actuals.
2. To make separate electricity demand forecast for mega cities of
population of 50 lakhs and above. The number of cities of population of
50 lakhs or above will be around 7.
3. Categorization of rural/urban loads in the forecast may be in such a way
to achieve 100% rural electrification target.
4. Impact of energy conservation on electricity demand forecast.
5. Impact of inter sector linkages of power sector with other important
sectors of the economy on electricity demand forecast.
6. Capture and adopt Demand Side Management in the forecast.
7. Capture and adopt T&D loss reduction programme in the forecast.
8. Annual updating of the electricity demand forecast
Generation planning and procurement security
FA, FB and FC are the fixed costs,
VA, VB and VC the variable costs of above plants
How many outage hours to allow?
Load should be unserved in hours when the cost of serving it would exceed
Value Of Lost Load (VOLL). Put algebraically, outage makes sense so long as
VOLL × (Outage Hours) < FA + (VA × (Outage Hours)),
and solving this gives us the answer.
Peaking capacity versus mid-load plant?
Peakers are the least cost option so long as
FA + X*(VA) < FB + X*(VB),
and solving for X gives us the number of hours that the last peaker
built runs.
How much peaking capacity to build?
Calculation of mid load and base load capacity
Generation planning
• In a competitive market also, the mix of
plant types are arrived at similar to
centralized planning except that it is
through a decentralized price discovery
and profitability analysis.
Transmission planning
• Once we have the load forecast and generation
location, it is easy to identify ‘where to build lines
and how many’.
• In India the transmission planning is done as per
the Manual on Transmission Planning Criteria
prepared by CEA in June 1994
CEA Transmission planning criteria (1)
Section 2.2: The system shall be evolved based on
detailed power system studies which shall include
– Power flow studies
– Short Circuit Studies
– Stability Studies (including transient stability, voltage stability and
steady state oscillatory stability studies)
– EMTP studies to determine switching / temporary overvoltages
• Note: Voltage stability, oscillatory stability and EMTP studies
may not form part of perspective planning studies. These are
however required to be done before any scheme report is
finalised.
CEA Transmission planning criteria (2)
Section 2.4:
The following options may be considered for strengthening
of the transmission network.
• Addition of new Transmission lines to avoid overloading of existing
system. (whenever three or more circuits of the same voltage class are
envisaged between two sub stations, the next transmission voltage
should also be considered.)
• Application of Series Capacitors in existing transmission line to increase
power transfer capability.
• Upgradation of the existing AC transmission lines
• Reconductoring of the existing AC transmission line with higher size
conductors or with AAAC.
• Adoption of multi-voltage level and multi-circuit transmission lines.
CEA Transmission planning criteria (3)
2.5
ln case of generating station close to a major load centre, sensitivity of its
complete closure with loads to be met (to the extent possible) from other
generating stations (refer para 3.3.3) shall also be studied.
2.6
In case of transmission system associated with Nuclear Power Stations
there shall be two independent sources of power supply for the purpose of
providing start-up power facilities. Further the angle between start-up
power source and the NPP switchyard should be, as far as possible,
maintained within 10 degrees.
2.7
The evacuation system for sensitive power stations viz., Nuclear Power
stations, shall generally be planned so as to terminate it at large load
centres to facilitate islanding of the power station in case of contingency.
2.8
Where only two circuits are planned for evacuation of power from a
generating station, these should be ( as far as possible) two single circuit
lines instead of a double circuit line.
CEA Transmission planning criteria (4)
2.9
Reactive power flow through ICTs shall be minimal. Normally it
shall not exceed l0% of the rating of the ICTs. Wherever voltage
on HV side of ICT is less than 0.975 pu no reactive power shall
flow through ICT.
2.10
Thermal/nuclear Generating units shall normally not run at leading
power factor. However, for the purpose of charging, generating unit
may be allowed to operate at leading power factor as per the
respective capability curve.
CEA Transmission planning criteria (5)
3.2
LOAD DEMANDS
3.2.1
The profile of annual and daily demands will be determined from past data.
These data will usually give the demand at grid supply points and for the
whole system identifying the annual and daily peak demand.
