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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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slide1

INDIAN ELECTRICITY

GRID CODE

(IEGC)

Salient Features

Northern Regional Power System

Welcome

  • Largest sized hydro unit (180 MW at Chamera) in the country
slide2

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
slide3

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.

slide4

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.

slide5

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.

slide6

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

slide7

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

slide8

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

slide9

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

slide10

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.
slide11

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.
slide12

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.

slide13

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.

slide14

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.

slide15

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.
slide16

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.

slide17

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.
slide18

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.
slide19

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.

slide20

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
slide21

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
slide22

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)
slide23

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.
slide24

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.

slide25

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
slide26

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.
slide27

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.
slide28

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.
slide29

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 …..

slide30

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.
slide31

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
slide32

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

slide33

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 …..

slide34

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.

slide35

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.

slide36

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.
slide37

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
slide38

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

slide39

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.
slide40

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
slide41

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.
slide42

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.
slide43

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.

slide44

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.

slide45

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.

slide46

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.

slide47

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.

slide48

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.

slide49

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.

slide50

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.

slide51

NOMINAL(kV)

MAX. (kV)

MIN. (kV)

400

420

360

220

245

200

132

145

120

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

SYSTEM SECURITY ASPECTS :-

All regional constituents shall send all information / data, including DR/SER output, to RLDC for analysis of any grid disturbance / event. Access by RLDC to such information should not be blocked by any constituent.

Grid voltage should always be maintained within the operating range

slide52

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

DEMAND ESTIMATION

(Daily/Weekly/Monthly/Annually)

DEMAND CONTROL

(including manual disconnection)

Continued …..

slide53

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

  • PERIODIC REPORTS

Weekly report shall be issued by RLDC to all constituents and REB Secretariat covering for the past week

        • Frequency profile
        • Voltage profile
        • Major generation and transmission outages
        • Transmission constraints
        • Instances of persistent / significant non - compliance of IEGC.

Continued …..

slide54

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

  • OTHER REPORTS

RLDC to prepare quarterly report, bringing out

      • System constraints
      • Reduction in security standards & quality

of service and reasons thereof.

      • Actions taken by different agencies
      • Agencies responsible for constraints

as above.

slide55

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

OPERATIONAL LIASION PROCEDURE :-

To facilitate quick transfer of information between operational staff so as to correlate the required inputs for optimisation of decision making and actions.

slide56

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID

OBJECTIVE

To produce a coordinated Generation Outage Programme for the Regional Grid considering all available resources and constraints.

To minimise surplus or deficits, if any, in the system requirement of power and energy and operate system within security standards.

slide57

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID

OUTAGE PLANNING PROCESS

All SEBs/STUs, CTU, ISGS to provide REB Secreteriat their proposed outage programme of all elements in writing for the next financial year by 30th November each year.

Draft outage programme by 31st December to be brought out by REB Secreteriat.

Continued …..

slide58

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID

OUTAGE PLANNING PROCESS

Final outage programme ready by 31st January latest or as mutually decided in REB coordination meeting. This programme to be intimated to all regional constituents / RLDC.

Above annual programme to be reviewed on quarterly and monthly basis by REB Secreteriat.

Continued …..

slide59

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID

OUTAGE PLANNING PROCESS

  • Final approval required from RLDC prior to availing an outage. RLDC authorised to defer the planned outage in case of
      • Major grid disturbance
      •   System isolation
      •   Black out in a constituent state
      •   Any other event affecting system security
slide60

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

RECOVERY PROCEDURES

Detailed plans & procedures for restoration of the Grid to be developed by RLDC in consultation with all regional constituents / REB Secreteriat and to be reviewed / updated annually.

Restoration within the system of each constituent to be finalised by concerned constituent in co-ordination with RLDC. To be reviewed once every year.

Continued …..

slide61

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

RECOVERY PROCEDURES

List of Generating Stations with black start facility, inter-state / inter-regional ties, synchronising points and essential loads to be restored on priority to be prepared and to be available with RLDCs.

  For fast recovery, RLDC authorised to operate system with reduced security standards for voltage and frequency. 

Continued …..

slide62

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

RECOVERY PROCEDURES

All communication channels required for restoration process shall be used for operational communication only, till grid normalcy is restored.

slide63

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

EVENT INFORMATION

REPORTABLE EVENTS BY RLDC/ REGIONAL CONSTITUENTS

  • Violation of security standards
  •   Grid indiscipline
  • Non-compliance of RLDC's instructions
  •   System islanding/system split
  •   Region black out/partial black out
  • Protection failure on any element of ISTS, and on any item on the 'agreed list' of the intra - state systems
  •   Power system instability
  •   Tripping of any element of the regional grid
slide64

CHAPTER – 6OPERATIONAL CODE FOR REGIONAL GRIDS

FORM OF WRITTEN REPORTS

  • Time and date of event
  •   Location
  •   Plant and / or equipment directly involved
  •   Description and cause of event
  •   Antecedent conditions
  •   Demand and / or generation (in MW) interrupted and its duration
  •   All relevant system data including copies of all DR/EL/DAS outputs
  •   Sequence of trippings with time
  •   Details of relay flags
  • Remedial measures
slide65

