Rgmo Operation Procedure

JULY-2013 REV 0

TABLE OF CONTENTS .

Page No 1. General…………………………………………………………………:01 2. Network Security and System Operation…………………………….:05 3. Demand Monitoring & Control Procedure………..…………………:16 4. Outage Planning……………………………………………………….:20 5. Defence Mechanisms ……………………………………….................:24 6. Collective Transaction Procedures………………………………..….:27 7. Scheduling & Despatch Procedures……………..……………………:30 8. Grid Disturbances & Revival Procedure……………………………..:34 9. Event Information & Reporting Procedure……………………...…..:37 10. Switching Coordination……………………………………………….:39

ANNEXURES

Page No I.

Frequency Linked Despatch Guidelines…………………….….:42

II.

FRC-CERC Approved Procedure and Formats………………:44

III.

Surge Impedance Loading(SIL) of Transmission Lines……....:73

IV.

Thermal loading-As per CEA Planning Criteria…………….…:74

V.

NLDC Advisory on High capacity 765kV corridors…………...:76

VI.

Congestion Formats……………………………………………..:84

VII. UI Price Vector…………………………………………………..:91 VIII. List of important Grid Elements………………………….……..:94 IX.

Procedure for Outage Planning - Proposed……………..……..:115

X.

UFR & df/dt Load Shedding…………………………………….:129

XI.

System Protection Schemes-All India Level……………………:136

XII. Islanding Schemes…………………………………………….….:168 XIII. Multiple Element Outage Circular………………………… .….:178 XIV. Regional Power Maps…………………………………………....:179 XV. Glossary and Definitions………………………………………...:192

ACRONYMS CERC - Central Electricity Regulatory Commission SERC - State Electricity Regulatory Commission IEGC - Indian Electricity Grid Code NLDC - National Load Despatch Centre RLDC - Regional Load Despatch Centre SLDC - State Load Despatch Centre TTC

- Total Transfer Capability

ATC

- Available Transfer Capability

TRM - Transmission Reliability Margin ISGS - Inter State Generating Stations ISTS

- Inter State Transmission System

CEA

- Central Electricity Authority

STU

- State Transmission Utilities

CTU

- Central Transmission Utility

RPC

- Regional Power Committee

STOA - Short-term Open Access MTOA - Medium-term Open Access OCC

- Operation Coordination Committee

IPP

- Independent Power Producer

DR

- Disturbance Recorder

AVR - Automatic Voltage Regulator SVC

- Static VAR Compensator

UI

- Unscheduled Interchange

NER

- North Eastern Region

RGMO - Restricted Governor Mode of Operation FGMO - Free Governor Mode of Operation HVDC - High Voltage Direct Current MCR - Maximum Continuous Rating (MCR) UFR

- Under Frequency Relay

FRC

- Frequency Response Characteristic

1. General 1.1

Objective:-

1.1.1

Operating Procedures of National Load Despatch Centre (NLDC) document has been developed by NLDC as per Cl. 5.1(e) of Indian Electricity Grid Code (IEGC) in consultation with the RLDCs for the guidance of the staff of NLDC. This document is brought out in line with IEGC, 2010. After that Hon’ble CERC issued amendment to IEGC principal regulation (2010) on 05/03/12. The revision/updation of this procedure is based on amendment in various regulations, recent Orders/Regulations issued by Hon’ble Central Electricity Regulatory Commission (CERC) and recent changes in the power sector. CERC amended IEGC, UI Regulations, Grant of Connectivity, LTA & MTOA in ISTS and related matters Regulations, Terms & Conditions of Tariff Regulations, Procedure, Terms and Conditions for Grant of Trading Licence and other related matters Regulations. Also the procedure for relieving congestion in real time operation has also been revised by NLDC and approved by CERC vide its order dated 22.04.2013, Procedure for assessment of Frequency Response Characteristic (FRC) of Control Areas was approved by CERC and Manual on Transmission Planning Criteria was revised by CEA in Jan 2013. CERC has approved the detailed "Procedure for the Implementation of the Mechanism of Renewable Regulatory Fund" under Regulation 6.1 (d) of Central Electricity Regulatory Commission (Indian Electricity Grid Code), Regulations 2010 vide its order dt 09-07-13. This procedure supersedes the earlier procedure issued by NLDC in June, 2012.

1.1.2 The real time operation of National Grid is one of the important functions of NLDC. As more and more inter regional links are coming up and more number of 765kV lines are coming, demand rising rapidly, the task of real time grid operation is becoming more and more complex. The Indian Grid has interconnections with neighbouring countries like Bhutan and Nepal also. In India, two power exchanges are in operation as per the regulations of CERC for collective transactions and the approved procedure prepared by NLDC. The need was felt to develop the written document for the guidance of real time operator of National Grid and to develop the reference manual for day to day operation. 1.1.3

Objective of this document is to clearly spell out the procedures adopted for the integrated system operation and roles of each agency and their responsibilities in grid operation in compliance of IEGC. This document aims at operation and development of national power system in the most efficient, economic, secure and reliable manner. This document also aims to facilitate beneficial trading opportunities to harness bottled up power. These procedures are to be read in conjunction with the Central Electricity Regulatory Commission (Indian Electricity Grid Code) Regulations, 2010 IEGC and its first amendment2012, CEA (Grid Standards) regulation, 2010 and respective RLDCs Operating Procedures. If any ambiguity arises in interpretation of this operating procedure, the meaning, intent and the purpose of clauses as provided in IEGC and CEA (Grid Standards) shall prevail.

1.2

Role of NLDC:-

1.2.1

National Load Despatch Centre (NLDC) has been constituted as per Ministry of Power (MOP) notification, Government of India, under section 26(2) of the Act, dated 2nd March 2005 and is the apex body to ensure integrated operation of the national power system.

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1.2.2

The main functions assigned to NLDC as per the above notification are: a) Supervision over the Regional Load Despatch Centres. b) Scheduling and despatch of electricity over inter-regional links in accordance with grid standards specified by the Authority and Grid Code specified by Central Commission in coordination with Regional Load Despatch Centres. c) Coordination with Regional Load Despatch Centres for achieving maximum economy and efficiency in the operation of National Grid. d) Monitoring of operations and grid security of the National Grid. e) Supervision and control over the inter-regional links as shall be required for ensuring stability of the power system under its control. f) Coordination with Regional Power Committees for regional outage schedule in the national perspective to ensure optimal utilization of power resources. g) Coordination with Regional Load Despatch Centres for the energy accounting of interregional exchange of power. h) Coordination for restoration of synchronous operation of national grid with Regional Load Despatch Centres. i) Coordination for trans-national exchange of power. j) Providing operational feedback for national grid planning to the Authority and Central Transmission Utility. k) Levy and collection of such fee and charges from the generating companies or licensees involved in the power system, as may be specified by the Central Commission. l) Dissemination of information relating to operations of transmission system in accordance with directions or regulations issued by Central Government from time to time.

1.2.3 NLDC shall also carry out the following functions as per directions issued from time to time. a) NLDC is the nodal agency for collective transactions as per CL.5 of CERC (Open Access in Inter-State Transmission) Regulations, 2008. b) NLDC is the implementing agency for (Sharing of Inter-State Transmission Charges and Losses) Regulations as per Cl 18.1 of the above regulation. c) NLDC is the Central Agency for Renewable Energy Certificate(REC) mechanism vide CERC Order dated 29.01.2010. d) NLDC would act as the Central control room in case of natural & man made Emergency/disaster where it affects the power system operation vide MOP letter dt 27-052009. e) Any other function as may be assigned by the Commission by order or regulations from time to time.

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1.3

Role of RLDC:According to Sections 28 and 29 of Electricity Act, 2003, the functions of RLDCs are as follows: a) The Regional Load Despatch Centre shall be the apex body to ensure integrated operation of the power system in the concerned region. b) The Regional Load Despatch Centre shall comply with such principles, guidelines and methodologies in respect of wheeling and optimum scheduling and despatch of electricity as may be specified in the Grid Code. c) The Regional Load Despatch Centre shall – a. be responsible for optimum scheduling and despatch of electricity within the region, in accordance with the contracts entered into with the licensees or the generating companies operating in the region; b. monitor grid operations; c. keep accounts of quantity of electricity transmitted through the regional grid; d. exercise supervision and control over the Inter State Transmission System ; and e. be responsible for carrying out real time operations for grid control and despatch of electricity within the region through secure and economic operation of the regional grid in accordance with the Grid Standards and the Grid Code. d) The Regional Load Despatch Centre may give such directions and exercise such supervision and control as may be required for ensuring stability of grid operations and for achieving the maximum economy and efficiency in the operation of the power system in the region under its control. e) Every licensee, generating company, generating station, sub-station and any other person connected with the operation of the power system shall comply with the directions issued by the Regional Load Despatch Centers. f) All directions issued by the Regional Load Despatch Centers to any transmission licensee of state transmission lines or any other licensee of the state or generating company (other than those connected to interstate transmission system) or substation in the state shall be issued through the State Load Despatch Centre and the State Load Despatch Centers shall ensure that such directions are duly complied with by the licensee or generating company or sub-station. g) If any dispute arises with reference to the quality of electricity or safe, secure and integrated operation of the regional grid or in relation to any direction given by the Regional Load Despatch Centre, it shall be referred to Central Commission for decision. However, pending the decision of the Central Commission, the directions of the Regional Load Despatch Centre shall be complied with by the State Load Despatch Centre or the licensee or the generating company, as the case may be. The following are contemplated as exclusive functions of RLDCs 1) System operation and control including interstate transfer of power, covering contingency analysis and operational planning on real time basis; 2) Scheduling / re-scheduling of generation; 3) System restoration following grid disturbances; 4) Meter Data Processing; 5) Compiling and furnishing data pertaining to system operation; 6) Operation of regional UI pool account, regional reactive energy account and Congestion Charge Account, provided that such functions will be undertaken by any entity(ies) other than RLDCs if the Commission so directs.

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7) Operation of ancillary services In cases of Short Term Open access bilateral transaction in Inter State Transmission, the Regional Load Despatch Centre of the region where point of drawal of electricity is situated, shall be the nodal agency for the short-term open access. The procedure and modalities in regard to short-term Open Access shall be in accordance with the Central Electricity Regulatory Commission (Open Access in Inter State Transmission)\Regulations, 2008, as amended from time to time.

1.4 Role of SLDC:In accordance with section 32 of Electricity Act, 2003, the State Load Despatch Centre a) The State Load Despatch Centre shall be the apex body to ensure integrated operation of the power system in a State. b) The State Load Despatch Centre shall a. be responsible for optimum scheduling and despatch of electricity within a State, in accordance with the contracts entered into with the licensees or the generating companies operating in that State; b. monitor grid operations; c. keep accounts of the quantity of electricity transmitted through the State grid; d. exercise supervision and control over the intra-State transmission system; and e. be responsible for carrying out real time operations for grid control and despatch of electricity within the State through secure and economic operation of the State grid in accordance with the Grid Standards and the State Grid Code. In accordance with section 33 of the Electricity Act 2003, the State Load Despatch Centre in a State may give such directions and exercise such supervision and control as may be required for ensuring the integrated grid operations and for achieving the maximum economy and efficiency in the operation of power system in that State. Every licensee, generating company, generating station, sub-station and any other person connected with the operation of the power system shall comply with the directions issued by the State Load Depatch Centre under subsection (1) of Section 33 of the Electricity Act,2003. The State Load Despatch Centre shall comply with the directions of the Regional Load Despatch Centre. In case of inter-state bilateral and collective short-term open access transactions having a state utility or an intra-state entity as a buyer or a seller, SLDC shall accord concurrence or no objection or a prior standing clearance, as the case may be, in accordance with the Central Electricity Regulatory Commission (Open Access in Inter-State Transmission) Regulations, 2008, amended from time to time.