3.2.2
Active Power (MW)
The system peak demands shall be based on the latest reports of Electric
Power survey (EPS) Committee. ln case these peak load figures are more
than the peaking availability, the loads will be suitably adjusted substationwise to match with the availability. The load demands at other periods
(seasonal variations and minimum loads) shall be derived based on the
annual peak demand and past pattern of load variations. From practical
considerations the load variations over the year shall be considered as
under:
• Annual Peak Load
• Seasonal variation in Peak loads (corresponding to high thermal and high hydro
generation)
• Minimum load.
• Off -Peak Load relevant where Pumped Storage Plants are involved or interregional exchanges are envisaged.
CEA Transmission planning criteria (6)
3.2.3
Reactive power (MVAR)
Reactive power plays an important role in EHV transmission system planning and
hence forecast of reactive power demand on an area-wise or substation-wise
basis is as important as active power forecast. ……………………
……………………………………………… This will require compilation of past data
in order to arrive at reasonably accurate load forecast. Recognising the fact that
this data is presently not available it is suggested that pending availability of such
data, the load power factor at 220/132 KV voltage levels shall be taken as 0.85
lag during peak load condition and 0.9 lag during light load condition
excepting areas feeding predominantly agricultural loads where power
factor can be taken as 0.75 and 0.85 for peak load and light load conditions
respectively. In areas where power factor is less than the limit specified above, it
shall be the responsibility of the respective utility to bring the load power factor to
these limits by providing shunt capacitors at appropriate places in the system.
CEA Transmission planning criteria (7)
3.3.1
Generation despatch assumptions………..Table at Annex-1
3.3.2
Generation despatches corresponding to the following operating
conditions shall be considered depending on the nature and
characteristics of the system
• Annual Peak Load
• Maximum thermal generation
• Maximum hydro generation
• Annual Minimum Load
• Special area despatches
• Special despatches corresponding to hi-uh agricultural load with low power factor,
wherever applicable
• Off peak conditions with maximum pumping load where Pumped Storage stations
exist and also with the inter-regional exchanges, if envisaged
• Complete closure of a generating station close to a major load centre.
CEA Transmission planning criteria (8)
4.0
Permissible line loading limits
4.1
Permissible line loading limit depend on many factors such as voltage
regulation, stability and current carrying capacity (thermal capacity) etc.
While Surge Impedance Loading (SIL) gives a general idea of the loading
capability of the line, it is usual to load the short lines above SIL and long
lines lower than SIL (because of the stability limitations). SIL at different
voltage levels is given at Annex -II. Annex-II also shows line loading (in
terms of surge impedance loading of uncompensated line )as a function of
line length assuming a voltage regulation of 5% and phase angular
difference of 30 degree between the two ends of the line. In case of shunt
compensated lines, the SIL will get reduced by a factor k, where
k = square root (1-degree of compensation)
For lines whose permissible line loading as determined from the curve
higher than the thermal loading limit, permissible loading limit shall be
restricted to thermal loading limit.
CEA Transmission planning criteria (9)
Annex-II
CEA Transmission planning criteria (10)
4.2
Thermal loading limits……………………..Annex-III
CEA Transmission planning criteria (11)
5.0
Steady state voltage limits
Note: The step change in voltage may exceed the above limits where
simultaneous double circuit outages of 400 kV lines are considered. In such
cases it may be necessary to supplement dynamic VAR resources at
sensitive nodes.
CEA Transmission planning criteria (12)
5.0
Steady state voltage limits
CEA Transmission planning criteria (13)
6.0
6.2
Security Standards
Steady state operation
i) As a general rule, the EHV grid system shall be capable of withstanding
without necessitating load shedding or rescheduling of generation, the
following contingencies:
–
–
–
–
–
–
Outage of a 132 kV D/C line or,
Outage of a 220 kV D/C line or
Outage of 400 kV single circuit line or,
Outage of 765 kV single circuit line or
Outage of one pole of HVDC Bipolar line or
Outage of an Interconnecting Transformer
The above contingencies shall be considered assuming a precontingency system depletion
(planned outage) of another 220 kV double circuit line or 400 kV single circuit line in another
corridor and not emanating from the same substation. All the generating plants shall operate
within their reactive capability curves and the network voltage profile shall also be
maintained within voltage limits specified in para 5.