CHAPTER – 7SCHEDULING AND DESPATCH CODE

  • COVERING
  • Objective
  • Scope
  • Demarcation of responsibilities
  • Scheduling & Despatch procedure
  • Reactive Power and Voltage Control

ANNEX

        • Complementary Commercial Mechanism
        • Metering Details (to be included later)
slide66

CHAPTER – 7SCHEDULING AND DESPATCH CODE

OBJECTIVE :-

To enable RLDCs to prepare the despatch schedule for each beneficiary. It also provides methodology of issuing real time despatch / drawal instructions and rescheduling, if required, as also commercial arrangement for the deviations from schedules and mechanism for reactive power pricing.

slide67

CHAPTER – 7SCHEDULING AND DESPATCH CODE

SCOPE :-

Applicable to RLDC / SLDCs, ISGS, SEBs / STUs and other beneficiaries in the Grid.

Procedure for the generating stations of BBMB shall be separately formulated by NRLDC in consultation with BBMB.

slide68

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • Regional grid shall be operated as loose power pools with states having full operational autonomy.
  • System of each state shall be treated as a notional control area. States shall generally be expected to maintain their actual drawal from the Regional Grid close to the net drawal schedule (sum of scheduled drawal from ISGS and any bilateral inter change).
slide69

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • Tight control on the deviations from schedule by states not mandated due to non availability of requisite facilities for minute – to - minute on line regulation of drawals. Deviations from schedule to be priced appropriately.
  • Whenever system frequency is below 49.5 Hz, states shall endeavor to restrict their net drawal to within the schedule. Loadshedding to be resorted to in case frequency < 49.0 Hz.
slide70

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • SLDCs / STUs to carry out short - term and long - term demand estimation to enable advance planning to meet the consumer’s load without overdrawing.
  • ISGS shall be responsible for generating as per the daily schedule advised by RLDC.
  • ISGS allowed to deviate from the schedule, in line with the flexibility allowed to States. Deviations are to be appropriately priced.
slide71

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • Whenever system frequency > 50.3 Hz, actual net injection of ISGS should not exceed scheduled despatch.
  • RLDC nay direct the SLDCs / ISGS to increase / decrease their drawal / generation in case of contingencies and such directions shall be immediately complied.
  • Outage of Generation and Transmission system to be coordinated through OCC / RLDC. Outage requiring restriction on ISGS generation to be planned carefully.
slide72

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • Agreements between constituents and ISGS indicating shares, drawal pattern, tariffs, payment terms etc. to be filed with RLDCs and REB Secreteriats for being considered in REA. Similar filing required in respect of bilateral agreements.
  •   Frequency linked despatch guidelines, as issued by RLDC, should be followed by all constituents unless otherwise advised by RLDC.
slide73

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • ISGS to declare plant capabilities faithfully and avoid gaming. RLDC may ask the ISGS to explain instances of gaming, if any, with necessary backup data.
  • CTU would be allowed to install Special Energy Meters on all Inter-Utility Exchange Points and the constituents would extend the necessary assistance to CTU in timely collection of metered data.
slide74

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • RLDC to compute
      • Actual Net Injection of each ISGS
      • Actual Net Drawal of each beneficiary

based on above meter readings and forward the same to REB Secreteriat on weekly basis by each Thursday noon for the seven day period ending previous Sunday Mid-Night.

slide75

CHAPTER – 7SCHEDULING AND DESPATCH CODE

DEMARCATION OF RESPONSIBILITIES :-

  • Computations of RLDC open to checking / verification by constituents for 20 days. In case any mistake / omission is detected, the RLDC shall forthwith make a complete check and rectify the same.
scheduling and despatch procedure

CHAPTER – 7SCHEDULING AND DESPATCH CODE

SCHEDULING AND DESPATCH PROCEDURE

All ISGS stations with capacities and allocated shares to be listed out

slide77

CHAPTER – 7SCHEDULING AND DESPATCH CODE

SCHEDULING AND DESPATCH PROCEDURE:-

  • RLDC to ensure schedules are operationally reasonable with respect to ramping up / ramping down rates and the minimum to maximum ratio of generation.
  • ISGS / SLDCs to inform any modifications in foreseen capability / station wise drawal schedule to RLDC by 2200 hrs. RLDC to issue final schedule in such cases by 2300 hrs.
  • Revisions in schedule permitted during the course of the day. Such revisions effective one hour after the first advise is received by the RLDC.
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CHAPTER – 7SCHEDULING AND DESPATCH CODE

SCHEDULING AND DESPATCH PROCEDURE:-

  • RLDC to check for transmission constraints, if any, before finalising the drawal / despatch schedule.
  • On completion of the operating day, schedule, as finally implemented during the day shall be issued by RLDC. This would be the datum for commercial accounting.
  • RLDC to properly document all the above information exchanged between ISGS and RLDC, constituents and RLDC etc.
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REVISION OF SCHEDULES

S.no.