1.5 Maintenance of Operating Procedures:These procedures shall be maintained and reviewed periodically. However, in case of urgent need arising due to operating problems, the procedures can be reviewed / revised expeditiously. NLDC will be the coordinating agency for updating/review of Operating Procedures.

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2. Network Security and System Operation 2.1

Introduction: This chapter highlights the actions required to be undertaken by system operators to keep the network secured at all times against contingencies arising in the grid due to outage of critical lines, bus, generating units or other important elements of the grid. It also describes the actions required to maintain system parameters close to nominal values in day-to-day operation.

2.2

Network Security

2.2.1 Background i)

At present, the Indian power system has two asynchronous grids i.e., NEW grid comprising Northern, Eastern, North-Eastern & Western regions and SR (Southern region) grid. The NEW grid and SR Grid together caters about 120 GW of demand with a peak shortage in the range of 6000 to 10000 MW with about 2700 MU energy consumption. The NEW grid has already yielded various benefits by taking advantage of diversity of time, surplus/deficit management due to demand forecast errors/ weather variations, increased economic transactions, improvement in overall system security and efficiency due to increase in stability margin and a stiffness of about 3500 MW/Hz. The stiffness of SR grid is of the order of 2000 MW/Hz.

ii)

However, synchronisation of regional grids has also resulted in evolution of different contingencies of critical nature in the grid, which has a potential to snowball in to credible contingency in the grid In addition, system may operate at times beyond the assumptions of the planner in line with various transmission security standards and associated criteria mentioned in section 3.5 of IEGC due to following reasons: a. Planned maintenance programme of the generators and transmission lines/elements. It is imperative to ensure that such maintenance programmes are properly coordinated and do not result in reduced redundancy not envisaged during planning. b. The events beyond the control of operators such as extreme weather conditions affecting the reliability of transmission system, uneven demand growth or delay in commissioning of generators/transmission elements.

2.2.2 Measures to ensure Network Security and Reliability For safe and secure grid operation, it is imperative that system parameters i.e. frequency, voltage etc., remain close to nominal values. This section highlights the measures to be adopted by the System Operators at NLDC/ RLDCs / State Load Despatch Centres (SLDCs) / Inter State Generating Stations (ISGS) / substations for frequency and voltage control.

2.2.3 Frequency Control 2.2.3.1 Frequency Band:-All the regions would make all possible efforts to ensure the maintenance of grid frequency within the normal IEGC band that is 49.7 Hz to 50.2 Hz currently as per IEGC Clause. 5.2(m) and as specified by the IEGC from time to time. The nominal frequency of operation in Indian grid is 50.0 Hz.

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This would be ensured by implementing following measures:

i) Each RLDC shall regulate the load / generation under its control so that the region may not draw more than its schedule whenever the system frequency is below 49.8 Hz and less than its schedule drawl whenever frequency is above 50.1 Hz and has rising trend. ii) Each regional entity shall maintain generation under its control such that it may not generate more than its schedule whenever the system frequency is above 50.1 Hz and has rising trend and less than its schedule whenever frequency is below 49.8 Hz. iii) In no case, entities in a region would resort to over drawl at a frequency of 49.7 Hz and below. Similarly, entities in the region should not under draw / generate more than schedule at frequency above 50.2 Hz. iv) PRIMARY RESPONSE :- All regional entities shall ensure that the generating units synchronised with the grid provide primary response in line with sections 5.2 (f), 5.2 (g), and 5.2 (h) of IEGC. v) SUPPLEMENTARY CONTROL:- All regional entities shall provide supplementary control in line with regulation 5.2 (i) of IEGC. Whenever frequency falls below 49.8 Hz, all partly loaded generating units, particularly of overdrawing regional entities shall pick up additional generation to control declining system frequency. The Frequency Linked Despatch Guidelines is attached as Annexure I. vi) Sudden reduction in generator output by any entity by more than 100 MW (20 MW in case of North Eastern Region (NER)) shall be avoided particularly when frequency is falling or is below 49.7 Hz unless, under an emergency condition or, to prevent an imminent damage to the equipment. vii) Sudden increase/decrease in load by any regional entity by more than 100 MW shall be avoided to minimize frequency fluctuation. Sudden increase in load by more than 100 MW by any regional entity, particularly when frequency is falling below 49.7 Hz. and reduction in load by such quantum when frequency is rising above 50.2 Hz. shall be avoided. 2.2.3.2. NLDC shall exchange the power between the NEW and SR grid to minimise the frequency differential between the grids in consultation with the concerned Regional Load Despatch Centre (RLDC) on opportunity basis in real-time in addition to the Inter-regional scheduled power. 2.2.3.3 Measures during high frequency conditions Based on the scheduled load shedding programme, hydro pick up, change in STOA schedules and load ramp ups, NLDC shall anticipate possible frequency rises at the beginning of each hour and initiate advance actions. When the system frequency is above 50.1 Hz and in the rising trend:i) NLDC will co-ordinate with WR, ER to export the power to SR region in case the NEW grid frequency is above 50.1 Hz and margin is available in the inter regional links and associated lines of the regions & vice versa in case the SR grid frequency is above 50.1Hz. ii) NLDC will coordinate with all the regions to maximize the load in case of under drawl and minimise the generation based on merit order after ensuring that all pumped storage schemes are in operation in pumping mode. NLDC -

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iii) Advise all RLDCs to endeavour to restrict their actual net injection to within their scheduled dispatch. All regions shall follow frequency linked dispatch guidelines. iv) All the regions shall endeavour to ensure that their drawl from the grid is not less than their schedule by following actions:a. Instruct SLDCs to Phase out scheduled load shedding b. Advise constituents to surrender relatively high cost entitled power from ISGS through revision of schedules. c. Follow merit order and conserve fuel by reducing or shutting down high cost generators including IPPs. d. Explore additional export through Short-term Open Access (STOA). v) All regions shall stagger their rostering pattern in a manner so as to arrest stiff high frequency excursions during load changeover period. vi) In case of persistent (based on merit order) high frequency, all regions may resort to shutting down/ backing down of generators in the event of threat to grid security as per directions of NLDC.

2.2.3.4 Measures during low frequency conditions All regions shall carry out day ahead operational planning by balancing availability from all sources and expected demand. When the system frequency is below 49.8 Hz and in the decaying trend: i) All regions shall endeavour to ensure the actual net injection of ISGS generation as per their scheduled dispatch. ii) All the regions shall ensure that their drawl from the grid is not more than their schedule by maximizing generation in line with frequency linked dispatch guidelines. iii) NLDC would advise RLDC’s for further instructing to SLDC to restrict the over drawl at 49.8 Hz, within its schedule as per the Clause 5.4.2(a) IEGC-2010. iv) If frequency further deteriorates and goes below 49.7 Hz and the over drawl of the region continues then NLDC shall advise the RLDCs to make arrangements that will enable manual demand disconnection to take place as instructed by RLDC/ SLDCs. v) The measures undertaken to reduce the drawl from the grid shall not be withdrawn as long as the frequency / voltage remain at a low level unless specifically permitted by NLDC/RLDC. vi) In case of certain contingencies and / or threat to system security, NLDC may direct RLDCs to ensure reduction of drawl by particular regional entity by a certain quantum. Such directions shall immediately be acted upon. vii) NLDC will co-ordinate with WR, ER to import the power from SR region in case the NEW grid frequency is below 49.8 Hz and margin is available in the inter regional links and associated lines of the regions & vice versa in case the SR grid frequency is below 49.8Hz.

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2.2.3.5 Governor Operation

a)

In accordance to the Clause 5.2(f), 5.2(g), 5.2(h), 5.2(i) of IEGC, all thermal generating units of 200 MW and above and all hydro units of 10 MW and above (except those with upto three hours pondage), which are synchronized with the grid, irrespective of their ownership, shall have restricted governor mode of operation (RGMO) with effect from 01.08.2010.

b) The restricted governor mode of operation shall essentially have the following features. i

There should not be any reduction in generation in case of improvement in grid frequency below 50.2 Hz. ( for example if grid frequency changes from 49.3 to 49.4 Hz. then there shall not be any reduction in generation). Whereas for any fall in grid frequency, generation from the unit should increase by 5% limited to 105 % of the Maximum Continuous Rating (MCR) of the unit subject to machine capability.

ii Ripple filter of +/- 0.03 Hz. shall be provided so that small changes in frequency are ignored for load correction, in order to prevent governor hunting. iii If any of these generating units is required to be operated without its governor in operation as specified above, the RLDC shall be immediately advised about the reason and duration of such operation. All governors shall have a droop setting of between 3% and 6%. iv Provided that if a generating unit cannot be operated under restricted governor mode operation, then it shall be operated in free governor mode operation with manual intervention to operate in the manner required under restricted governor mode operation. v All thermal generating units of 200 MW and above and all hydro units of 10 MW and above operating at or up to 100% of their Maximum Continuous Rating (MCR) shall normally be capable of (and shall not in any way be prevented from) instantaneously picking up to 105% and 110% of their MCR, respectively, when frequency falls suddenly. After an increase in generation as above, a generating unit may ramp back to the original level at a rate of about one percent (1%) per minute, in case continued operation at the increased level is not sustainable. Any generating unit not complying with the above requirements, shall be kept in operation (synchronized with the Regional grid) only after obtaining the permission of RLDC. vi The recommended rate for changing the governor setting, i.e., supplementary control for increasing or decreasing the output (generation level) for all generating units, irrespective of their type and size, would be one (1.0) per cent per minute or as per manufacturer’s limits. However, if frequency falls below 49.7Hz, all partly loaded generating units shall pick up additional load at a faster rate, according to their capability. c)

If any of the generating units are required to be operated without its governor in operation as specified above, the RLDC shall be immediately advised about the reason and duration of such operation.

d)

Procedure to monitor primary response through Frequency Response Characteristic (FRC) from different control areas was submitted by NLDC and it is approved by the Hon’ble CERC through its order dt.03-05-2013. The detailed procedure is attached as Annexure II

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2.2.4 Voltage Control 2.2.4.1 Operating Range As defined in the IEGC Section 5.2(s), the operating range of the voltages at various voltage levels of the grid is as follows: Voltage (kV-rms) Nominal 765 400 220 132 110 66 33

Minimum 728 380 198 122 99 60 30

Maximum 800 420 245 145 121 72 36

The maximum and minimum values in the above table are the outer limits and all the regions shall endeavour to maintain the voltage level within the above limits. NLDC operators should monitor the above voltage limits across all inter regional links& important nodes and should interact with RLDCs for keeping the system voltage within the above specified limit. As defined in the IEGC Section 5.2(J), all users and SEBs shall ensure that temporary over voltage due to sudden load rejection and the maximum permissible values of voltage unbalance shallremain within limits specified under Central Electricity Authority (Grid Standards) Regulations, 2010. Reactive Power manual of NLDC may be referred for detailed Reactive power management and voltage control procedures. 2.2.4.2 AVRs of Generators Generating units of all the region shall keep their Automatic Voltage Regulators (AVRs) in operation and power system stabilizers (PSS) in AVRs shall be tuned in line with clause 5.2(k) of IEGC.

2.2.4.3 VAR Exchange by regional constituents for Voltage and Reactive Control Each constituent shall provide for the supply of its reactive requirements including appropriate reactive reserves, and its share of the reactive requirements to support safe and secure power transfer on interconnecting transmission circuits. The RLDC and constituent states shall take action in regard to VAR exchange with the grid looking at the topology and voltage profile of the exchange point. In general, the beneficiaries shall endeavour to minimize the VAR drawl at interchange point when the voltage at that point is below the nominal value and shall not inject VARs when the voltage is above the nominal value. In fact, the beneficiaries are expected to provide local VAR compensation so that they do not draw any VARs from the grid during low voltage conditions and do not inject any VARs to the grid during high voltage conditions.

