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Largest sized hydro unit (180 MW at Chamera) in the country

INDIAN ELECTRICITY GRID CODE (IEGC). Salient Features Northern Regional Power System Welcome. Largest sized hydro unit (180 MW at Chamera) in the country. CONTENTS:. Need for an IEGC. Development of the present IEGC version.

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Largest sized hydro unit (180 MW at Chamera) in the country

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  1. INDIAN ELECTRICITY GRID CODE (IEGC) Salient Features Northern Regional Power System Welcome • Largest sized hydro unit (180 MW at Chamera) in the country

  2. CONTENTS: • Need for an IEGC • Development of the present IEGC version • Indian Electricity Grid Code : Contents • IEGC : Demarcation of Resposibilities • ABT / IEGC Clauses • ABT Feedback

  3. NEED FOR AN IEGC PeriodSituation Early 1970sVertically integrated SEBs. Late 1970s- Entry of Central Generating Utilities. Early1980s Gradual increase in disputes Late 1980s Increase in Central Sector Utilities. Early 1990s Unresolved commercial disputes - resulted in need of an umpire. 1994-96 Transfer of RLDCs from CEA to POWERGRID. 1997-99 Unbundling of SEBs , possible entry of Mega IPPs and more independent players - more scope for disputes.

  4. DEVELOPMENT OF IEGC Feb 1999 Special Working Group Under Shri D.P. Sinha, Member CERC Submits Its Report Indicating Modalities for Formulating IEGC. 31st Mar 99 CERC issues directives to POWERGRID for preparing IEGC and organisational arrangements for the CTU. 9th April 99 Draft IEGC submitted to CERC (Petition 1/99). Apr-May 99 Draft IEGC made public on the directions of CERC to elicit comments from all sections.

  5. DEVELOPMENT OF IEGC July 1999 Public hearings by CERC on the draft IEGC on 20th, 21st & 23rd July 1999. 30th Aug 99 Revised IEGC draft submitted by POWERGRID to CERC. 30th Oct 99&CERC’s orders on above IEGC draft (Aug. 99 22nd Nov 99Version) 7th Dec 99 IEGC draft (Aug. 99 Version) revised as per above orders and filed before CERC.

  6. DEVELOPMENT OF IEGC 21st Dec 99 Final directions of CERC on the above IEGC draft. 28th Dec 99 First version of IEGC as per above orders and circulated to all agencies & implemented w.e.from 1st Feb 2000 24th July IEGC Review Panel constitution approved 2000 by CERC 17th Nov Rules & Guidelines of IEGC Review Panel 2000 approved by CERC

  7. DEVELOPMENT OF IEGC 29th March Amendments to IEGC forwarded by 2001 Review Panel to CERC after meetings on 12th Feb & 26th March 2001 22nd Feb First review of IEGC approved by CERC 2002 based on the draft submitted by CTU based on orders dated 3rd Aug 2001 and meeting of Review Panel on 10th Dec 2001. 1st April First review of IEGC in force. 2002

  8. Indian Electricity Grid Code Chapter – 1 --- General Chapter – 2 --- Role of RLDC, REB, CTU etc. and their organisational linkages Chapter – 3 --- Planning Code for Interstate transmission Chapter – 4 --- Connection conditions Chapter – 5 --- Grant of transmission license

  9. Indian Electricity Grid Code Chapter – 6 --- Operating Code for Regional Grids Chapter – 7 --- Scheduling & Despatch Code Annex – 1 --- Complementary Commercial Mechanisms Annex – 2 --- Metering Details Chapter – 8 --- Management of IEGC

  10. CHAPTER – 1 GENERAL Objective of IEGC :- The IEGC is a Compendium of Technical Rules, covering all utilities connected to or using the Inter-state Transmission System (ISTS) and provides the following : • Documentation of the principles and procedures defining the relationship between the various users of the ISTS as well as the RLDCs & SLDCs. • Facilitates the Operation, Maintenance, Development and Planning of Economic and Reliable Regional Grid. • Facilitates beneficial trading of electricity by defining a common basis of operation of the ISTS, applicable to all the users of the ISTS.

