Indian power sector

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Indian power sector

  1. 1. Indian Power Sector STRUCTURAL, OPERATIONAL AND TRANSACTIONAL ASPECTS
  2. 2. Indian Power System  For the purpose of grid management and energy accounting, the Indian Power system is divided into Five Regional Grids – Northern Region Western Region Eastern Region North Eastern Region Southern Region
  3. 3. TWO ELECTRICAL REGIONS w.e.f Aug. 2006 NORTHERN REGION MAJOR INTER CONNECTIONS 1 ‘NEW’ GRID WESTERNRE GION NORTHEASTERN REGION EASTERN REGION TALCHER HVDC INTERCONNECTS 2 AC INTERCONNECTS SOUTHERN REGION KOLAR 1000 MW BACK TO BACK STATION AT BHADRAWATI(WR) 2X500 MW BACK TO BACK STATION AT GAZUWAKA(SR) TALCHER-II TO KOLAR 2500 MW BIPOLE LINK
  4. 4. Indian Power System Sector Hydro STATE 25067.6 PRIVATE 1306.2 CENTRAL 7887 TOTAL 34260.7 Installed Capacity as on 30-09-2007 (Figures in MW) Thermal Wind/ RES Coal Gas Diesel Total Nuclear /SHP Total 39431 3759.8 604.6 43795.4 0 2084 70947 4491.4 4183 597.1 9271.5 0 8091 18668.7 28260 5899 0 34159 4120 0 46166 72182.4 13841.8 1201.8 87226 4120 10175 135781.7 Thermal Wind/ RES/ Region Hydro Coal Gas Diesel Total Nuclear SHP Total NORTHERN 12671.1 18193.5 3433.2 15 21641.7 1180 1220.2 36713 WESTERN 7003.5 23635.2 5860.8 17.5 29513.5 1840 2670.3 41027.3 SOUTHERN 10646.2 15972.5 3586.3 939.3 20498.1 1100 5899.3 38143.7 EASTERN 2823.9 13996.2 190 17.2 14203.4 0 227.8 17255.1 N.EASTERN 1116 385 771.5 142.7 1299.2 0 146.1 2561.2 ISLANDS 0 0 0 70 70 0 11.4 81.4 ALL-INDIA 34260.7 72182.4 13841.8 1201.8 87226 4120 10175 135781.7 Installed capacity does not include benefits from projects in Bhutan
  5. 5. Power Supply Position National (April 07 – Nov 07) Peak Region Deman MW NORTHERN 32462 WESTERN 37955 SOUTHERN 26054 EASTERN 11385 NORTH1657 EASTERN Peak Peak Deficit / Energy Energy Energy Deficit/ Met Surplus Requir Availa Surplus MW MW % MU MU MU % 29495 -2967 -9.10% 147720 135962 -11758 -8% 27852 -10103 -26.60% 155108 134701 -20407 -13.20% 24194 -1860 -7.10% 122152 119075 -3077 -2.50% 10669 -686 -6% 50494 48503 -1991 -3.90% 1347 -310 -18.70% 5932 5285 -647 -10.90%
  6. 6. INTER STATE FLOWS AT PEAK HOUR WHEN ISGS DESPATCH IS FULL ER ISGS BHADRAWATI HVDC GAZUWAKA HVDC 143 MW Ramagundam 2480 MW APTRANSCO SYSTEM TALCHER-KOLAR HVDC TALCHER STG II 1640 MW 3 Nos. 400 kV lines & 2 Nos 220 kV lines ENT: 1728 MW 6 Nos. 400 kV lines & 2 Nos 220 kV lines 895 MW MAPS Nuclear 265 MW 585 MW Goa 95 MW TNEB SYSTEM KPTCL SYSTEM ENT: 1385 MW KAIGA Nuclear 450 MW 1480MW ENT: 2185 MW 940 MW 25 MW 262 MW Pondy NEYVELI II NEY EXP 1642 MW 4 Nos. 400 kV lines & 1 Nos 220 kV line KSEB SYSTEM ENT: 965 MW 4 Nos. 400 kV lines & 3 Nos 230 kV line
  7. 7. Installed capacity of Southern Region as on 30-04-2007 Sector State Private Central Total Hydro 10956.3 55.45 11011.7 Coal 7572.5 510 8090 16172.5 Gas 735.8 2500.5 350 3586.3 Diesel 362.52 576.8 939.32 Thermal total 8670.82 3587.3 8440 20698.1 Nuclear 1100 1100 Renewable 557.5 4414.1 4971.55 Total 20184.6 8056.8 9540 37781.4
  8. 8. Interstate lines
  9. 9. 0:15 1:15 2:15 3:15 4:15 5:15 6:15 7:15 8:15 9:15 10:15 11:15 12:15 13:15 14:15 15:15 16:15 17:15 18:15 19:15 20:15 21:15 22:15 23:15 Typical Demand pattern and frequency profile of Kerala 3000 49.6 2500 49.4 2000 49.2 1500 49 48.8 1000 48.6 500 48.4 0 48.2
  10. 10. ROLE OF LOAD DESPATCH CENTRES
  11. 11. 500 MW from unit 1 & 700 MW from unit 2 is the optimum dispatch (economic)
  12. 12. Assumption: Line can carry max. of 400 MW Transmission line opened because of failure
  13. 13. Corrective measure taken : Lower the generation of Unit 1 to 400 MW
  14. 14. For same contingency contingency condition is analysis, post
  15. 15.  Load Generation Balance(LGB) preparation Demand Forecasting  Scheduling of Central share  Power Purchase  Outage Planning  Preparation of Daily System Statistics  Functions of LD centers
  16. 16. Constraints in merrit order  Availability from hydal restricted on account of water availability  Naphtha based generation – Technical limits are stringent.  Minimum generation from hydro.  Time required for bringing in thermal generation.  Advantage of KSEB – Higher hydro.