2.2.4.4 VAR generation / absorption by generating units In order to improve the overall voltage profile, the generators shall run in a manner so as to have counter balancing action corresponding to low/high backbone grid voltage and to bring it towards the NLDC -

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nominal value. In order to achieve the same, all generators shall generate reactive power during low voltage conditions and absorb reactive power during high voltage conditions as per the capability limit of the respecting generating units. The online tap changers (OLTC) on the generator transformer wherever possible should also be used to achieve this. Off load tap changes should be used to take care of the seasonal variations in the voltage profile.

2.2.4.5 Transformer Taps In line with IEGC clause 6.6.5 & 6.6.4, the transformer tap positions on different 765kV, 400kV, 220kV & 132kV class ICTs shall be changed as per requirements in order to improve the grid voltage. RLDCs shall coordinate and advise the settings of different tap position and any change in their positions shall be carried out after consultation with RLDC. The modified tap position shall be informed to NLDC by RLDCs. The tap settings shall be reviewed and changed before the start of monsoon and winter and based on system requirement. NLDC shall review and advise RLDCs on the tap position of 765/400kV ICTs periodically.

Fig:- Typical Transformer

2.2.4.6 Control of Voltage at grid substations/generating stations Following corrective measures shall be taken in the event of voltage going high / low:i) In the event of high voltage (when the bus voltage going above 410 kV), following specific steps would be taken by the respective grid substation/generating station at their own, unless specifically mentioned by NLDC/RLDC/SLDCs. a. The bus reactor be switched in b. The manually switchable capacitor banks be taken out c. The switchable line/tertiary reactor are taken in d. Optimize the filter banks at HVDC terminal e. All the generating units on bar shall absorb reactive power within the capability curve f. Operate synchronous condensers wherever available for VAR absorption g. Operate hydro generator / gas turbine as synchronous condenser for VAR absorption wherever such facilities are available h. Bring down power flow on HVDC terminals so that loading on parallel EHV network goes up resulting in drop in voltage. i. Open lightly loaded lines in consultation with RLDC/SLDC for ensuring security of the balanced network.

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ii) In the event of low voltage (when the bus voltage going down below 390kV), following specific steps would be taken by the respective grid substation/generating station at their own, unless specifically mentioned by NLDC/RLDC/SLDCs. a.Close the lines which were opened to control high voltage in consultation with RLDC/SLDC. b. The bus reactor be switched out c. The manually switchable capacitor banks are switched in. d. The switchable line/tertiary reactor are taken out e. Optimize the filter banks at HVDC terminal f. All the generating units on bar shall generate reactive power within capability curve. g. Operate synchronous condenser for VAR generation h. Operate hydro generator / gas turbine as synchronous condenser for VAR generation wherever such facilities are available i. Increase power flow on HVDC terminals so that loading on parallel Extra High Voltage (EHV) network goes down resulting in rise in voltage. 2.2.4.7 Load Management for controlling the Voltage All the regions shall identify the radial feeders in their areas in consultation with SLDCs which have significant reactive drawls and which can be disconnected in order to improve the voltage conditions in the event of voltage dropping to low levels. The details of all such feeders shall be kept ready in the respective control rooms of RLDC/SLDC and standing instruction would be given to the operating personnel to ensure the relief in the hour of crisis by disconnecting such feeders. Automatic under voltage load shedding shall commence at 380kV.

Switching off the line reactors in case of low voltage

2.2.4.8

In the event of persistent low voltage conditions, some of the line reactors are to be selected on the basis of line length, grid conditions, network topology etc. by each region which can be switched off in order to improve the system voltage profile. The switching off of such line reactors and reviving them back would be carried out as per the instructions issued by RLDCs/SLDCs. 2.2.4.9 Switching off of the lines in case of high voltage In the event of persistent high voltage conditions when all other reactive control measures as mentioned earlier including opening of redundant HT lines with in the state system by the concerned SLDCs have been exhausted, selected 765 / 400 / 230 / 220 / 132 / 110 KV lines shall be opened for voltage control measures. The opening of lines and reviving them back in such an event would be carried out as per the instructions issued by RLDC/NLDC in real time and as per the standing instructions issued from time to time. While taking such action, RLDC/NLDC would duly consider that to the extent possible the same does not result in affecting ISGS generation as well as the system security & reliability is not affected.

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2.2.5

Line loading In addition to frequency & voltage control measures outlined above, each system operator would also have before him the thermal loading limits, surge impedance loading and the loading permitted from stability considerations for each line listed under important elements. RLDC would endeavour to keep the line/ ICT loadings within limits and inform NLDC in case of overloading of any element. Special emphasis would be paid by each system operator in identifying credible system contingencies & continuously evaluating the system under his control against these contingencies. In addition to monitoring the loading of critical individual elements, the power flow across the identified flow gates shall also to be monitored and controlled with in the value specified based on the study results. All the regions hence would extend the necessary cooperation in maintaining network reliability and security. Surge Impedance Loading of the transmission lines is given in Annexure III. Thermal Loading limits of different conductors is given in Manual on Transmission Planning Criteria- Jan 2013’. It is attached as Annexure IV. The advisory issued by NLDC for secure operation of the grid consequent to commissioning of the high capacity 765 kV corridors in the NEW grid is enclosed as Annexure V

2.2.6

System Protection Scheme As per IEGC, System Protection schemes are required to take care of some special contingencies like tripping of important corridor/flow gates etc to avoid the voltage collapse, cascade tripping, load generation mismatch and finally blackouts in the system. It will have pre identified load shedding, generation backing down/tripping of generators and inter tripping features. To ensure the healthiness of SPS, necessary checking / testing will be done by RPC secretariat periodically. Several SPS schemes have been implemented in different regions and several schemes are being planned. It is explained in Chapter on Defense Mechanisms.

2.2.7 Islanding Scheme In order to isolate the healthy subsystems following a large-scale disturbance, islanding schemes have been implemented by few generating stations/Users and State Utilities. This is a system requirement under contingency conditions according to which the power network may be split into healthy and self-sustaining zones so that cascade tripping of all generating stations in the entire region is avoided. It is explained in Chapter on Defense Mechanisms. .

2.2.8 Security of Grid In line with Central Electricity Authority (Technical Standards for Connectivity to Grid) Regulations 2007, the utilities shall make arrangements for integration of the controls and telemetering features of their system in to the automatic generation control, automatic load shedding, system protection scheme, energy management system and supervisory control & data Acquisition System of the respective State or the region.

2.2.9 Congestion Management in real time operation Congestion management in real time operation is tackled as per CERC Regulation dated 22nd December 2009 on “Measures to relieve congestion in real time operation”. The revised NLDC

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procedure (Detailed Procedure for Relieving Congestion in Real Time Operation) has been prepared by NLDC and approved by CERC vide its order dated 22.04.2013 may be referred for further details. 2.2.9.1 Transfer Capability i)

Total Transfer Capability (TTC) means the amount of electric power that can be transferred reliably over the inter-control area transmission system under a given set of operating conditions considering the effect of occurrence of the worst credible contingency.

ii)

Transmission Reliability Margin (TRM) means the amount of margin kept in the total transfer capability necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions.

iii)

Available Transfer Capability (ATC) means the transfer capability of the inter-control area transmission system available for scheduling commercial transaction (through long term access, medium term open access and short term open access) in a specific direction, taking into account the network security. Mathematically ATC is the Total Transfer Capability less Transmission Reliability Margin The updated ATC, TRM & ATC of all inter regional corridors and Intra Regional corridors shall be available to NLDC operator for facilitating optimum utilization. Sample format for declaration of TTC/TRM/ATC is enclosed as Format-I is given in Annexure VI .

2.2.9.2 Declaration of congestion in real-time a) SLDCs/ RLDCs/ NLDC shall have a display available in their web-sites showing TTC, TRM, ATC declared in advance. Real time power flow in the corridor for which TTC has been declared shall be displayed alongside for comparison. The voltage of the important nodes in the grid downstream/ upstream of the corridor shall also be displayed. The display is available in the NLDC SCADA system. The same is attached as Format II in Annexure VI

A corridor shall be considered congested under the following circumstances: i) Grid voltage in the important nodes downstream/ upstream of the corridor is beyond the operating range specified in the IEGC and/or ii) The real time power flow along a corridor is such that n-1 criteria may not be satisfied. iii) One or more transmission lines in the corridor are loaded beyond the normal limit specified in CEA Manual on Transmission Planning Criteria. Whenever actual flow on inter/ intra regional link/ corridor exceeds ATC and security criteria as mentioned above are violated NLDC, RLDC may issue a warning notice. In case SLDC observes congestion within the intra State grid it shall inform the respective RLDC which in turn shall inform the NLDC. The notice for congestion shall be communicated to all the Regional entities telephonically or through fax/ voice message/ e-mail and through postings on website and making the same available on the common screen at NLDC/ RLDCs/ SLDCs. The format III of the notice is enclosed in Annexure VI b) If the power flow on the corridor is as per the schedule, but the congestion has been caused by forced outages of a transmission line in the corridor, which occurs after the drawal schedule has NLDC

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been fixed, then open access transactions shall be curtailed in the priority given in the Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-State Transmission and related matters) Regulations, 2009(as indicated below) followed by revision of TTC, TRM and ATC. c) If the power flow on the corridor is as per the schedule and the corridor is congested due to either of the circumstances mentioned in clauses 2.2.9.2 (a) i & iii, then TTC, TRM and ATC shall be revised accordingly. d) If violation of TTC limits persists for 2 time-blocks not counting the time-block in which warning notice was issued by RLDC and no affirmative action by the defaulting agency is taken, NLDC/ RLDC(s) shall issue a notice for application of congestion charge. This notice shall be communicated to all the concerned Regional entities telephonically or through fax message and through postings on website and making available the same at the common screen at NLDC/ RLDCs/ SLDCs. The format IV is enclosed as Annexure VI 2.2.9.3 Applicability of Congestion Charge a) Congestion Charge shall be applicable to Regional entities as per the CERC (Measures to relieve congestion in real time operation) Regulations and orders on rate of congestion charge as applicable from time to time.

b) At Congestion charge would be levied for a) over drawal or under-injection in the importing control area and b) under drawal or over-injection in the exporting control area. c) Congestion charges may also become applicable for an intra-regional corridor of one region, if the congestion is attributable to other regional entities of other region. Congestion charge shall be applicable only after two time blocks from the time of issuing the notice, not counting the time block in which notice is issued. c) Congestion charge shall be withdrawn after the power flow on the affected transmission link/ corridor has come down to the ATC and remains at this level for one time block. NLDC/ RLDC shall communicate to all concerned Regional entities telephonically or through fax message/ email and through postings on website and making available the same on the common screen available at NLDC/ RLDCs/ SLDCs for lifting of congestion charge. The format V of the notice is enclosed as Annexure VI. The various formats may be referred in the “Detailed procedure for relieving congestion in real time operation” also. e) As per CERC notification, the congestion charge is currently at Rs.5.45 per kwh which will be applicable to all regions. The Commission may, from time to time, by order specify the rate of congestion charge applicable to whole or a part of the region.

2.2.10 Inter-regional Exchanges NLDC shall endeavour to exchange power between the regions on opportunity basis in real-time in addition to the Inter-regional scheduled power. NLDC shall exchange power with the neighboring region on Unscheduled Interchange (UI) basis for the following. i) In case of Grid disturbance / Grid Incidents ii) Network contingent conditions in either of NEW and SR regions iii) Wheeling of other regions power during contingencies

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iv) Testing / maintenance of important elements v)

Providing power assistance during emergency

vi) Load changeover period in either of NEW grid and SR regions

2.2.11 Contingency Evaluation In addition to frequency and voltage control measures outlined above, each system operator at NLDC/RLDCs/ SLDCs would continuously run the Real Time Contingency Analysis (RTCA) application to identify credible contingencies, evaluate the system under his control against these contingencies and ensure immediate remedial measures for revival. All the constituents of each region should implement network applications under EMS at the earliest to facilitate the contingency evaluation. Pre-requisite for this is however the updation of network of models alongwith availability of real-time data from all the sub-stations / generating stations. Intense efforts are required from all SLDCs/RLDCs/NLDC in this direction.