  11. CHAPTER – 1 GENERAL Scope of IEGC :- • Applicable to all parties that connect with and/or utilise the ISTS. • DVC treated similar as STU/SEB. • BBMB Generating Stations treated as Intra-State while its Transmission System treated as ISTS.

  12. CHAPTER – 1 GENERAL Non - Compliance of IEGC :- • Persistent non - compliance of any stipulation of IEGC by Constituent / ISGS / CTU shall be reported to Member Secretary, REB. • Non – compliance of IEGC stipulations by RLDC / REB shall be reported to CEA. • MS - REB / CEA would take up the matter with the defaulting agency for terminating non - compliance. • In case of inadequate response to above efforts by MS REB/CEA, non - compliance shall be reported to CERC. • CERC after due process may order the defaulting agency for compliance. CEA/REB SHALL MAINTAIN APPROPRIATE RECORDS OF SUCH VIOLATIONS.

  13. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS FREQUENCY VARIATION INDEX (FVI) :- A performance index representing the degree of frequency variation from the nominal value of 50 Hz, over a specified period of time. N ∑ (Fi– 50)2 i=1 FVI = 10 X ----------------------------- N where, Fi = Actual Frequency in Hz at ith time period, N = Number of measurements over the specified period of time.

  14. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS INTER STATE GENERATING STATION (ISGS) :- A Central / Mega Power Project/ other Generating Station in which two or more than two states have a share and whose scheduling is to be coordinated by the RLDC.

  15. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS INTER STATE TRANSMISSION SYSTEM (ISTS) :- Any system for the conveyance of energy by the means of a main transmission line from the territory of one state to another state and includes : • The conveyance of energy across the territory of an intervening state as well as conveyance within the state which is incidental to such interstate transmission of energy. • The transmission of energy within the territory of a state on a system built, owned, operated, maintained or controlled by the Central Transmission Utility (CTU) or by any person /agency under the supervision and control of a CTU.

  16. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS STANDING COMMITTEE FOR TRANSMISSION PLANNING : A committee constituted by the CEA to discuss, review and finalise the proposals for ISTS and associated Intra-State Systems.

  17. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES • Role of RLDCs :- EXTRACTS FROM ‘ELECTRICITY SUPPLY ACT, 1948’ – • RLDCs Shall be the Apex body to ensure integrated operation of the Power System in the concerned Region. • RLDCs may give such directions and exercise such supervision and control as may be required for ensuring integrated grid operations and for achieving the maximum economy and efficiency in the operation of the Power System in the Region under its control.

  18. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES • Role of RLDCs :- EXCLUSIVE FUNCTIONS OF RLDC AS DEFINED IN IEGC • System operation and control including Inter - State / Inter - Regional transfer of power, covering contingency analysis and operational planning, on real time basis. • Scheduling / Rescheduling of Generation. • System restoration following grid disturbances. • Metering and data collection • Compiling and furnishing data pertaining to system operation.

  19. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES B. Role of REBs :- Subject to the provisions of Sections 55(1) to 55 (6) of the ES Act 1948, REBs in the Region may mutually agree from time to time on matters concerning the smooth operation of the Power System in that Region and every agency involved in the operation of the Power System shall comply with the decision of the Regional Electricity Boards.

  20. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES • Role of REBs :- Functions of REB which facilitate the smooth operation :- • Operational planning including planning of outages of Generators and Transmission System • Co-ordination of protection system • Finalisation of Automatic Under - Frequency Load Shedding Scheme • Regional Energy Accounting including operation of the Pool Account

  21. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES • Role of REBs :- Functions of REB which facilitate the smooth operation :- • Exploring possibilities of Inter – State / Inter - Regional transfer of power • To review reactive compensation to be provided by various agencies at regular intervals say on a yearly basis through studies carried out in association with the CTU and other constituents

  22. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES C. Role of CTU :- • To undertake transmission of energy through ISTS • To discharge all functions of planning and co- ordination related to ISTS with STUs, GoI, State Govt., Gen. Cos, REBs, CEA and Licensees. • To exercise supervision and control over the ISTS (for systems owned, operated and maintained by it as well as transmission licensees)

  23. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES C. Role of CTU :- • To operate the RLDCs until otherwise specified by the Central Government. • To enter into agreements with any transmission licensee for exclusive use of the latter’s Transmission System.

