Enhancing Power System Reliability: Adequacy & Security Planning

1. Power System Reliability: adequacy-long term planning, procurement security, planning criteria, states of power system PSTI Bengaluru 16th June 2011

2. 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

3. 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)

4. Reliability Adequacy Security Reliability • 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

5. 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)

6. Analysis of reliability….hierarchial levels • Generation only (Level 1) • Generation + Transmission (Level 2) • 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.

7. 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.

8. 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

9. 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

10. 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

11. Loss of Load Probability (LOLP)

12. Optimal value of reliability

13. 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)

14. Time scale involved in security analysis Source: IEEE tutorial 2006 Delhi, Mohd. Shahidehpour

15. 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)

16. Ability to remain in operating equilibrium Equilibrium between opposing forces Power System Stability Angle stability Voltage stability Mid term Long term Small signal stability Transient stability Large disturbance Small disturbance Study period upto 10 secs Study period upto several minutes Study period upto tens of minutes Power System stability

17. Small signal Stability Oscillatory instability Non-oscillatory instability Insufficient damping torque Unstable control action Local plant modes Inter area modes Control modes Torsional modes Power System stability (contd/-) Insufficient synchronizing torque

18. 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.)

19. 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.

20. Electric Power Survey (contd/-) High deviation in peak load estimates for the last two years!!

21. 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.

22. Guidelines/objectives for 18th EPS • 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. • Categorization of rural/urban loads in the forecast may be in such a way to achieve 100% rural electrification target. • Impact of energy conservation on electricity demand forecast. • Impact of inter sector linkages of power sector with other important sectors of the economy on electricity demand forecast. • Capture and adopt Demand Side Management in the forecast. • Capture and adopt T&D loss reduction programme in the forecast. 8. Annual updating of the electricity demand forecast

23. Generation planning and procurement security FA, FB and FC are the fixed costs, VA, VB and VC the variable costs of above plants

24. 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.

25. 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.

26. How much peaking capacity to build?

27. Calculation of mid load and base load capacity

28. 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.

29. 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

30. 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.

31. 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.

32. 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.

33. 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.

34. 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 substation- wise 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 inter-regional exchanges are envisaged.

35. 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.

36. 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.

37. 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.

38. CEA Transmission planning criteria (9) Annex-II

39. CEA Transmission planning criteria (10) 4.2 Thermal loading limits……………………..Annex-III

40. 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.

41. CEA Transmission planning criteria (12) 5.0 Steady state voltage limits

42. CEA Transmission planning criteria (13) 6.0 Security Standards 6.2 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.

43. CEA Transmission planning criteria (14) • 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. • 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. • The maximum angular separation between any two adjacent buses shall not normally exceed 30 degrees. 6.0 Security Standards 6.2 Steady state operation

44. CEA Transmission planning criteria (15) 6.0 Security Standards 6.3 Stability considerations • A. Transient Stability • The system shall remain stable under the contingency of outage of single largest unit. • 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).

45. CEA Transmission planning criteria (16) 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. 6.0 Security Standards 6.3 Stability considerations

46. CEA Transmission planning criteria (17) • 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. • 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. 6.0 Security Standards 6.3 Stability considerations

47. CEA Transmission planning criteria (17) 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. 6.0 Security Standards 6.3 Stability considerations

48. CEA Transmission planning criteria (18) • 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)

49. CEA Transmission planning criteria (19) • 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.

50. CEA Transmission planning criteria (20) • 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.