2.2.12 Requirements for Solar & Wind generator System operator(RLDC/SLDC) shall make all efforts to evacuate the available power from solar and wind and treat as a must run station. SLDC/RLDC may direct solar/wind generator to back down its generation for system security purpose or safety of personnel/equipments. SLDC/RLDC may direct a wind farm to curtail its VAr drawal/Injection on consideration of system security or safety of personnel/equipments.

2.2.13 HVDC SET points NLDC shall inform to all RLDCs the optimum setting of the HVDC set points of all interregional HVDC system. Ramping up/down of all intra-regional Bipole and Back-Back HVDC has to be done with prior intimation of NLDC/RLDCs. .

2.2.14 Operating Manpower The Control Rooms of NLDC, RLDCs, SLDCs, Power plants, Grid Substations shall be manned / monitored round the clock by qualified and adequately trained manpower who would remain vigilant and cooperative at all the times so as to maintain safe and secure grid operation.

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3. Demand Monitoring & Control Procedures 3.1 Objective This chapter describes the procedures / responsibilities of the SLDCs for all India demand monitoring and also the steps to be taken by SLDCs for reduction of demand in the event of inadequate generating capacity and in the event of breakdown or operating problems (such as frequency, voltage levels or network elements overloading) on any part of the grid.

3.2 Overview Demand monitoring plays a very important role in grid operation. Long term demand data (five years and beyond) is an important input for generation / transmission planning. Medium term demand data (one year and below) constitutes an important input for outage planning of generating units and transmission lines. The short term demand forecast (spanning from one week to next time block) facilitates an important input for generation scheduling. Variation in demand in real time operation from the estimated values should be within +-2% limits to ensure that the grid is not affected adversely. Demand estimation and control is essentially the responsibility of SLDCs and RLDC/NLDC would generally not have a major role in this area except for integrating the demand value from the regions and projecting the same as national demand. NLDC however, would give instructions to RLDCs on demand control whenever the same has a bearing on the security of the national grid and such instructions would have to be complied by the SLDC’s through their respective RLDCs.

3.3 Demand estimation 3.3.1 The SLDCs would forecast demand on an annual, quarterly, monthly, weekly and ultimately on daily basis which would be used in the day ahead scheduling. 3.3.2 In line with the clause 5.3(c & d) of IEGC-2010, each SLDC shall maintain a historical database and develop methodologies / mechanism for demand estimation. The data for the estimation shall also include load shedding, power cuts etc. Similar database should be available at RLDCs and NLDC level. 3.3.3 Each State / SLDCs shall utilize the forecasting modules suitable for their system and compatible for transfer of forecasted data in the form required by RLDCs. 3.3.4 The historical database to be maintained by SLDCs/RLDCs shall also include major events visà-vis effect of weather forecast on the actual demand, grid disturbances and loss of major generation. Effect of weekends and other basis of historical data. 3.3.5 The annual, quarterly and monthly demand forecast would be finalized in the respective subcommittee meetings of RPCs and used in the outage plan prepared by respective RPC Secretariats in consultation with all the constituents. 3.3.6 Attention would also be paid by SLDCs in demand forecasting for special days such as important festival and national holidays having different crest and troughs in the daily load curve as compared to normal days.

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3.3.7 The load forecast utility based on Similar Day Forecast (SDF) technique is available at all the SLDCs and RLDC as a part of the EMS function. SDF can take two approaches for demand forecast i.e., Profile Based Forecast (PBF) and Weather Based Forecast (WBF). 3.3.8 In the PBF technique, historical demand profile contains hourly demand data for 96 profiles consisting of recent past seven days of every calendar month and 12 special days (holidays like 15th August, 26th January etc.). In the WBF technique, a composite weather parameter representing temperature, atmospheric pressure, wind speed, wind direction, rainfall and relative humidity and corresponding demand data are stored on hourly basis in history as profile.

3.3.9 Presently, the SDF technique based on PBF is in vogue in all the region which calls for each SLDC to upload the demand forecast data for the next day by 15 hours on daily basis. It also facilitates SLDCs to incorporate changes on online basis and upload. 3.3.10 The SLDC shall take into account the wind and other renewable energy forecasting to meet active and reactive power requirement. 3.3.11It is also important that, the reactive power / Mvar requirements are forecasted right from substation level by each SLDC. The reactive power planning exercise and program for installation of reactive compensation equipments should take care of these requirements also.

3.4 Demand Control 3.4.1 The need for demand control arises on account of following conditions:

a) Variation in demand from the estimated value (by more than 2%) which can not be absorbed by the grid. b) Unforeseen generation / transmission outages resulting in reduced power availability. c) Heavy reactive power demand, particularly during Rabi crop season (agricultural load) / high industrial activity causing low voltages d) Critical loading on inter-regional corridors/flow gates e) Sudden variations in Wind power generation f) Commercial reasons such as payment default leading to regulation of power supply by generating companies 3.4.2 In line with section 5.3.(c) of IEGC, the SLDCs would regularly carry out the necessary exercises to estimate short term and long term demand to facilitate planning so as to ensure that they meet their load without overdrawing from the grid. The deviations of drawl from the schedule have to be controlled by the SLDCs in the following cases: a) Overdrawl at frequency below 49.7 Hz b) Underdrawal at frequency above 50.2 Hz c) Over/under drawl in line with real time advice from NLDC/RLDCs during critical contingencies in inter-regional corridors / flow gates d) Reactive power drawls / injections causing low voltage / high voltage. 3.4.3 The constituents shall endeavour to restrict their net drawl from the grid to within their respective drawl schedule whenever the system frequency is below 49.8 Hz in line with section 5.4.2(a) of NLDC

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IEGC. However, when the frequency falls below 49.8 Hz, requisite load shedding (manual) shall be carried out in the concerned State to curtail the over drawl in order to avert the drop in frequency below 49.7 Hz. 3.4.4. All regions shall endeavour to maintain the system frequency above 49.7 Hz and would cooperate for helping optimum utilization of regional hydro resources so as to ensure maximum availability during peak hours. 3.4.5. All regions shall ensure the availability of the defence mechanism in place . 3.4.6. Demand control would have to be exercised under low frequency conditions by taking the following actions by regions. a) Scheduled load shedding as decided in OCCM/Board meetings. b) Un-scheduled load shedding for the load generation balancing exercise which is planned for the following day. Unscheduled load shedding accounts for fluctuations in availability due to forced outages, transmission outages, fuel related problems, demand fluctuations due to weather related factors and other important events c) Distress load shedding due to load generation imbalance in real time leading to frequency going below 49.7 Hz. This will be carried out through already identified radial feeders. Loads may be shed under any System Protection Schemes, UFR and df/dt relays. 3.4.7. During the demand control by scheduled load shedding as well as unscheduled load shedding by staggering in different groups, the changeover from one group to another shall be carried out in a gradual & scientific manner so as to ensure that the change in load at any point of time does not exceed 100 MW so as to avoid excursions in system parameters. 3.4.8 In the case of low voltage pockets, RLDC/SLDCs would disconnect the preidentified radial feeders drawing heavy quantum of reactive power which are not feeding the important loads like Traction, Hospital, Defence etc. when voltage goes below 380kV. 3.4.9 Each User/STU/SLDC shall formulate contingency procedures and make arrangements that will enable demand disconnection to take place, as instructed by the RLDC/SLDC, under normal and/or contingent conditions. These contingency procedures and arrangements shall regularly be / updated by User/STU and monitored by RLDC/SLDC. RLDC/SLDC may direct any User/STU to modify the above procedures/arrangement, if required, in the interest of grid security and the concerned User/STU shall abide by these directions. 3.4.10 The SLDC through respective State Electricity Boards/Distribution Licensees shall also formulate and implement state-of-the-art demand management schemes for automatic demand management like rotational load shedding, demand response (which may include lower tariff for interruptible loads) etc. before 01.01.2011, to reduce overdrawl in order to comply para 5.4.2 (a) and (b) . A Report detailing the scheme and periodic reports on progress of implementation of the schemes shall be sent to the Central Commission by the concerned SLDC. 3.4.11 In order to maintain the frequency within the stipulated band and maintaining the network security, the interruptible loads shall be arranged in four groups of loads, for scheduled power cuts/load shedding, loads for unscheduled load shedding, loads to be shed through under frequency relays/ df/dt relays and loads to be shed under any System Protection Scheme identified at the RPC level. These loads shall be grouped in such a manner , that there is no overlapping between different Groups of loads. In case of certain contingencies and/or threat to system security, the RLDC may direct any SLDC/ SEB/distribution licensee or bulk consumer connected to the ISTS to decrease drawal of its control area by a certain quantum. Such NLDC

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directions shall immediately be acted upon, SLDC shall send compliance report immediately after compliance of these directions to RLDC.

3.5

Operational planning on day ahead basis

3.5.1 In line with clause 6.5 of IEGC under the head of ‘Scheduling & Despatch Procedure’,plantwise requisitions from the States are compiled a t e a c h R L D C s to draw up scheduled for each ISGS. The day ahead operational planning exercise helps the state with large deficit to opt for un-requisitioned power in some of the ISGS plants within or outside the region. 3.5.2 The state utilities bridge the anticipated shortfall by day-ahead Short Term Open Access transactions/collective transactions (PX trades). 3.6

Day Ahead Balancing

3.6.1 The day ahead power balance cann ot be obtained without planning for load shedding in case of deficient power region. Out of the total deficits for the following day, the scheduled load shedding takes care of a major portion of the deficits and is planned and frozen atleast a month in advance and announced to public. The balance part of the deficit is taken care of through planning of unscheduled load shedding. 3.6.2 Unscheduled load shedding accounts for fluctuations in a v a i l a b i l i t y due to forced outages, transmission outages, fuel related problems, demand fluctuations due to weather related factors and other important events 3.7

Same Day Operational Planning

3.7.1 On the day of operation, due to errors in demand forecast, forced outage of units, some of the States or Central Sector Plants, sellers/buyers of Short Term Open Access transactions (advance reservations and first-cum-first serve basis only) may revise their schedules – one and half hour ahead for planned deviations and one hour ahead for unforeseen problems. 3.7.2 The deviations from schedules in any region may require purchase/sell of balancing power from the other power surplus regional to power deficit regional pool at a rate determined by UI price vector. This price vector is given in Annexure VII.

3.8

Load Crash In the event of load crash in the system due to weather disturbance or other reasons, the situation would be controlled by SLDCs / ISGS by the following methods:a) Lifting the load restrictions, if any. b) Exporting the power to neighbouring regions by STOA c) Phasing out hydro d) Backing down or closing down of generating units Further in case of hydro generation linked with irrigation requirements, the actual backing down or closing down of units shall be subject to limitations on such account.

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4. Outage Planning 4.1

Introduction

a)

This section brings out the process for preparation of outage schedules for generators and transmission lines at the national level subject to network security, constraints and reliability. The general guidelines shall be as per section 5.7 of the IEGC. NLDC operator should be familiar with all important transmission lines given in Annexure VIII and generation units covering the entire national grid and effecting the operation of the national grid concerning its security, integrity and economy facilitating optimum utilization of all national resources. While planning for generation outages and transmission line outages due consideration shall have to be made for long term commitments, medium and short term commitments including transactions that are settled through multiple Power Exchanges.

b)

Outages effecting network security on a Pan-India scale shall have to be planned meticulously and Power System Studies have to be carried out for this purpose.

c)

Annual outage plan shall be prepared in advance for the financial year by the RPC Secretariat in consultation with NLDC and RLDC and reviewed during the year on quarterly and Monthly basis. All users, CTU, STU etc shall follow these annual outage plans. If any deviation is required the same shall be with prior permission of concerned RPC and RLDC. The outage planning of run-ofthe-river hydro plant, wind and solar power plant and its associated evacuation network shall be planned to extract maximum power from these renewable sources of energy. Outage of wind generator should be planned during lean wind season, outage of solar, if required during the rainy season and outage of run-of-the river hydro power plant in the lean water season.