Event

Revision effective from

1.

Forced outage of an ISGS unit.

4th time block after generator advises NRLDC of change in declared capability.

2.

Transmission constraint

4th time block + post facto revisions for first three time blocks.

3.

Revision of ISGS capability

6th time block.

4.

Revision of requisition by any beneficiary

6th time block

5.

Suo-moto revisions by NRLDC

4th time block.

Note: In all the above cases, the 15 minute time block in which NRLDC receives the above advise would be considered as the first one.

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CHAPTER – 7SCHEDULING AND DESPATCH CODE

SCHEDULING AND DESPATCH PROCEDURE:-

  • All records in respect of above open to all constituents for any checking / verification for a period of 20 days.
slide81

CHAPTER – 7SCHEDULING AND DESPATCH CODE

REACTIVE POWER AND VOLTAGE CONTROL:-

  • Beneficiaries to provide local VAR compensation / generation so as not to draw VARs from EHV grid. Tight control not being insisted upon presently. However, VAR pricing for beneficiaries would be as under :
      • pay for VAR drawal at points where voltage < 97%
      • get paid for VAR return at points where voltage < 97%
      • get paid for VAR drawal at points where voltage > 103%
      • pay for VAR return at points where voltage > 103%
slide82

CHAPTER – 7SCHEDULING AND DESPATCH CODE

REACTIVE POWER AND VOLTAGE CONTROL:-

  • Charges / payments for VARs - 4 paise/kVARh upto 31st March, 2001 and escalated at 5% per year thereafter unless otherwise revised by CERC.
  • RLDC may direct a beneficiary to curtail its VAR drawal / injection in case of threat to equipment safety / grid security.
  • Switching IN / OUT of Bus / Line Reactors of 400 kV lines and tap changing of 400 / 220 kV ICTs to be done as per RLDC instructions only.
slide83

CHAPTER – 7SCHEDULING AND DESPATCH CODE

REACTIVE POWER AND VOLTAGE CONTROL:-

  • ISGS to generate / absorb Reactive Power as per RLDC instructions taking into account capability limits and without sacrificing active generation required. No payments to generating companies for such VAR generation / absorption.
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CHAPTER – 7SCHEDULING AND DESPATCH CODE

COMPLEMENTARY COMMERCIAL MECHANISMS :-

  • Payments to ISGS from beneficiaries :
      • Capacity charge based on declared (before the fact) ex-power plant capability and entitlement of beneficiary
      • Energy charge (rupees per MWh) based on schedule drawals
  • Payments to / from UI settlement system based on Unscheduled Interchange (UI) and frequency.
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CHAPTER – 7SCHEDULING AND DESPATCH CODE

COMPLEMENTARY COMMERCIAL MECHANISMS :-

  • REA to be prepared by REB Secreteriat on weekly basis based on Special Energy Meter (SEM) data provided by RLDCs.
  •   Weekly bills for UI and Reactive Exchanges to be raised by REB Secreteriat. These bills to have higher priority.
slide86

CHAPTER – 8MANAGEMENT OF IEGC

OBJECTIVES :-

Methodology of managing the IEGC document, pursuing of any change / modifications required and constituents responsibility to effect that change.

slide87

CHAPTER – 8MANAGEMENT OF IEGC

  • SCOPE :-
  • CTU responsible for coordinating, managing and servicing the IEGC document
  • IEGC Review Panel to consider proposals for modifications
  • Decision of review panel to be put upto CERC
slide88

CHAPTER – 8MANAGEMENT OF IEGC

IEGC REVIEW PANEL :-

To be constituted by CERC comprising one representative from

01. CEA

02. NTPC

03. NHPC

04. NPC

05. Two from each REB representing the constituents

06. PTC

07. One representative from Mega Power Projects

08. One representative from Railways / Steel / Coal

09. One representative from CII / FICCI / ASSOCHAM

10. One representative from CERC as an observer

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CHAPTER – 8MANAGEMENT OF IEGC

IEGC REVIEW PANEL :-

Director (Operations), POWERGRID shall be the Chairman and Convener of the Panel and preside over its meetings.

Back

slide90

Thank You

Thank You

slide91

Central Govt. CEA

REB

State Govt.

SLDC

CERC

SEB/STU

SERC

CTU

G1

G2

RLDC

Intra State System

ISTS

ISGS

Load

IEGC to Operate on the periphery

X=

L

- G

G

L1

L2

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CONTROL AREAS

CS - 2

CS - 1

CS - 3

SEB-A

SEB-B

SEB-C

STATE

SLDC

SEB's GRID

COORDINATES/

DIRECTS

DISTR - A

DISTR - C

DISTR - B

RLDC

REGIONAL GRID

COORDINATES/

STATE

GENR.

CENTRAL

IPP

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