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 <4 kA) one attempt to close the line would be taken by the transmission utility without waiting for an operation code from RLDCs. However the tripping and restoration would be intimated to RLDC immediately. Before charging, all necessary precaution shall be taken care by substation and in coordination with other end substation. If above mentioned elements are coming under NLDC important elements, RLDCs should inform/get approval from NLDC.

10.4. Other Precautions to be taken during Switching In addition to the above, it is necessary that special attention to be paid to maintaining the reliability of the system. The following areas need careful implementation by the concerned constituents / stations: (i)

In case of a two-bus system at any substation it must be ensured that the segregation of feeders on the different buses is uniform. This would help in minimizing the number of elements lost in case of a bus fault. This is assuming the availability of bus-bar protection at such substation(s).

(ii)

In 400 kV substations having a breaker and a half scheme, it must be ensured that the two buses at such substation remain connected at least by two parallel paths so that any line / bus fault does not result in inadvertent multiple outages. In case any element, say a line or an ICT or a bus reactor, is expected to remain out for a period say beyond two hours at such substation, the main & tie breakers of such elements should be closed after opening the line side isolator. This should be done after taking all suitable precautions to avert inadvertent tripping. This of course assumes that no maintenance is planned on such breakers / isolators.

(iii) In case when circuit breaker controlling the line is under lockout it is not advisable to interrupt the changing current through an isolator the following practice to be adopted in such cases :a) De-energise the bus connecting the line with lockout CB and then open the isolator.

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b) If due to some reason it is not possible to open the isolator in above mentioned way, then open the isolator so that no charging current is interrupted through the isolator and the charging current is diverted to other parallel path. Such switching sequence could be possible in case of breaker and half scheme or Double breaker Scheme, which is as follows: 

Open the line from remote end first with direct trip (DT) disabled. With this now line remains charged from the end where CB has problem.



In case of breaker and half scheme open the isolator so that charging current is diverted to the parallel path and after that open the CB of parallel path.



In case of double breaker scheme open the isolator of the lockout breaker diverting the charging current to other CB and then open the CB.



In case of double main and transfer scheme open the isolator of lockout breaker so that divert the charging current through transfer bus coupler and then open the line through TBC circuit breaker.

It is also recommended that while vacating a bus in such cases, the operators need to check the switching arrangement for individual feeders so as to avoid unintended loss of any feeder. (iv) The substation operators must ensure the above condition even when any lightly loaded line is opened to control overvoltage. Such opening of lines is generally superimposed over other line outages on account of faults created by adverse weather conditions resulting in reduced security of the system. (v)

Single pole auto-reclose facility on 400 kV / 220 kV lines should always be in service. RLDC’s/NLDCs approval would be required for taking this facility out of service.

(vi) All precautions should be taken to avoid switching on to fault particularly in case of Interconnecting Transformers. In order to avoid fault current through costly equipment generally the line shall be charged from the far end, wherever possible. (vii) A transmission line side shall preferably be charged from the grid substation. Dead line charging by a generator shall normally be avoided except during system restoration, black start, or in case where both ends of the transmission line are terminating at a generating station. (viii) During test charging of transmission line for the first time, all safety precautions shall be taken and the transmission utility owning/operating the line shall satisfy the substation utility at either ends with regards to statutory/safety clearances. During test charging if the line does not hold even after two attempts, thorough checking of protection settings and line patrolling shall be carried out. (ix) Operation code issued by NLDC/RLDC for switching shall become invalid if the switching is not completed within half an hour of issue of code. In case the switching operation is not completed within half an hour of the issue of operation code from RLDCs/NLDC, and if there is a probability of further delay same code could be revalidated by RLDC/NLDCs within that half an hour. The utility obtaining at one end shall intimate the other end utility.