4. 2

Objective

a)

To produce a coordinated generation and transmission outage programme for the National/Regional grid, considering all the available resources and taking into account transmission constraints, as well as, irrigational requirements.

b)

To minimise surplus or deficits, if any, in the system requirement of power and energy and help operate system within Security Standards.

c)

To optimize the transmission outages of the elements of the National/Regional grid without adversely affecting the grid operation but taking into account the Generation Outage Schedule, outages of User/STU/CTU systems and maintaining system security standards.

4.3

Scope This section is applicable to NLDC, RLDC, SLDCs, CTU, STU, RPCs and all Users

4.4

Outage Planning Process

a)

The RPC Secretariat shall be primarily responsible for finalization of the annual outage plan for the following financial year by 31st January of each year.

b)

All SEBs/STUs, transmission licensees, CTU, ISGS IPPs, MPPs and other generating stations shall provide RPC Secretariat their proposed outage programmes in writing for the next financial year by 30th November of each year. These shall contain identification of each generating unit/line/ICT, the preferred date for each outage and its duration and where there is flexibility, the earliest start date and latest finishing date.

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c)

RPC Secretariat shall then come out with a draft outage programme for the next financial year by 31st December of each year for the Regional grid taking into account the available resources in an optimal manner and to maintain security standards. This will be done after carrying out necessary system studies and, if necessary, the outage programmes shall be rescheduled. Adequate balance between generation and load requirement shall be ensured while finalising outage programmes. The same shall be uploaded by the RPCs on their website.

d)

The outage plan shall be finalized in consultation with NLDC, RLDCs and SLDCs. The final outage plan shall be intimated to NLDC, Users, STUs, CTU, other generating stations connected to ISTS and the RLDC for implementation by 31st January of each year.

e)

The above annual outage plan shall be reviewed by RPC Secretariat on quarterly (March, June, September & December) and monthly basis in coordination with all parties concerned, and adjustments made wherever found to be necessary. Monthly review of the outage plan for the current month and consecutive month would be done in the Operation Coordination Committee (OCC) of RPC meeting and RPC would issue the revised outage plan to all constituents and RLDC/NLDC/SLDC.

f)

In case of emergency in the system, viz., loss of generation, break down of transmission line affecting the system, grid disturbances, system isolation, RLDC may conduct studies again before clearance of the planned outage.

g)

The NLDC/RLDC shall be authorized to defer/ cancel any planned outage involving lines/elements in case of any of the following taking into account statutory requirements: i. ii. iii. iv.

Grid disturbances System isolation Partial Black out in a state Any other event in the system that may have an adverse impact on the system security by the proposed outage.

h)

The detailed generation and transmission outage programmes shall be based on the latest annual outage plan (with all adjustments made to date).

i)

Each User, CTU and STU shall obtain the final approval from RLDC/NLDC prior to availing an outage.

j)

RPCs shall submit quarterly, half-yearly reports to the Commission indicating deviation in outages from the plan along with reasons. These reports shall also be put up on the RPC website.

k)

A Draft procedure for coordinated transmission element outage planning is proposed by NLDC to all RPCs through letter dt. 28th February 2013. Subsequently, a letter dt 05-07-2013 also sent to RPCs. It is given in Annexure IX. And after getting approval from all the RPCs, it should be implemented. The draft procedure aims to streamline the process of outage coordination between SLDCs, RLDCs, NLDC, RPCs and Indenting Agencies.

4.5 a)

NLDC

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b)

In case of any outage affecting more than one constituent in one or more than one region, the information about the approval / deferment shall be communicated by RLDC to all such affected constituents in consultation with NLDC.

c)

Before availing any planned or unforeseen outage of any important elements as per Annexure VIII the indenting utility shall request for a code on real-time from NLDC through respective RLDC under whose supervisory area the utility remains. NLDC shall issue a common code to concerned RLDC’s involving regional grids on either end of the line. Respective RLDC’s may convey their final code to NLDC as well as their respective utilities involved on either ends of the transmission line/equipment. All preparatory works for availing outage must be done in advance before actually availing code. In the same manner code must be obtained in real-time from NLDC by concerned utility through it’s RLDC before restoration/revival of the line/element. Respective RLDC’s shall convey their final code to NLDC for confirmatory exchange with other RLDC’s involved. RLDC would ensure that the outage availed should come into service as per the scheduled time. Delays with reasons thereof if any should be immediately reported to NLDC in advance. During shutdown RLDC may concur for extension of such shutdown after reviewing the grid conditions and status of shutdown.

d)

The code issued by NLDC / RLDC’s for opening / restoration of line / element is consent from operational point of view notwithstanding anything contained in respect of safety measures and switching operations that may be carried out locally. All safety measures related to sub-station and/or transmission lines shall be the responsibility of the personnel authorized to execute the work.

e)

During the approved shutdown of line/ICT, any other opportunity based maintenance work by the concerned agencies to be carried out only after getting the consent of RLDC/NLDC.

4.6

Outage Planning Procedures for NLDC Important elements

i)

In order to maintain the security of the Integrated power system, it is important that the planned outage of generation and transmission system particularly in the important flow-gates, Important grid elements and inter regional transmission links are properly coordinated.

ii)

Reliable operation of the All India grid is important from the view point of Quality Of Service (QoS) to the customers and other stakeholders. Proper co-ordination of transmission outages in the system is one of the key aspects to ensuring reliability. Outages in the transmission network could either be on account of planned maintenance activities or construction related activities or any emergency conditions arising in the field. Since these may have an impact across two or more regions and hence needs to be planned by the concerned regions in consultation with NLDC. Proper coordination of the same is important mainly due to the following factors:

a. Reliability of operation of the All India grid b. Certainty to the electricity markets. c. Proper crew resource mobilization at the work sites to ensure that outage time is minimized. iii)

In order to ensure the same, the following procedures may kindly be followed by all RLDCs/NLDC.

1) Following outages might be approved only after concurrence of NLDC. This is enclosed as Annexure VIII

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   

All inter-regional links irrespective of voltage level. HVDC systems and all lines operating at 765kV, & 765kV ICTS, Reactors. All outages necessitating change in TTC and/or curtailment of transactions. Trans National Links

2) At the RPC level, outages are finalized in the Operation Coordination sub Committee (OCC). A list of the shutdowns approved by OCC may be forwarded by each RLDC to the Reliability Coordinators of each RLDC and NLDC by email immediately after OCC approval. 3) On a daily basis (say day D), by 1030 hours each RLDC would forward a list of outages planned for their respective regions for the D + 3rd day by email to the Reliability Coordinators of each RLDC/NLDC along with the study results. 4) The NLDC Reliability Coordinators would further assess the impact of these outages on the overall reliability of the all India grid and concurrence of outages under categories listed at (1) above would be conveyed by NLDC within a day. 5) All planned shutdowns on the next day would be reviewed a day in advance of the shutdown. RLDCs would try to ensure that no new element gets added to the list provided three days in advance at Sl. no. 3 above as far as possible, unless the outage is of an emergency nature. 6) A list of all the outages approved for the next day would be readily available at each RLDC/NLDC control room along with simulation results, if any and the precautions required to be taken. 7) In real time if any emergency requirement of outage occurs in real time, RLDCs would inform NLDC and actions taken accordingly in real time. RLDCs/NLDC might devise separate internal procedures for fast co-ordination between their respective Control Rooms and Reliability Coordinators in real time. 8) Any deviation in the outage from the schedule can affect other planned outages as well as affect reliability and also the electricity markets. RLDCs may impress on the agencies intending for an outage to strictly adhere to the shutdown timings. 9) A record may be kept of outage overshooting the approved time of return to bring in seriousness and to avoid market distortion.

10) It is therefore necessary to carry out operational studies in order to assess the grid security and network stability while finalizing the annual outage plan of these important elements.

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5. Defence Mechanisms 5.1

General

5.1.1 Well designed and healthy defence mechanism is a pre requisite for secure operation of the interconnected system. Despite the utmost caution exercised during operational planning and implementing all the above steps for improvement of network security and reliability, the possibility of a contingent situation cannot be totally eliminated. 5.1.2 It calls for suitable defence mechanism to be available in the system to take care of such contingencies. Following are the minimum schemes which should be operational to ensure safe and secure grid operation

5.2

Unit Protection System

5.2.1 In line with the regulation 3 (e) of the CEA (Grid Standards) regulation 2010 all regional entities shall provide standard protection systems having reliability, selectivity, speed and sensitivity to isolate the faulty equipment and protect all components from any type of faults, within the specified fault clearance time and shall provide protection coordination as specified by the Regional Power Committee.

5.2.2 Protection audit of the substations shall be carried out by the respective utilities on a regular basis as advised in Protection coordination committee meetings. 5.2.3 As per 3 (e) of CEA (Grid Standard) regulation 2010, the fault clearance time shall be within the time mentioned in table below: Table 1: Fault Clearance time Sl. No 1 2

Nominal System Voltage in kV rms 765 and 400 220 and 132

Maximum time of fault clearing in ms 100 160

All substations of 220 kV and above shall be equipped with breaker fail protection and bus bar protection scheme. Non clearance of the fault by a circuit breaker within the time limit mentioned above, the breaker fail protection shall initiate tripping of all other breakers in the concerned bussection to clear the fault in next 200 milliseconds.

5.3

Flat Frequency and Rate of Change of Frequency Relay

5.3.1

In line with clause 5.2(n) of IEGC, all regional entities shall provide Automatic Under Frequency Load Shedding in their respective system to arrest frequency decline that could result in a collapse / disintegration of the grid as per the scheme formulated by concerned RPC forum and shall ensure its effective application and functionality at all times to prevent cascade tripping of generating units in case of any contingency.

5.3.2 All Entities shall set their under frequency (UF) Relays and rate of change of frequency with time Relays in their respective systems, in accordance with the plan made by the Regional Power Committee, to provide adequate load relief for grid security and ensure the operation of these relays at the set frequencies. NLDC

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5.3.3

Under-frequency and rate of change of frequency (UFR & df/dt) are envisaged to take care of sudden contingencies arising out of outage of generation stations or separation of inter-regional lines. UFRs setting are for steady state operation of the grid at considerably low frequency and df/dt settings are for fast change in frequency due to large generation outage.

5.3.4

SLDCs shall submit a detailed report of operation of these Relays at different frequencies to Regional Load Despatch Centre and Regional Power Committee on monthly basis and the Regional Power Committees shall carry out inspection of these Relays as and when required.

5.3.5 In line with regulation 5.4.2 (e) of IEGC, the interruptible loads in a control area shall be arranged in four groups of load,  For scheduled power cuts/load shedding,  loads for unscheduled load shedding,  loads to be shed through under frequency relays/(df/dt) relays and  Loads to be shed under any System Protection Scheme identified at the RPC level.

These loads shall be grouped in a manner, that there is no overlapping between different groups of loads. This would ensure that the automatic relief through these relays would be available to the system under all conditions. Under Frequency Relay ( UFR) Load shedding, df/dt load shedding in different regions is given in Annexure X. CEA has revised the UFR settings for NEW grid as per the discussion at the 2nd meeting of National Power Committee(NPC) held on 16th July, 2013. It is to be implemented within three months. It is also given in the Annexure X.