CEA Transmission planning criteria (14)
6.0
6.2
Security Standards
Steady state operation
ii. The power evacuation system from major generating station/complex
shall be adequate to withstand outage of a 400 kV Double Circuit line if
the terrain indicates such a possibility.
iii. In case of large load complexes with demands exceeding 1000 MW the
need for load shedding in the event of outage of a 400 kV Double circuit
line shall be assessed and kept minimum. System strengthening
required, if any, on account of this shall be planned on an individual
case-to-case basis.
iv. The maximum angular separation between any two adjacent buses
shall not normally exceed 30 degrees.
CEA Transmission planning criteria (15)
6.0
6.3
Security Standards
Stability considerations
A. Transient Stability
i.
The system shall remain stable under the contingency of outage of single
largest unit.
ii.
The system shall remain stable under the contingency of a temporary
single-phase-to-ground fault on a 765 s/c kV line close to the bus
assuming single pole opening of the faulted phase from both ends in 100
msec (5 cycles) and successful reclosure (dead time I sec).
CEA Transmission planning criteria (16)
6.0
Security Standards
6.3
Stability considerations
iii) The system shall be able to survive a single phase-to-ground fault on a
400 kV line close to the bus as per following criteria:
A. 400 kV S/C line : System shall be capable of withstanding a permanent
fault. Accordingly, single pole opening ( 100 msec) of the faulted phase
and unsuccessful reclosure (dead time 1 sec.) followed by 3-pole opening
(100 msec) of the faulted line shall be considered.
B. 400 kV D/C line : System shall be capable of withstanding a permanent
fault on one of the circuits when both circuits are in service and a transient
fault when the system is already depleted with one circuit under
maintenance/outage. Accordingly, 3 pole opening (100 msec) of the
faulted circuit shall be considered when both circuits are assumed in
operation ( single pole opening and unsuccessful auto-reclosure is not
considered generally in long 400 kV D/C lines since the reclosure facility
is bypassed when both circuits are in operation, due to difficulties in sizing
of neutral grounding reactors) and single pole opening ( 100 msec ) of the
faulted phase with successful reclosure (dead time I sec) when only one
circuit is in service.
CEA Transmission planning criteria (17)
6.0
6.3
Security Standards
Stability considerations
iv)
ln case of 220/132 kV networks, the system shall be able to survive a
three-phase fault with a fault clearing time of 160 msec (8 cycles)
assuming 3-pole opening.
v)
The system shall be able to survive a fault in HVDC converter station
resulting in permanent outage of one of the poles of HVDC bipoles.
B. Voltage stability
Each bus shall operate above knee point of Q-V curve under normal as
well as the contingency conditions as discussed above in para 6.2.
CEA Transmission planning criteria (17)
6.0
6.3
Security Standards
Stability considerations
C. Steady State Oscillatory Stability
The steady state oscillatory stability may be evaluated through Eigenvalue
analysis. In case all the real parts of Eigen-values of linearized system
matrix are negative, the system may be considered to have steady state
oscillatory stability.
CEA Transmission planning criteria (18)
7.
Reactive power compensation
7.1
Shunt capacitors……..provide as close to lower voltages
7.2
Shunt reactors
7.2.1
Switchable reactors shall be provided at EHV substations for controlling
voltages within the limits defined in the Para 5 without resorting to
switching-off of lines. The size of reactors should be such that under
steady state condition, switching on and off of the reactors shall not cause
a voltage change exceeding 5%. The standard sizes (MVAR) of reactors
are
400 kV (3-phase units)
50, 63 and 80 (at 420 kV)
765 kV (1-phase units)
50, 63 and 110 (at 800 kV)
CEA Transmission planning criteria (19)
7.
Reactive power compensation
7.2
Shunt reactors
7.2.2
Fixed line reactors may be provided to control Temporary Power
Frequency overvoltage (after all voltage regulation action has taken place]
within the limits as defined in para 5 under all probable operating
conditions.