  17. 17. Major problems existed in Indian grid operation  Low frequency during peak load hours, with frequency going down to 48.0-48.5 Hz for many hours every day.  High frequency during off peak hours, with frequency going up to 50.5 to 51 Hz for many hours every day.  Rapid and wide changes in frequency – 1 Hz change in 5 to 10 minutes, for many hours every day.  Very frequent grid disturbances, causing tripping of generating stations, interruption of supply to large blocks of consumers, and disintegration of the regional grids. One important reason attributed to the situation was the absence of direct incentives or penalties for the individual utilities responsible for the problems.
  18. 18. AVAILABILITY BASED TARIFF
  19. 19. Introduction to ABT    Availability based tariff is implemented in the Southern Region with effect from 1-1-2003. Implementation of ABT can be considered as a landmark in the process of power sector reforms in the country. Concept of performance based rate making and bench marking of operational standards. This approach helped to induce the regulated entities under this regime to significantly improve their performance and reduce operational costs.
  20. 20.  The earlier bulk tariff system recognised the total cost as consisting of two elements, namely capacity cost and energy cost. Both the fixed cost and the variable cost of a generating station were charged to the beneficiaries in proportion to the actual energy drawn by them during that period.  The ABT enables dispatch of power in relation to a schedule, given by every beneficiary based on the availability of allocated shares of Central generating stations, and other power that might be available. It enables penal tariffs to be charged when any utility or generating company acts against the grid discipline.
  21. 21.  ABT is a three part tariff ◦ Capacity charges (Fixed cost) ◦ Energy charges (Variable cost) ◦ UI charges Capacity charges and energy charges are settled monthly as per the Regional energy Account. UI charges are settled weekly Energy accounts are prepared and issued by the Southern Regional Power Committee Secretariat TARIFF STRUCTURE
  22. 22. Capacity Charges    The capacity charge is paid for the entitlement from each generating station. The entitlement includes the share allotted to each constituent, as per the Gadgil formula, special allocations and allocation by the ministry of power issued time to time from the unallocated portion. This payment is affected by the availability of the generating station. If the availability is lesser than the target availability fixed, the capacity charges payable will also be less.
  23. 23. Energy Charges The energy charge is for the energy scheduled from the generating station.  CERC has fixed the heat rate and the variable cost for each generating station under central sector.  Whether the constituent has drawn the entire scheduled energy or whether the generating station has generated as per the schedule does not matter in this case. 
  24. 24. Unscheduled Interchange (UI) The UI is the difference between the schedule and the actual drawal/ generation.  After many deliberations in various forums, CERC has admitted a time block consisting of 15 minutes as the basis for energy accounting.  In contrast to the capacity charges and energy charges, the UI bills are issued and settled weekly. 