5.4

Under Voltage Load Shedding Scheme As per Cl. 5.3 (t) of IEGC, all Users, CTU and STUs shall provide adequate voltage control measures through voltage relay as finalized by RPC, to prevent voltage collapse and shall ensure its effective application to prevent voltage collapse/ cascade tripping.

5.5

System Protection Scheme

5.5.1 The complexities in Indian electric power system operation are increasing day by day. The size of the grid has expanded manifold and is on a high growth phase. As per Cl. 5.3 (t) of IEGC, All Users, STU/SLDC, CTU/RLDC and NLDC, shall also facilitate identification, installation and commissioning of System Protection Schemes (SPS) (including inter-tripping and run-back) in the power system to operate the transmission system closer to their limits and to protect against situations such as voltage collapse and cascade tripping, tripping of important corridors/flow-gates etc. Such schemes would be finalized by the concerned RPC forum, and shall always be kept in service. If any SPS is to be taken out of service, permission of RLDC shall be obtained indicating reason and duration of anticipated outage from service 5.5.2 As per Indian Electricity Grid Code(IEGC), interstate transmission system(ISTS) shall be capable of withstanding and be secured against the certain outages without necessitating load shedding or rescheduling of generation during steady state operation. These include 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 or Outage of one pole of HVDC bipole or Outage of 765 kV S/C line. 5.5.3

NLDC

The aforesaid contingencies would be superimposed over a planned outage of another 220kV D/C line or 400 kV S/C line in another corridor and not emanating from the same substation. ISTS shall be capable of withstanding the loss of most severe single system infeed without loss of stability. It has also been stated that any one of the aforesaid events shall not cause loss of supply, -

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abnormal Disturbances cause discomfort to the people as well as results into huge economic loss. Therefore, in addition to conventional unit protection system few System Protection Schemes (SPS) are also desirable for safe and reliable operation of the power system. The main objective of SPS is to preserve the integrity of the electric system by using automatic measures that are simple, reliable and safe for the system as a whole and to provide the most extensive coverage against all possible extreme credible contingencies. frequency on sustained basis, unacceptable high or low voltage, system instability, unacceptable overloading of ISTS elements. 5.5.4

As per the IEGC or transmission planning criteria, the system is not designed for 400 kV double circuit line or outage of HVDC bipole. In practice it has been observed that there are some contingencies happening in the system resulting in outage of multiple elements for which system is not designed.

5.5.5

Outage of a large capacity link between two distant nodes in a synchronously interconnected system may result into excessive loading on parallel AC lines, severe drop in voltage profile, power oscillations and finally leading to a major blackout or brown out in the system, in case instantaneous corrective actions are not in place. On the other hand similar outage in an asynchronously connected system may result into load – generation imbalance on either side of the link.

5.5.6

Disturbances like loss of load, loss of generation or loss of transmission line in large grid may cause wide variations in frequency, voltage & load angles. Originating causes of grid failure may be due to equipment failure (including those of protective systems), human error and cascade tripping or large scale disturbances due to weather and/or natural calamities. In view of the above System Protection Schemes have been designed and implemented. These involve predefined generation backing down as well as load shedding under selected contingencies. The details of SPS schemes have been described in detail in Annexure XI.

5.6

Islanding Scheme

5.6.1 In order to isolate the healthy subsystems following a large-scale disturbance, few generating stations/Users and State Utilities have implemented islanding schemes. To avoid total black out of the grid during system disturbances and for early normalisation, the procedure for islanding of systems and major generating stations with associated loads need to be developed constituent wise/system wise. 5.6.2 As per CEA grid standards, the Regional Power Committees shall prepare Islanding schemes for separation of systems with a view to save healthy system from total collapse in case of grid disturbance. 5.6.3 As per CEA grid standards, Islanding Scheme’ means a scheme for the separation of the Grid into two or more independent systems as a last resort, with a view to save healthy portion of the Grid at the time of grid disturbance.

Users/utilities intending to implement any islanding schemes for their station may do so in consultation with RLDC and RPCs secretariat. The details of islanding schemes have been described in detail in Annexure XII.

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6. Collective Transaction Procedures 6.1.0 Introduction 6.1.1 With the implementation of Hon’ble CERC order on Short Term Open Access(STOA), bilateral exchanges / collective transactions have provided a suitable edge to constituents in planning and minimizing the gaps in demand and availability. As per CERC, Open Access regulations dated 25.01.2008 and subsequent (Amendment) Regulations, 2009 dated 20.5.2009, CTU has prepared a detailed procedure for scheduling of bilateral and collective transactions (Available on website of all RLDCs/ NLDC and CTU). 6.1.2

The Procedures shall apply to the Applications made for Scheduling of Collective Transactions by availing of Short-Term Open Access for use of the transmission lines or associated facilities with such lines on the inter- State transmission system.

6.2.0 Collective Transaction Procedure 6.2.1

Collective transactions are implemented through power exchanges. National Load Dispatch Center is the nodal agency for such transactions. Applications under collective transactions are day ahead.

6.2.2

State Utilities and intra state entities participating in trading through Power Exchange shall obtain standing ‘Standing Clearance’ / ‘No Objection Certificate’ from respective State Load Despatch Centres (SLDCs) as per format PX-I specified by CTU in the procedure of scheduling of collective transactions.

6.2.3

List of regional entities shall be displayed on the website of RLDC. Similarly each SLDC shall display the list of intra state entities of their state on their website.

6.2.4

Final schedule for collective transactions is obtained after coordinated operations between NLDC, RLDC and Power Exchange.

6.2.5

All data between NLDC and Power Exchange(s) shall be exchanged electronically through a dedicated communication channel.

6.3.0

Time Line For Submission / Processing

i)

RLDCs shall furnish Available Transmission Capacity (ATC) of respective Region for next day to NLDC at 0900 Hrs of each day. NLDC shall convey the same to Power Exchange by 11:00 Hrs.

ii)

Power Exchange shall furnish provisional interchange on various interfaces/regions/control areas as intimated by NLDC and information of total drawal and injection in each of the regions by 1300Hrs to NLDC.

iii)

PowerExchange(s) shall ensure that “Scheduling Request for Collective Transaction”is within the limits for each time block as intimated by NLDC. Further, Power Exchange(s) shall ensure that the Scheduling Request is within the limits for each time block specified by respective SLDCs in the “Concurrence” or “No Objection” or “Prior Standing Clearance” (submitted by State Utilities/intra-State Entities to Power Exchange(s)).

iv)

NLDC shall check for congestion. In case of congestion NLDC shall intimate Power Exchange

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regarding the period of congestion and available margins at 14.00 hrs. v)

If there is no congestion, at 1600 Hrs. Power Exchanges to send the application for scheduling of collective transaction to NLDC.(As per Format-PX-II of procedure of scheduling of collective transactions). Details of scheduling request for collective transaction shall also be submitted by Power Exchange to NLDC (as per Format-PX-III of procedure of scheduling of collective transactions).

vi)

At 1600 Hrs. NLDC shall send details to RLDC for final checking.

vii)

At 1700 Hrs. RLDC will confirm its acceptance.

viii) At 1730 Hrs. NLDC shall convey acceptance of scheduling to Power Exchange. ix)

At 1800 Hrs. RLDC shall incorporate schedule of collective transaction in the day-ahead schedule.

6.4.0 Implementation of Collective Transaction 6.4.1 Schedule of collective transaction shall be accommodated by RLDC in the day ahead schedule. All buyers within a particular state are clubbed together as one group and all sellers within a state are clubbed together as another group. 6.4.2 Individual transactions for state utilities / intra state entities shall be scheduled by the respective SLDCs. 6.4.3 While finalizing the drawal schedule / injection schedule of entities, each transaction shall have a resolution of 0.01 MW at each state / inter regional boundaries.

6.5.0 Payment Terms For Collective Transaction 6.5.1 Power Exchanges shall pay collective transaction charges to NLDC.

6.5.2 Following charges for use of inter-state transmission system and scheduling at regional level shall be payable to NLDC: (i)

Application fees: Non-refundable application fee of Rs. 5000/- to be paid along with the application

(ii)

Operating charges: Rs. 5000/- per entity. All Buyers within a state is clubbed together into one group and all Sellers within a State are clubbed together into another group. Each Buyer group and each Seller group is considered as separate entities.

(iii) In case of default in payment, NLDC at its discretion may suspend scheduling of transaction and/or terminate already scheduled transaction and/or may not consider any such application in future. Simple interest at the rate of 0.04% for each day of default shall be payable by Power Exchange to NLDC. 6.5.3 NLDC reconciles the Open Access charges collected during the previous month and shall disburse th

the same by 10 day of the current month.

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6.6.0 Curtailment of Short Term Open Access Transaction 6.6.1

Curtailment of STOA transactions becomes necessary in the event of real time congestion in transmission corridor. Bilateral transactions are curtailed first followed by collective transactions and long-term transactions.

6.6.2

Bilateral Transaction shall also be curtailed or cancelled by RLDC, if the Central Government allocates power from ISGS in one region, to an entity in another region and such allocation cannot otherwise be implemented due to congestion in the Inter-regional corridor.

6.6.3

Transmission charges in case of curtailment of bilateral transactions shall be payable on pro-rata basis. Operating charges shall not be revised.

6.6.4

In case of Collective transactions curtailment is done in consultation with NLDC by respective RLDC at the periphery of regional entities. SLDCs shall further incorporate the curtailment of intra-state entities to implement the curtailment.

6.6.5

Transmission charges in case of curtailment of collective transactions shall be payable on prorata basis in accordance with the finally implemented schedule. Operating charges shall not be revised.

6.6.6

Settlement of charges in case of curtailment shall be directly between Power Exchange and the participants. NLDCs/RLDCs/SLDCs shall only interact with Power Exchange.

6.7.0

Bilateral Short Term open access:- The detailed procedure of Short Term Open Access bilateral transaction is available in the operating procedure of each RLDC. STOA bilateral transactions are scheduled according to this procedure.

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7. Scheduling and Despatch Procedures 7.1

Overview

7.1.1 This scheduling and despatch code will be applicable to NLDC, RLDC/SLDCs, ISGS, Distribution Licensees / SEBs/ STUs / regional entities, Power Exchanges, wind and solar generating stations and other concerned persons in the National and Regional grid. This code deals with the procedures to be adopted for scheduling of the net injection / drawals of concerned regional entities on a day ahead basis with the modality of the flow of information between the NLDC / RLDCs / SLDCs/Power Exchange and regional entities In context to the Indian electrical grid, apart from scheduling Inter State Generating Stations (ISGS), drawal schedules of SLDCs are also required to be in place. Under decentralized market mechanism practiced in India, the power system under each SLDC constitutes a notional control area in which the states have full operational autonomy and their SLDCs shall have the total responsibility for scheduling and despatch of their own generation including generation of their captive licensees, regulating the demand of their customers, scheduling their drawal from ISGS, arranging any bilateral exchanges and regulating their real-time drawal from the regional grid. 7.1.2

The revised IEGC 2010 facilitates methodology for scheduling of wind and solar power also. This code provides the methodology for rescheduling of wind and solar energy on three (3) hourly basis and the methodology of compensating the wind and solar energy rich State for dealing with the variable generation through a Renewable Regulatory charge.

7.1.3 Section 6.4 of the IEGC details the demarcation of responsibilities a n d principles and guidelines to be followed for the purpose of scheduling and despatch. This chapter describes the procedure for scheduling with the treatment to be accorded for special conditions. 7.1.4 As per section 28(3)(a), the Electricity Act 2003, the RLDCs shall be responsible for optimum scheduling and despatch of electricity within the region, in accordance with the contracts entered into with the licensees or generating companies operating in the region. The system of each regional entity shall be operated as a notional control area and the regional grids shall be operated as power pools with decentralized scheduling and despatch [IEGC-6.4.5 and 6.4.6].