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ANNEXURE I Frequency Linked Despatch Guidelines All generating units above 200 MW should participate in primary regulation wherein the output of the generator increases or decreases as per droop characteristics of the turbine without any manual action when the frequency decreases or increases respectively. However as per IEGC regulation 6.4.15, all regional entities should abide by the frequency linked dispatch guidelines. This implies that each generating stations is expected to maintain its scheduled generation till a threshold frequency where the UI rate is more than the variable cost of generation of that unit. Therefore when the output of the generating unit has changed as a result of mandatory primary response, its output may be readjusted depending upon the system frequency and the variable charge of the station. For this purpose, the threshold frequency for ISGS unit shall be determined from the prevailing design of the Unscheduled Interchange vector and the variable charge of the station. The threshold frequency for the generating units within the State control area will be specified by SLDCs. The generator on its own can reduce generation when frequency goes above this cut-off frequency. For frequency below cut-off frequency, the generator would respond to frequency changes but would come back to its set point in a slow manner with ramp rates of 1% MW per minute. This may be further understood by the illustration given below. Consider a generator of 500 MW capacity with 5% droop setting, operating at 100 % load when the frequency is 49.6 Hz (Operating point ‘A’ in figure 1). In case the frequency falls from 49.6 Hz, the generator would pick up load say up to 105 % (i.e. 525 MW and limited by load limiter set at 525 MW; Operating point ‘B’ in figure 1). After the primary response by the generator, the load on the generator may be reduced in a gradual manner and may be brought back to its original level of 100% (i.e. 500 MW; operating point ‘C’ in figure 1) in about 5 minutes time. At point ‘C’, the machine can once again respond to frequency change from ‘C’ with droop of 5 % (along dotted line CD). In case of frequency increases from 49.6 Hz, the generator would reduce its output instantaneously as per droop characteristics (Operating point would change from ‘A’ to ‘E’). After the primary response by the generator, the load on the generator may be increased in a gradual manner to the desired level (Operating point would change from ‘E’ to ‘F’). Alternatively, if the generator is operating at threshold level say at point ‘G’ in figure 1 and the frequency rises further, then the machine can drop generation as per droop characteristics (operating point ‘G’ to ‘H’ and then from ‘H’ to ‘J’ ).

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Figure 1: Frequency linked despatch for supplementary regulation

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Annexure II - FRC Procedures

Annexure II Procedure for Assessment of

Frequency Response Characteristic (FRC) Of

Control Areas in Indian Power System

Power System Operation Corporation Ltd In association with

Forum of Load Despatchers (FOLD)

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This Page has been Intentionally Left Blank

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INDEX 1.

Background

2.

Definitions

3.

Frequency Response

4.

Control Area Wise Frequency Response

5.

Procedure to calculate Frequency response Characteristic (FRC)

6.

Limiting Factors

Annexure-1(A): Regions under Jurisdiction of NLDC/RLDC Annexure-1(B): Regional Entities of Gujarat Under Jurisdiction of SLDC Annexure-2:

Illustrative Example for Calculation of FRC

References

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1. Background 1.1.

The objective of this procedure is to develop a common understanding among all the control areas and other entities responsible for the reliable operation of each Interconnection in India for computation of FRC.

1.2.

This procedure has been developed to monitor the compliance of Regulation 5.2. (f) of the Indian Electricity Grid Code, 2010.

2. Definitions

2.1.

As per IEGC “Control Area means an electrical system bounded by interconnections (tie lines), metering and telemetry which controls its generation and/or load to maintain its interchange schedule with other control areas whenever required to do so and contributes to frequency regulation of the synchronously operating system”. In Indian context, the geographical area of a state under the jurisdiction of SLDCs, Inter State Generating Stations (ISGS) and regional entities whose scheduling is coordinated by RLDCs are deemed control areas for the purpose of this procedure.

2.2.

“Net Interchange” of the Control Area is the algebraic sum of its Imports (+) and Exports (-) with other control areas.

2.3.

“Demand” means the demand of Active Power in MW.

2.4.

“Frequency response” is defined as the automatic, sustained change in the power consumption by load or output of generators that occurs immediately after a change in the control area‟s load-generation balance and which is in a direction to oppose a change in the Interconnection‟s frequency.

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2.5.

“System Inertia” is the ability of power system to oppose changes in frequency. Physically, it is loosely defined by the mass of all the synchronous rotating generators and motors connected to the system.

2.6.

“Interconnection” refers to one synchronous system operating at a common frequency. In the Indian context, NEW Grid/Bhutan and Southern Grid would be two interconnections.

2.7.

“Historical Data Recording (HDR)” refers to the facility to archive and retrieve data at periodic intervals (typically 10 seconds or lower) from the Systems available at each SLDC, RLDC, NLDC or at Generating Station.

3. Frequency Response During a contingency, such as the tripping of a generator or a loss of load block, the frequency changes due to the mismatch in load and generation. The level to which the frequency drops depends on the starting operating point as well as the system inertia. It is the system inertia, which provides the initial ability of power system to oppose change in the frequency. If the system inertia is high, then the frequency will fall slowly and vice versa, during any system contingency. It is the natural frequency response of a control area, which provides self healing immediately after occurrence of a contingency. The various sources that contribute to the response of a control area are shown in the resources pyramid (Figure-1).