7.2.3
Line reactors (switchable/controlled fixed) may be provided if it is
not
possible to charge EHV line without exceeding the voltage limits defined
in para 5. The possibility of reducing pre-charging voltage of the charging
end shall also be considered in the context of establishing the need for
reactors.
CEA Transmission planning criteria (20)
7.
Reactive power compensation
7.3
Static Var Compensation (SVC)
7.3.1
Static Var Compensation shall be provided where found necessary to
damp the power swings and provide the system stability under conditions
defined in the para 6 on "security Standards ". The dynamic range of static
compensators shall not be utilized under steady state operating condition
as far as possible.
CEA Transmission planning criteria (21)
8.
Sub-Station Planning Criteria
8.2
The maximum fault level on any new substation bus should not
exceed 80% of the rated rupturing capacity of the circuit breaker.
The 20% margin is intended to take care of the increase in shortcircuit levels as the system grows. The rated breaking current
capability of switchgear at different voltage levels may be taken as
CEA Transmission planning criteria (22)
8.
Sub-Station Planning Criteria
8.4
The capacity of any single sub-station at different voltage levels
shall not normally exceed :
765 kV
2500 MVA
400 kV
1000 MVA
220 kV
320 MVA
132 kV
150 MVA
8.5
Size and number of interconnecting transformers (ICTs) shall be
planned in such a way that the outage of any single unit would not
over load the remaining ICT(s) or the underlying system.
8.6
A stuck breaker condition shall not cause disruption of more than
four feeders for 220kV system and two feeders for 400 kV
system and one feeder for 765 kV system.
Power system operating states
Normal
Restorative
In extremis
Alert
Emergency
Power system operating states (2)
• Normal state
– All system variables are in the normal range
and no equipment is being overloaded. The
system operates in a secure manner and is
able to withstand a contingency without
violating any of the constraints.
Power system operating states (3)
• Alert state
– Security level falls below a certain limit of adequacy or if the
possibility of a disturbance increases due to adverse weather
conditions such as the approach of severe storms. All system
variables are still within the acceptable range and all constraints
are satisfied. However the system has weakened to a level
where a contingency may cause equipments to get overloaded
and reach an emergency state. If the contingency is very severe
we could land up directly in the in extremis state (extreme
emergency).
– Preventive actions such as a generation re-dispatch could bring
the system back to normal state else it might remain in alert
state.
Power system operating states (4)
• Emergency state
– Sufficiently severe disturbance under alert state leads to an
emergency state. Voltages at many buses become low and
equipment loading exceeds the short term emergency ratings.
System is still intact.
– System can be restored back to alert state by emergency control
actions such as fault clearing, excitation control, fast valving,
generation tripping, generation runback, HVDC modulation and
load shedding.
Power system operating states (5)
• In extremis state
– If the emergency measures are not applied or are
ineffective, the system goes to in extremis state, the
result is cascading outages and the possibility of
shutdown of major part of the system.
– Control actions such as load shedding and controlled
separation could save much of the system from a
possible blackout.
Power system operating states (6)
• Restorative state
– This represents a condition where control action is
being taken to reconnect all the facilities as well as
the affected loads.
– System could either go directly to the normal state or
through the alert state depending on the conditions.
References
1. Roy Billinton and Ronald N Allan, ‘Reliability Assessment of Large
Electric Power Systems’, Kluwer Academic Publishers
2. Dr. Mohammad Shahidehpour, ‘Electricity Restructuring and the role of
security in power systems operation and planning’, IEEE tutorial, April
2006, New Delhi
3. P Kundur, ‘Power System Stability and Control’, Mc Graw Hill Inc.
4. Brainstorming session and agenda for the first meeting of 18th EPS
Committee on 27th August 2010 available at CEA website
http://www.cea.nic.in
5. ‘Manual on Transmission Planning Criteria’, June 1994, CEA
6. Sally Hunt, ‘Making Competition Work in Electricity’, John Wiley and
Sons, Appendix E----Building New generators, When, Where and How
Thank you
Discussion………