7.2 .0 General 7.2.1 For the purpose of scheduling, each day(24 hours) would be divided into 96 blocks of 15minutes duration each and for each block, RLDCs would intimate each SLDCs the drawl schedule and to each ISGS the generation schedule in advance as outlines below: 7.2.2 The net drawl schedule of any Regional Entity would be the sum of the ex-PP schedule from different ISGS and the total Open Access (both long term, medium term and short term) exchanges agreed with other constituent States in the region or outside the region minus the estimated transmission loss. The power system under each Regional Entity constitutes a notional control area and hence the Regional Entity would be required to maintain their actual drawl from the grid close to such net drawl schedule by regulating own generation and / or customers load particularly when frequency is going below 49.7 Hz or going above 50.2 Hz. 7.2.3 The despatch schedule of each ISGS / UMPP / ISTS shall be some of the requisitions made by each of the beneficiaries, restricted to their entitlements and subject to the maximum and minimum value criteria and any other technical constraints as indicated by RLDC. 7.2.4 Clause 5.2.(m) of IEGC stipulates the grid frequency operation in the band of 49.7-50.2 Hz. Regions shall endeavour to maintain their drawl in such a manner such that they do not overdraw from the grid whenever the frequency is below 49.8 Hz and do not under draw NLDC

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whenever the frequency is above 50.2 Hz. Similarly, each ISGS shall also endeavour to maintain their generation in such a manner that they do not generate above schedule at frequency above 50.2 Hz and do not generate below schedule at frequency below 49.7 Hz. 7.2.5 RPCs Secretariat would ensure that any change in the allocations from each ISGS is finalized and intimated to all concerned at least 24 hours in advance to facilitate trading of such capacity if required. This is in line with spirit of clause 5.1.3 of the ABT order of CERC. 7.2.6 The scheduling and despatch procedure for the generating stations of Bhakra Baes Management Board (BBMB) shall be as per the procedures formulated by the BBMB in consultation with NRLDC. 7.2.7 Similarly, the scheduling and despatch procedure for the generating stations of Sardar Sarovar Project (SSP) shall be as per the procedures formulated by the WRLDC in consultation with Narmada Control Authority (NCA).

7. 3 Scheduling and Despatch Procedure 7.3.1 By 0800 hrs of every day, each ISGS shall advise RLDCs the station-wise ex-PP MW and MWh capabilities foreseen for the next day in 96 time blocks. 7.3.2 RLDC shall intimate the MW and MWh entitlements for each State during the following day by 1000 hrs in 96 time blocks. 7.3.3

RLDC will communicate to NLDC, the ATC Margins for Export and Import of complete 96 time blocks to facilitate Collective Transactions by Power Exchanges (PX) as per STOA Regulations.

7.3.4 All the drawing regional entities shall review their availability including Short Term Open Access (STOA) vis-à-vis foreseen demand and by 1500 hours would advise RLDC their requisition in each of the regional ISTS Control Area generating stations along with the already approved STOA transactions. While indicating their station-wise requisitions RLDCs must ensure that the step change should not cause ramp-up / ramp-down of the ISGS / HVDC in order to avoid sudden steep excursions in system frequency. 7.3.5 NLDC will send the trade schedule details to respective RLDCs for final checking and for accommodating them in their final schedule at 1600 hrs. RLDCs shall prepare final schedule for the collective transactions and communicate to NLDC by 1700 hrs. 7.3.6 AT 17.30 hrs. NLDC shall confirm the acceptance of collective transactions schedule prepared by RLDCs to Power Exchange. At 1800 hrs. PXs shall send the detailed break up of each point of injection and each point of drawal within the state to concerned SLDC for scheduling. 7.3.7 By 1800 hours, RLDC shall convey to each regional ISTS Control Area generating stations the generation schedule i.e., ex-PP despatch schedule and to each drawing Regional Entities the net drawl schedule that is the schedule at the periphery of the State after deducting the apportioned estimated transmission losses. 7.3.8 RLDCs shall club together all buyers within a State and all seller within a State for the purpose of scheduling of regional entities. 7.3.9 The SLDCs / Regional ISTS Control Area generating stations / drawing Regional Entities may inform the modifications / changes to be made if any in the above schedule to RLDCs by 2200 hrs. 7.3.10 RLDCs shall issue the final generation / drawl schedule to each Regional ISTS Control Area generating stations / drawing Regional Entities by 2300 hrs. 7.3.11 RLDCs will ensure following points while preparing the schedule: 7.3.11.1 The final drawl / despatch schedule shall not give rise to any transmission constraints. NLDC

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In case of such constraints, RLDCs shall moderate the schedule to the required extent. 7.3.11.2 The final drawl /despatch s c h e d u l e s shall b e o p e r a t i o n a l l y r e a s o n a b l e particularly in terms of ramping up / ramping down rates and ratio between minimum and maximum generation levels. In case of such problem, RLDCs shall moderate the schedule to the required extent. 7.3.11.3 The procedure to be followed for STOA collective agreements has already been indicated in Chapter-6. 7.3.11.4 NLDC will continuously check the schedules of all interregional exchange received from each RLDCs and ensure that they are matching to each other. If any mismatch, then NLDC will communicate to corresponding RLDCs to rectify the same.

7.4 . Revision of Schedules 7.4.1 In case of a forced outage of a unit, RLDC will revise the schedules on the basis of revised DC. The revised schedule will become effective from the 4th time block counting the time block in which the revision is advised by the generator to be the first one. 7.4.2 In the event of a situation arising out of bottle neck in evacuation of power due to transmission constraints, RLDC shall revise the schedule which shall become effective from the 4th time block counting the time block in which the transmission constraint has been brought to the notice of RLDCs as a first one. During the first three time blocks, the schedules shall deem to have been revised to be equal to the actual generation of ISGS and drawl by the States. 7.4.3 In case of transmission constraints, curtailment shall be done by RLDC in following priority: i)

Inter-regional UI if any.

ii)

STOA, if any on pro-rata basis

iv)

Collective transactions

v)

Medium term customers

iv)

Long term customers on pro-rata basis

Only the curtailments relieving congestion will be done. 7.4.4 Revision of declared capability by generator and requisition by the beneficiaries for the remaining period of the day shall be permitted with advance notice. Revised schedules / declared capability in such cases shall become effective from the 6th time block counting the time block in which the request for revision has been received by RLDC to be the first one. 7.4.5 If at any point of time, RLDCs observes that there is need for revision of schedules in the interest of better system operation, it may do so on its own and in such cases, the revised schedules shall become effective from the 4th time block counting the time block in which the revised schedule is issued by RLDC to be the first one. 7.4.6 On completion of the operating day, the final schedule as implemented shall be issued by RLDCs after incorporating all before the fact changes during the day of operation.

Exchange of Information

7.5

In order to avoid any adverse commercial effect on the ISGS/SLDCs, the need for a reliable and fast communication arrangements for exchange of information in respect of scheduling need not be over emphasized.

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7.5.1 The revision of schedule would be required under the following conditions as detailed at 7.4 i)

Forced outage of an Regional ISTS Contro Area generating stations

ii) Transmission constraints resulting in output reduction in any ISGS iii) Revision of DC by any Regional ISTS Control Area generating stations iv) Revision of requisition by any beneficiary Regional Entity v)

Suo Moto revision by RLDC in the interest of better system operation

As the time available for schedule revision is limited (half an hour to one hour only), some of the steps mentioned above would be skipped for e.g., in cases i), ii) & iii) above, there need not be any fresh requisition from the beneficiaries and RLDC would assume as follows: a) On occasions of downward revision: The beneficiary Regional Entity requisition will be deemed as earlier MW requirement or maximum revised entitlement whichever is less. b) On occasion of upward revision: The beneficiary Regional Entity requisition will be deemed as earlier MW requirement if there was under-requisition by the constituents prior to the revision otherwise the constituents requirement will be deemed as full revised entitlement. 7.5.2 In view of large volume of information needed to be exchanged in a time bound manner, the transfer of information between RLDCs and other constituents i.e., constituent States and ISGS will be carried out on internet only. However, in case of contingencies like internet failure etc., the transfer of information could be effected through alternate mode i.e., fax / telephone on request of concerned SLDC/ISGS. 7.5.3 The ISGS and all beneficiaries shall get the information at the RLDCs website with regard to scheduling by continuous access to RLDC website and download the generation / drawl / STOA schedules. 7.5.4 At the end of the day, the final schedule as implemented after incorporating all before the fact changes during the day of operation shall be made available by RLDCs in the website and can be downloaded by the constituents. 7.5.5

Scheduling of Wind and Solar generation shall be done as per IEGC clause 6.5.23 & CERC Order No 209/2011. w.e.f 01.07.2013

7.5.6 The conventional voice / fax arrangement would act as back-up in case of failure of PC -to-PC communication link through INTERNET. 7.5.7 No link wise schedule at inter regional level.

Inter Regional Schedule

7.6

NLDC would be separately working out a mechanism for approval of interregional STOA transactions at NLDC level, for preparing net interregional schedules and inter regional UI computations. This would however involve need for amending the Open Access Regulations of CERC for dispersing with path specific approvals, amendments to IEGC & UI Regulation so as to have a National Pool Account etc..

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8. Grid Disturbances and Revival Procedures 8.0

Objective The objective of this chapter is to facilitate restoration and resynchronization of affected systems in the wake of grid disturbance in the shortest possible time taking into consideration all essential requirements like traction loads, Hospital loads, core sector industrial loads, Nuclear power stations, generation capability and the operational constraints of transmission system.

8.1

Overview

a)

A grid disturbance is a power system state under which a set of generating units / transmission elements trip in an abrupt and unplanned manner affecting the power supply in a large area and / or causing the system parameters to deviate from the normal values in a wide range. In the event of a grid disturbance, highest priority is to be accorded to early restoration / revival of the system.

b)

As per CEA regulations on Grid standards 2010, (a)“Grid disturbance” means tripping of one or more power system elements of the grid like a generator, transmission line, transformer, shunt reactor, series capacitor and Static VAR Compensator, resulting in total failure of supply at a sub-station or loss of integrity of the grid, at the level of transmission system at 220 kV and above. (b) “Grid incident” means tripping of one or more power system elements of the grid like a generator, transmission line, transformer, shunt reactor, series capacitor and Static VAR Compensator, which requires re-scheduling of generation or load, without total loss of supply at a sub-station or loss of integrity of the grid at 220 kV and above.

c)

During restoration, it is possible that system may have to be operated with reduced security standards and under suspension of all commercial incentives / penalties. This chapter forms the guidelines for classifications of disturbances into different categories for the purpose of analysis and reporting. In case of a Grid disturbance in any of the region/regions, NLDC shall inform to the other regions about the disturbance and extent all possible support to the affected region.

d)

List of generating stations with black start facility, inter-State/interregional ties, synchronizing points and essential loads to be restored on priority, shall be prepared and be available with NLDC, RLDC and SLDC.

e)

Detailed plans & procedures for restoration of the regional grid under partial/total blackout shall be developed by RLDC in consultation with NLDC, all users, STU, SLDC, CTU and RPC Secretariat and shall be reviewed /updated annually.

f)

Detailed plans and procedures for restoration after partial/total blackout of each User’s/STU/CTU system within a Region, will be finalized by the concerned User’s/STU/CTU in coordination with the RLDC. The procedure will be reviewed, confirmed and/or revised once every subsequent year. Mock trial runs of the procedure for different subsystems shall be carried out by the Users/CTU/STU at least once every six months under intimation to the RLDC.

g)

Diesel Generator sets for black start would be tested on weekly basis and test report shall be sent to RLDC on quarterly basis.

h)

Detailed Restoration Procedures for restoration of integrated/national grid prepared by NLDC shall be made available at NLDC control room. RLDCs Restoration manual also be available at

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NLDC control room and referred during grid disturbances for reliable and quick restoration.