  24. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES D. Role of CEA :- Subject to regulations made under the ERC Act,1998 by the Central Commission in the case of RLDCs and the State Commission in case of SLDCs, any dispute with reference to the operation of the Power System including grid operation and as to whether any directions issued by RLDC under subsection 55(3) or 55(4) of the amended ES Act, 1948 is reasonable or not, shall be referred to the Authority for decision. Provided that pending the decision of the Authority, the directions of the RLDC or the SLDCs, as the case may be, shall be complied with.

  25. CHAPTER – 2ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES D. Role of SLDC :- • Demand Estimation & Control • Scheduling of own generation • Scheduling of ISGS limited to entitlements • Ensure compliance of directions of RLDC by all constituents • Reporting of events to RLDC • System operation & Control

  26. CHAPTER – 3PLANNING CODE FOR ISTS Objectives :- • Specify principles, procedures and criteria which shall be used in development of ISTS. • Promote coordination amongst all regional constituents in any development of ISTS. • Provide methodology for information exchange amongst regional constituents in planning and development of ISTS. Scope :- • Applicable to all utilities using the ISTS and involved in its development.

  27. CHAPTER – 3PLANNING CODE FOR ISTS Planning Methodology :- • CEA to develop and update perspective transmission plan (10-15 yrs) for ISTS as well as Intra - State. • CTU to develop annually Five Year Plans fitting into the above perspective plan. • System strengthening schemes to be identified additionally by CTU in consultation with CEA. • ISTS proposals to be discussed, reviewed and finalised in the meeting of the ‘Standing Committee for Transmission System Planning' constituted by CEA for each Region.

  28. CHAPTER – 3PLANNING CODE FOR ISTS Planning Methodology :- • CTU Five Year Plan to be finalised by 30th September each year comprising interalia • additional equipment such as ICTs, Capacitors, Ractors etc. • Schemes open for private investors. • Action taken and progress of schemes. • STUs should plan their system based on the CTU 5 Year Plan.

  29. CHAPTER – 3PLANNING CODE FOR ISTS Planning Criteria :- • ISTS shall be capable of withstanding and be secured against the following outages without necessitating load shedding or rescheduling of generation during steady state operation. Outage of a 132 kV D/C line or Outage of a 220 kV D/C line or Outage of a 400 kV S/C line or Outage of a single ICT Continued …..

  30. CHAPTER – 3PLANNING CODE FOR ISTS Planning Criteria :- or Outage of one pole of HVDC bipole or Outage of 765 kV S/C line • The aforesaid contingencies would be superimposed over a planned outage of another 220 kV D/C line or 400 kV S/C line in another corridor and not emanating from the same sub-station. • ISTS shall be capable of withstanding the loss of most severe single system infeed without loss of stability.

  31. CHAPTER – 3PLANNING CODE FOR ISTS Planning Criteria :- ANY ONE OF THE AFORESAID EVENTS SHALL NOT CAUSE • loss of supply • abnormal frequency on sustained basis • unacceptable high or low voltage • system instability • unacceptable overloading of ISTS elements

  32. CHAPTER – 3PLANNING CODE FOR ISTS Planning Data :- SEBs/ Utilities/ MPPs/ ISGS/ IPPs to supply standard planning data to CTU by 31st March every year in formats as approved by CERC in August 2001

  33. CHAPTER – 4CONNECTION CONDITION Connection conditions specify the minimum technical and design criteria to be complied with by CTU and any agency connected to or seeking connection to ISTS. Objectives :- • Basic rules for connections are complied with to treat all agencies in a non-discriminatory manner. • No adverse effects on the new equipment connected to ISTS, the ISTS and other agency’s system. Continued …..

  34. CHAPTER – 4CONNECTION CONDITION Objectives :- • Clear identification of ownership and responsibility for all equipment at the connection point. Scope :- Applicable to all constituents and agencies connected to and involved in developing the ISTS.

  35. CHAPTER – 4CONNECTION CONDITION For New Connections :- Connection Agreement is a must. For Existing Connections :- Agreement should be in place within one year i.e. by 01.04.2003. In case of a delay in finalising the connection conditions, constituent to approach CERC with a petition along with CTU’s recommendation/comments. Cost of modification, if any, shall be borne by concerned constituent.