Frequency

Response

Regulation (Secs to Mins) Operating reserves Load Following Market

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Figure-1: Frequency Response Frequency response is an inherent property of the system and influences the interconnection frequency change post-contingency and well before any secondary actions, manual or automatic take place. In Indian context, a change in frequency postcontingency provides a price signal to all generators in the system through the frequency linked Unscheduled Interchange (UI) mechanism. The generators may respond to these price signals & vary their generation accordingly. This could happen over the next few minutes (commonly known as secondary response) or over the next half-hour (commonly known as tertiary response. As tight control on net interchange of a control area is not mandated, it can be stated that secondary control is absent by design in the Indian power system. Primary response is however mandated as per the Indian Electricity Grid Code (IEGC). There are two groups of resources which contribute to the frequency response namely load response and governor response of generators. 3.1.

Load Response:

Loads also respond to these frequency fluctuations though in an uncontrolled fashion. In general, loads can be grouped into two major categories: motoring loads and nonmotoring loads. A Motor load in particular is affected by frequency. When a frequency drops, the motors slow down and they produce less work and therefore consume less energy. Typically for rotating loads such as motors, a 1% change in frequency leads to a 3% change in load [load being approximately proportional to cube of frequency] i.e., a 1.0 Hz change in frequency (2 % of 50 Hz) leads to the motor load changing by 6%. (Source: NERC Training Document Understand and Calculate Frequency Response). However lighting loads such as resistive (non-motoring) are insensitive to frequency.

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Figure-2: Load Characteristics with 5% droop The total load in the grid comprise of different kind of load and thus the frequency behavior of the load would depend on the composition of load viz. rotating and nonrotating. Frequency response from loads is declining and has been a cause for concern world-wide. Primary reason for the same is a reduction in industrial load (comprising rotating motor loads) over the years. The modern variable speed drives installed also do not provide the traditional load rejection. In India also there has been a gradual reduction in industrial load. Extract from the Economic Survey 2010-11 is indicated in Table 1 below. Table 1: Percentage electricity consumption across different sectors in India over the years

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From Table 1 it would be seen that the electricity consumption across industry, traction and agricultural (which would be mainly rotating loads) has fallen from 73.9% in 1950-51 to 59.7% in 2008-09.

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Domestic+ Commercial

Industry

Agriculture

70 60 50 40 30 20

2007-08

2005-06

2003-04

2001-02

1999-00

1997-98

1995-96

1993-94

1991-92

1989-90

1987-88

1985-86

1983-84

1981-82

0

1970-71

10

1950-51

Percentage of Electricity Consumption

80

Figure-3: Pattern of Electricity Consumption In contrast, the domestic and commercial consumption has increased from 20.1% in 1950-51 to 34.9% in 2008-09. There is an increasing trend in all silicon load (electronic devices) component not only in the domestic and commercial segments but also in the industry. These electronic loads do not provide the desired frequency response. This has a bearing on the frequency response from loads. Thus a frequency response of around 34% per Hz could be expected from loads due to its inherent nature. On the other hand, decrease in the System Inertia is also contributing to the decline in the frequency response. Inertia is the stored rotating energy in the system. Physically, it may loosely be defined by the mass of all the synchronous rotating generators and motors connected to the system.

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The inertia constant „H‟ for rotating machines is denoted by

Where, J = combined inertia of the generator and turbine w = rated angular velocity in mechanical radians per second. Following a contingency, the higher system inertia (assuming no frequency response) the longer it takes to reach a new steady state operating frequency i.e., frequency falls slowly. Directly connected synchronous generators and Induction generators will contribute directly to system inertia. A trend in decline of system inertia on account of new generator designs having less inertia and increasing renewable resources are contributing to the decline in the frequency response.

Source Machine Rating (MW) Rated MVA Inertia Constant „H‟ (Sec)

210 MW Singrauli-I 210 247 2.73

500 MW Singrauli-II 500 588 3

800 MW CGPL-I 830 960 2.71

Dehar Hydro 165 173.7 4.56

Nathpa Jhakri 250 278 4

From the above table it would be observed that inertia constant of 830 MW thermal generator commissioned in March 2012 is less than 500 MW thermal generating units commissioned in mid 1980s. Likewise a 250 MW hydro generator commissioned in 2003 has less inertia constant than a unit commissioned in early eighties. The issue of inertia is particularly important for high wind power penetration levels in synchronized systems. Most of the wind turbine generators are Standard variable speed wind turbines which are connected to the grid based on non-synchronous interfaces, e.g. power electronic converters. This gives variable speed wind turbines virtually zero inertia in power systems.