  25. 25. What is UI?  UI – Unscheduled interchange  Demand of the grid is not constant  Frequency of the grid is not constant  Depending on various conditions, the tie line flow varies from instant to instant  Thus UI is unavoidable in an integrated network  UI can be harnessed effectively to the advantage of the constituents if system permits Rate depends on frequency
  26. 26. UI Rate corresponding to different frequencies from 07.01.2008 Frequency Less than 49.12 49.22 49.32 49.42 49.52 49.62 49.72 49.82 49.92 50.02 50.12 50.22 50.32 50.42 Abov e 49.0 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50.0 50.1 50.2 50.3 50.4 50.5 Rate Rs. 10.00 9.10 8.20 7.30 6.40 5.50 4.60 3.70 2.80 2.40 2.00 1.60 1.20 0.80 0.40 0.00 18ps/0.02Hz for freq less than 49.8 8ps/0.02Hz for freq more than 49.8
  27. 27. UI Rate with effect from 07.01.2008 50.44 50.32 50.20 50.08 49.96 49.84 49.72 49.60 49.48 49.36 49.24 49.12 49.02 10.00 9.00 8.00 7.00 6.00 5.00 4.00 3.00 2.00 1.00 0.00
  28. 28. Beneficiary UI Actual drawal by beneficiary -UI +UI Drawal Schedule by RLDC
  29. 29. Generator UI Installed Capacity(IC) Actual Generation by Generator Generator UI Declared Capability (DC) +UI -UI Chance of gaming Generation Schedule by RLDC
  30. 30. Merit order Dispatch 1 UI Rs.4.50 300MW Rs.7.50 Hydel 400MW 900MW Rs.1.50 220MW 180MW Available resource 200MW Rs.6.50 900MW Load 1700MW Technical minimum
  31. 31. Merit order Dispatch 2 UI Rs.2.50 300MW Rs.7.50 Hydel 280MW 900MW Rs.1.50 220MW 300MW Reduced generation from hydro 200MW Rs.6.50 900MW Load 1700MW Technical minimum Hydel reduced when frequency increased
  32. 32. Merit order Dispatch 3 UI Rs.8.50 300MW Rs.7.50 Hydel 550MW 150MW 220MW -120MW Maximum generation possible 900MW Rs.1.50 200MW Rs.6.50 900MW Load 1700MW Technical limitations in change of generation Export when frequency reduces
  33. 33. Merit order Dispatch 4 UI Rs.8.50 300MW Rs.7.50 Hydel 550MW 150MW 300MW -200MW Maximum generation possible 900MW Rs.1.50 200MW Rs.6.50 900MW Load 1700MW Continuous low frequency expected Export when frequency reduces
  34. 34. Merit order Dispatch 5 UI Rs.0.50 300MW Rs.7.50 Hydel 200MW 200MW Rs.6.50 900MW Rs.1.50 700MW 220MW 580MW Minimum generation possible Load 1700MW Surrendere d to Technical minimum Technical minimum Maximum import at very high frequency
  35. 35. VAR Rates Payable @5 ps/KVARH For . VAR injection at Voltages above 103% of rated voltage .VAR drawal at Voltages below 97% of rated voltage Receivable @5 ps/KVARH For . VAR drawal at Voltages above 103% of rated voltage . VAR injection at Voltages below 97% of rated voltage
  36. 36. Mechanism of ABT  The commercial mechanism of the ABT contemplates the disciplining of all three entities in the grid viz., the generator, transmitter and the beneficiaries.  The commercial mechanism is a self regulated discipline and binding on all concerned, as opposed to a regulator-imposed discipline.  The UI charges in the ABT mechanism combined with payment of capacity cost on availability basis, facilitates the marketing of both capacity and energy on a continuous basis, and enforcement of grid discipline.  The term "Availability Based Tariff" is appropriate, as it reflects all elements of capacity made available as well as capacity utilised.
  37. 37. FREQUENCY COMPARISION OF 2003 AND 2002 ( 18TH WEEK) 2002 2003 51.50 51.00 50.00 49.50 49.00 48.50 48.00 DAY OF THE WEEK Sun:00:00 Sat:00:00 Fri:00:00 Thu:00:00 Wed:00:00 Tue:00:00 47.50 Mon:00:00 FREQUENCY IN HZ 50.50
  38. 38. Jan-02 TIME IN HRS ----> Jan-03 23:00 22:00 21:00 20:00 19:00 18:00 17:00 16:00 15:00 14:00 13:00 12:00 11:00 10:00 9:00 8:00 7:00 6:00 5:00 4:00 3:00 2:00 1:00 0:00 VOLTAGE IN KV ---> COMPARISON OF BANGALORE VOLTAGE FOR 14TH JAN 420 410 400 390 380 370 360 350 340 330 320
  39. 39. 30th and 31st July 2012-northern grid-620 million people (9% of world population)22 states out of 28 were out-32 GWrailways, roadways and airports.  MEERWAD not affected-solar-off grid14kW  Effects of summer-over drawal  Political speculations  BIGGEST OUTAGE AFTER ABT IMPLEMENTATION (after 2001)
  40. 40.         Inadequate response of SLDCs to instructions of the RLDC to reduce the drawal. High loading of the 400kV Bina-Gwalior-Agra link. Weak inter regional power transmission corridors due to multiple outages. Encourage off grid operations-Micro grids – Renewables More peak load power stations HVDC links – asynchronous operation Spot settlement of UI Distribution and transmission privatization. BIGGEST OUTAGE AFTER ABT IMPLEMENTATION (INVESTIGATIONS)
  41. 41.  Nuclear power Plants to be brought under ABT  Timely UI payment to be enforced  Formation of Power Exchange  Implementation of Intra state ABT IPPS, SEB, DISCOMs and Captives ABT-FUTURE
  42. 42. Thank You

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