  36. CHAPTER – 4CONNECTION CONDITION CONNECTION AGREEMENT WOULD INCLUDE :- • A condition requiring both parties to comply with the IEGC. • Details of connection, technical requirements and commercial arrangements. • Details of any capital expenditure arising from reinforcements required, if any. • Site Responsibility Schedule. • General philosophy, guidelines etc. on protection.

  37. CHAPTER – 4CONNECTION CONDITION RELEVANT AREAS IN CONNECTION CONDITIONS:- • ISTS parameter variations • Substation equipment • Fault Clearance Times • Generating Units and Power Stations • Reactive Power Compensation • Communication Facilities • System Recording Instruments • Responsibilities for operational safety • Procedure for site access, site operational activities and maintenance standards

  38. CHAPTER – 4CONNECTION CONDITION SCHEDULE OF ASSETS OF REGIONAL GRID:- CTU shall submit annually to CERC by 30th September each year a schedule of transmission assets which constitute the regional grid as on 31st March of that year indicating ownership on which RLDC has operational control and responsibility

  39. CHAPTER – 5GRANT OF TRANSMISSION LICENCE • Separate regulations by CERC would govern the grant of transmission license. • This chapter shall not be subject to review by the IEGC Review Panel.

  40. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS • COVERING • Operational policy •   System security aspects •   Demand estimation • Demand control •   Periodic reports •   Operational liasion • Outage planning •   Recovery procedures •   Event information

  41. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS OPERATIONAL POLICY:- • Primary objective of integrated operation is to enhance the overall operational economy and reliability of the entire network. • RLDC shall supervise overall real time operation of the regional code. •   Regional constituents shall comply with this operating code.

  42. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS OPERATIONAL POLICY:- • Detailed internal operating procedures consistent with IEGC to be developed and maintained by each RLDC. • Qualified and adequately trained personnel at all locations.

  43. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All regional constituents shall endeavor to operate their systems in synchronism with each other at all times.   Deliberate isolation of any part of the grid should be done only under a grave emergency or when specifically instructed by RLDC. In case of such isolation, synchronisation of the isolated system to be done at the earliest.

  44. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Removal of any trunk element from service to be done only on RLDC's instructions. Any such operations under emergency situation to be informed to RLDC at the earliest.   Trippings of trunk elements to be informed to RLDC as soon as possible, say within ten minutes of the event with reason (to the extent determined) and likely time of restoration.

  45. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Governors, with 3 to 6% droop setting, to be in normal operation on all generating units irrespective of ownership, type & size. Any deviation for units > 50 mw size to be informed to RLDC along with reason and duration of such operation.   Suppression of normal governor action, dead band, time delays introduced through other control features not to be resorted to.

  46. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All generating units shall normally be capable of picking up 5% extra load instantaneously (at least up to 105% MCR) for at least five minutes when frequency falls due to any contingency. RLDC’s approval required for any unit > 50 MW kept in operation without this requirement.   Recommended rate for decrease or increase of generation through supplementary control is 1.0% per minute or as per manufacturer’s limits. Faster pick up possible if frequency falls below 49.5Hz.

  47. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Reduction in generation / increase in load by 100 MW and above suddenly would not be permitted without prior intimation to and consent of the RLDC.   AVRs on all generating units to be in service and PSS (wherever provided) to be properly tuned as per the plan of CTU. CTU will be allowed to carry out tuning / checking of PSS wherever considered necessary.

  48. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Provision of protection and relay settings to be coordinated periodically by the protection committee of the REB.   Constituents to endeavor operation of system between 49.0 - 50.5 Hz, the frequency range within which all steam turbines conforming to IEC standards can safely operate.

  49. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All regional constituents to provide automatic under frequency relay load-shedding in their respective systems as finalised by REB. Constituents to ensure that the scheme is functional. No u/f relay to be bypassed without RLDC's prior consent, who shall also promptly inform REB about the locations where these relays are temporarily out. Periodic inspection of u/f relays to be done by REBs who shall also maintain proper records of such inspection.

  50. CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Procedures to recover from partial / total collapse of the grid to be developed and followed by all constituents. Adequate and reliable communication facility internally and with other constituents / RLDC to be provided by all constituents.

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