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3.2.

Generator Response: As per regulation 5.2.(f) of IEGC “All thermal generating units of 200 MW and above and all hydro units of 10 MW and above, which are synchronized with the grid, irrespective of their ownership, shall have their governors in operation at all times in accordance with the following provisions:

Governor Action

i) Following Thermal and hydro (except those with upto three hours pondage) generating units shall be operated under restricted governor mode of operation with effect from the date given below:

a) Thermal generating units of 200 MW and above, 1) Software based Electro Hydraulic Governor (EHG) system: 01.08.2010 2) Hardware based EHG system b) Hydro units of 10 MW and above

01.08.2010 01.08.2010

ii) The restricted governor mode of operation shall essentially have the following features: a) 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 MCR of the unit subject to machine capability. b) 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. c) If any of these generating units is required to be operated without its governor in operation as specified above, the RLDC shall be immediately

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advised about the reason and duration of such operation. All governors shall have a droop setting of between 3% and 6%. d) After stabilization of frequency around 50 Hz, the CERC may review the above provision regarding the restricted governor mode of operation and free governor mode of operation may be introduced. iii) All other generating units including the pondage upto 3 hours Gas turbine/Combined Cycle Power Plants, wind and solar generators and Nuclear Power Stations shall be exempted from Sections 5.2 (f) ,5.2 (g), 5.2 (h) and ,5.2(i) till the Commission reviews the situation”. All generators have some type of governor control. The governor senses a change in speed and regulates the energy to be delivered to the generator‟s prime mover. The changes in the generator output (MW) are in response to the change in frequency and occurs in the 3-10 seconds time frame. Primary response is responsible for the initial arrest of frequency variations. System Protection Schemes (SPS), Under frequency and df/dt relay operation occurs in the millisecond time frame, even before the primary response comes into play. 3.2.1. Generator Droop The ratio of frequency deviation to change (in per unit terms) in power output (in per unit terms) is defined as droop. What actually decides governor response is the generator‟s “droop setting.” This is the governor function that dictates the relationship between speed and power output. As per Regulation 5.2 (f) of Indian Electricity Grid Code (IEGC), all thermal units of 200 MW & above and all hydro units of 10 MW and above (except those up to three hours pondage), which are synchronized with the Grid, irrespective of their ownership shall have a droop setting between 3% and 6%.

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120

POWER (% MCR)

100

5% droop

75

50

25 0 49.0

50.0

51.0

52.0

52.5

FREQUENCY (HZ)

Figure-4: Generator Characteristics with 5% droop For example, a 5% droop or regulation means that a 5% (2.5 Hz) frequency deviation causes 100% change in power output. That is, for a unit operating at 50 Hz and full load, a 2.5 Hz rise in frequency would cause the governor to attempt to take the unit to no load.

3.2.2. Deadband Dead_band is the minimum amount of frequency change a governor must see before it starts to respond. As per the regulation 5.2.(f) of IEGC, “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”.

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4. Control Area Wise Frequency Response 4.1.

India follows a decentralized philosophy in which functions like scheduling, accounting, monitoring and control follow a hierarchical structure. Demand estimation, demand management, load generation balance, scheduling etc. are being carried out on control area basis by State Load Despatch Centres (SLDCs). At the regional level, the function is being carried out by Regional Load Despatch Centres (RLDCs). The National Load Despatch Centre (NLDC) is the apex body at National level which coordinates the load dispatch functions with RLDCs and neighboring countries.

4.2.

The national installed generating capacity as on 30th April 2012 is of the order of 201 GW with nearly 1800 generating units. The power system in India has been demarcated into smaller control areas for monitoring and control. A control area has its own generator or group of generators and it is responsible for its own load and scheduled interchange with neighboring areas. Each control area contains different kinds of uncertainties and various disturbances due to increased complexity, changing power system structure like sudden load/generation loss. Because of interconnectivity of control areas through tie lines any sudden change in load or generation affects the entire system. Therefore, monitoring of frequency response characteristics (FRC) at control area level is most suitable as it gives a good idea about the frequency response of the Control Area.