Classification of Grid disturbances/Incidents

8.2

8.2.1 The classifications of grid disturbances in increasing order of severity as per CEA Grid Standards is given below:i) Category-GD-1: When less than ten percent of the antecedent generation or load in a regional grid is lost; ii) Category-GD-2: When ten percent. to less than twenty percent of the antecedent generation or load in a regional grid is lost. iii) Category-GD-3: When twenty percent. to less than thirty per cent. of the antecedent generation or load in a regional grid is lost iv) Category-GD-4: When thirty percent. to less than forty per cent. of the antecedent generation or load in a regional grid is lost v) Category-GD-5: When forty percent. or more of the antecedent generation or load in a regional grid is lost. 8.2.2 The classifications of grid incidents in increasing order of severity as per CEA Grid Standards is given below:i)

Category-GI-1: Tripping of one or more power system elements of the grid like a generator, transmission line, transformer, shunt reactor, series capacitor and Static VAR Compensator, which requires re-scheduling of generation or load, without total loss of supply at a sub-station or loss of integrity of the grid at 220 kV (132 kV in the case of North-Eastern Region); Category-GI-2: Tripping of one or more power system elements of the grid like a generator, transmission line, transformer, shunt reactor, series capacitor and Static VAR Compensator, which requires re-scheduling of generation or load, without total loss of supply at a sub-station or loss of integrity of the grid at 400 kV and above (220 kV and above in the case of NorthEastern Region).

ii)

8.2.3

In any case, if only one state system or one ISGS is affected, the schedules would not be suspended but only revised.

8.2.4

In case of transmission constraints, curtailment shall be done by RLDCs on following priority: First

: Inter Regional UI, if any

Second : STOA, if any on pro-rata basis, bilateral transactions Third : Collective transactions Last

: Medium term & Long Term Customers on pro-rata basis

8.2.5

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

8.3

System Revival

8.3.1 The general guidelines and precautions to be followed during system revival are indicated below: i) NLDC

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remains within limits. ii)

Security of the network being built up would be strengthened at the earliest b y c l o s i n g t h e p a r a l l e l lines available in the restoration path.

iii)

Priority would be accorded for extending supply to Railway tractions, Mines installations where safety is of paramount important such as Nuclear power stations

iv)

All s w i t c h i n g i n s t r u c t i o n s f o r a particular system have to emanate from a single agency i.e. SLDC/CPCC as the case may be. For synchronization of two systems within a region, RLDC would be the coordinating agency and for interregional synchronisation NLDC would be the co-ordinating agency.

v)

During revival, only authorized personnel would be present in Control room of substation / power station / SLDC / RLDC / NLDC so as to expedite restoration.

vi)

In l i n e w i t h s e c t i o n 6.8(e) of I E G C , a l l c o m m u n i c a t i o n channels for restoration process shall be used for operational communication only until the grid normalcy is restored.

vii)

FGMO/RGMO and frequency/voltage control.

viii)

Synchronising facility shall be made available at major grid substations so as to have flexibility in choosing the point of synchronization.

ix)

All SLDCs / ISTS / RLDC / NLDC shall make available a copy of the latest ‘Recovery Procedures’ for ready reference to their operating staff in Control room.

x)

In case of disturbance or any other contingency in any region, NLDC shall exchange of such power with the neighbouring region on Unscheduled Interchange (UI) basis, needed to meet the essential load, start-up-power, railway traction and other such emergent requirements for the duration of such contingencies.

xi)

The RLDC is authorized during the restoration process following a black out, to operate with reduced security standards for voltage and frequency as necessary in order to achieve the fastest possible recovery of the grid.

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9. Event Information and Reporting Procedure 9.0

Objective

a)

The objective of this section is to define the incidents to be reported, the reporting route to be followed and information to be supplied in order to ensure consistent approach in reporting of the events/incidents.

b)

This section deals with reporting procedures in respect of events in the system to all Users/STU/ CTU, RPC Secretariat and NLDC/RLDC/SLDC. The reporting procedure shall be in accordance with the relevant CEA/CERC Regulations.

9.1

Overview

a)

Timely and accurate reporting and exchange of information plays an important role in grid operation. This assumes more importance during a disturbance or crisis. Timely and accurate information flow under such conditions would help people in making an informed decision and reduces uncertainty.

b)

The RLDC/SLDC shall be responsible for reporting events to the Users SLDC/STU, CTU/NLDC/RLDC/RPC Secretariat as the case may be.

c)

All Users, STU, CTU and the SLDC shall be responsible for collection and reporting of all necessary data to NLDC,RLDC and RPC Secretariat for monitoring, reporting and event analysis as the case may be.

9.2

Event Information

9.2.1 The significant and abnormal events which are required to be reported are articulated in clause 5.9.5 of IEGC as listed below: i) ii) iii) iv) v) vi) vii) viii)

Violation of security standards Grid indiscipline Non compliance of NLDC/RLDCs instructions System islanding / system split Blackout / partial system blackout Protection failure on any i mp o r t an t element the systems Power system instability Tripping of any important element like heavily loaded line, generating unit, ICTs, Reactor, TCSC, SVC of the grid. ix) Sudden load rejection by any user

9.2.3 Any operation planned to be carried by region which may have an impact on the grid or on any of the important element, shall be reported by RLDC in advance to NLDC. 9.2.4 Any operation planned to be carried out on the instructions of RLDC which may have an impact on the system of a constituent/s shall be reported by RLDC to such constituent/s in advance. 9.2.6 The intimation and the exact time of revival of any important element whether revived after a tripping or after a prolonged outage will be furnished to RLDC as early as possible by regional entities. Subsequently, RLDC shall inform the same to NLDC.

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9.3

Reporting system The details of event reports, grid disturbance/incident reports and periodic reports to be prepared and issued by constituents / RLDC are as follows:

9.3.1 Event Report and Grid Disturbance/Incident Report (RLDC to NLDC) Event Reporting In the event of tripping of important elements of RLDCs/NLDC, whether manual or automatic, shall be intimated by RLDCs to NLDC in a reasonable time say within 10 to 30 minutes of the incident. Along with the tripping intimation, the reasons for tripping (to the extent known) and the likely time of restoration shall also be intimated. Such information can be on telephone, fax or e-mail. The preliminary event report to be submitted by RLDCs to NLDC within 4 to 6 hours of the occurrence of the event. The detailed event report to be submitted on next day.

Grid Disturbance/Incident Report In the event of grid disturbance/grid incidents and any other significant and abnormal events as per Cl. 9.2.1 above, the constituents whose area / stations get affected in the Incident/disturbance shall submit a report to RLDC within 24 hours. Along with the report, clear copies of disturbance recorder (DR), sequential event recorder (SER), data acquisition system (DAS) outputs, relay flag indications and restoration sequence would be sent to RLDCs. RLDCs would send the above information’s along with detailed tripping analysis to NLDC not later than three working days of the incident. RLDCs would send the preliminary report within 4- 6 hours of the Grid Disturbance/Incident to NLDC. It is observed that multiple element outages in the system are quite common leading to Grid Disturbances/Incidents of different severity as per CEA Grid standards. Multiple element outages are beyond N-1 and N-1-1 criteria. Hence all RLDCs would record all such events. All delayed fault clearance on system to be flagged and taken up appropriately. Letter issued to all RLDCs in this regard is attached as Annexue 13.

9.3.3 Weekly Report and Daily Report A weekly report covering performance of the national/integrated grid in previous week is prepared by NLDC and the same report shall be available on the website of NLDC for 12 weeks. NLDC is preparing and uploading the daily report of previous day of performance of All India System Operation based on the inputs received from RLDCs.

9.3.4 Monthly Report NLDC is preparing the monthly report covering the performance of national/integrated grid NLDC sends this report to CERC, CEA, RLDCs and RPCs and it is uploaded in website also.

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10. Switching Coordination 10.1. Overview Coordination of switching operations in the grid is important for ensuring safety of personnel and equipment as well as for ensuring adequacy and security of the grid. Before any operation of important elements under NLDC perspective, is carried out on a User/STU system, the Users, SLDC, STU, CTU, licensee shall inform RLDC and RLDCs would inform to NLDC. Before any operation of important elements of the Regional Grid is carried out on a User/STU system, the Users, SLDC, STU, CTU, licensee shall inform RLDC.

10.2. Switching of System Elements for the First Time 10.2.1 In line with Regulation 6 (1) of the Central Electricity Authority (Grid Standards) regulations 2010, no entity shall introduce or take out an element in the ISTS of Regional Grid without the concurrence of RLDCs in the form of an operation code. In case a new power system element in Regional grid is likely to be connected with the Inter-State Transmission System or is to be energized for the first time, from the ISTS, the applicant User/STU/CTU/licensee shall send a separate request in advance along (at least one week) with the confirmation of the following:  Acceptance of RLDC with regards to registration as regional entity  Signed Connection Agreement if applicable  Availability of telemetry of station/Element at the RLDC/SLDC  Availability of voice communication with the station at RLDC/SLDC  Interface meter installed and tested by downloading data and forwarding it to RLDC  Single Line Diagram  Healthiness of Protection System/Protection Setting  Statutory clearance has already been obtained 10.2.2 Also NLDC approval to be obtained by respective RLDCs before introducing any new inter regional elements, 765kV elements, HVDC elements and any element will effect the TTC/ATC in Inter/Intra Reginal levels and Trans- national elements. Those details to be sent in advance along with protection details, Telemetry and voice communication details, Single Line Diagrams, Study details.

10.3. Switching of Important Elements 10.3.1 In line with regulation 5.2 (a, b, c), of the IEGC no part of the Regional grid shall be deliberately isolated from the rest of the National/Regional grid except under an emergency and conditions in which such isolation would prevent a total grid collapse and would enable early restoration of power supply or safety of human life; when serious damage to a costly equipment is imminent and such isolation would prevent it; when such isolation is specifically instructed by RLDC/NLDC. 10.3.2 Important elements under NLDC perspective is given in Annexure VIII. RLDCs shall obtain ‘operation code’ from NLDC before carrying out any switching operation on any of the important elements under NLDC perspective. RLDCs would ensure that the outage availed should come into service as per the scheduled time. Delays with reasons thereof if any should be reported to NLDC in advance. 10.3.3 Important elements of the regional grid, which have a bearing on the network security, is compiled and issued by respective RLDCs as a separate document. The regional entities, users, STU, CTU, licensee shall obtain ‘operation code’ from RLDCs before carrying out any switching operation on any of the important elements of the Regional grid. Shut down of any 400 kV bus at substation needs approval of RLDCs. NLDC

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10.3.4 In respect of double main and transfer switching scheme at 400 kV substations, RLDCs shall be informed whenever the 400 kV transfer breaker at any substation is utilized for switching any line/ICT. In a 400 kV substation/power station switchyard having breaker and a half switching scheme, outage within the substation (say main or tie circuit breaker) not affecting power flow on any line/ICT can be availed by the constituents under intimation to RLDCs. However, while availing such shutdowns or carrying out switching operations it must be ensured that at least two Dias are complete even after such outage from the view point of network reliability. Any outage not fulfilling the above conditions needs the approval of RLDCs. If above mentioned elements are coming under NLDC important elements, RLDCs should inform/get approval from NLDC. 10.3.5 Whenever any protection system such as Bus Bar protection, LBB protection, Auto reclose etc. at generating station or grid substation is required to be taken out of service for any maintenance work, an operational code would be taken from SLDC/RLDCs. NLDCs approval is required if it comes under NLDC important elements category. 10.3.6 Emergency switching if any have to be carried out and immediately informed to RLDC within a reasonable time, of ten minutes. Likewise, tripping of any of these important elements should also be informed to RLDCs within a reasonable time indicating the likely time of restoration. In case of single phase to ground fault (with low fault current level say