4.3.

Annexure-1 gives the details of the Control Areas under jurisdiction of each RLDC/NLDC.

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5. Procedure to Calculate Frequency Response Characteristics

5.1.

Frequency Response Characteristics (FRC) computations

Frequency Response Characteristics (FRC) will be computed for all events involving a sudden 1000 MW or more load/generation loss or a step change in frequency by 0.50 Hz shall be worked out by NLDC, RLDCs and SLDCs to compute each interconnection/region/control area‟s FRC. Currently, India has large number of 600/660 MW units and this is rapidly increasing. Tripping of one 600/660 MW unit is fairly common. The present maximum size generating unit is 800 MW (UMPP Mundra) and very soon there would be units of 1000 MW size i.e., after commissioning of Kudankulam Nuclear Power Station. Hence 1000 MW change is expected to be an optimal one for the purpose monitoring FRC. Any lower value would lead to more efforts at LDC without commensurate benefit. The following steps would be followed for computation FRC (a) After every event involving a sudden 1000 MW or more load/generation loss or a step change in frequency by 0.5 Hz, NLDC would get the PMUs frequency data wherever available, from all the RLDCs. NLDC would also get the exact quantum of load/generation lost from the RLDC of the affected region. (b) NLDC would plot the frequency graph and determine the initial frequency, minimum/maximum frequency, settling frequency and time points (points A, C and B of the Figure-5). Accordingly frequency difference points & corresponding time to be used for FRC calculations would be informed to all RLDCs. (c) NLDC would also work out region wise, NEW grid, Southern grid and Neighboring countries (Bhutan and Nepal) FRC (Format FRC-3) based on 10 second or 30 second Historical Data Recording (HDR) data available at NLDC and inform all RLDCs as well as post the same on its website within three (3) working days. RLDCs would inform the SLDCs in their region. (d) RLDCs shall also work out each control area wise FRC (Format FRC-2) based on HDR data available at RLDCs and post the same on its website within six (6) working days.

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(e) All the SLDCs shall work out FRC for all the intrastate entities for events indicated by the Regional Load Despatch Centres based on the HDR data available at their respective SLDCs and post the same on its website within six (6) working days. (Format FRC-1). (f) In cases where SLDCs do not have any website, the FRC (FRC-1) would be sent to RLDC within one week. 5.2.

Input data for FRC: i.

The data for Frequency Response Characteristic Calculations should be taken from the real time telemetered data recorded by the SCADA systems installed at Control Areas / Regional Load Despatch Centres / National Load Despatch Centre.

ii.

All control area interconnection (tie) points are expected to be equipped to telemeter MW power flow to respective control center.

iii.

Bad quality of data would be flagged / mentioned by the control centre and reasonable assumptions made for FRC computation. Details of these may be mentioned.

iv.

In cases of load/generation loss through action of System Protection Schemes (SPS) the exact quantum must be determined so that the FRC computations are correct. SLDCs/RLDCs/NLDC must therefore make efforts to get telemetered data of all such SPS locations.

5.3.

Instructions for computation of FRC: The FRC -1 is the Control Area Frequency Response Characteristic Survey form. A Sample frequency chart is shown in Figure-5 with points A, B, and C labeled. Figure-5 depicts a typical frequency excursion caused by a loss of a

large

generator

on

an

Interconnection.

Point

A denotes

the

interconnection frequency immediately before the disturbance. Point B represents the Interconnection frequency at the point immediately after the

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frequency stabilizes due to governor action but before the contingent control area takes any corrective actions, automatic or manual. Point C represents the interconnection frequency at its maximum deviation due to the loss of rotating kinetic energy from the interconnection.

Frequency Response

50.1

Frequency (Hz)

50

A = 49.984

49.9 49.8 49.7 49.6

B = 49.546

49.5 49.4 49.3

C = 49.302

49.2 1

6

11

16

21

26

31

36

Time (Sec)

Figure-5: Frequency excursion caused by a loss of a large generator Guidelines to work out Frequency Response Characteristics of Control Area (FRC - 1) are as follows (Refer FRC-1):Actual net interchange of the control area immediately before the disturbance Step-1

(Point - A) = PA. Sign convention for net power imported into a CONTROL AREA is positive (+) and net power exported out of a control area is negative (-). Actual net interchange of the control area immediately after the disturbance (Point -

Step-2

B) = PB. Use the same sign Convention as Step-1. The Net interchange of the CONTROL AREA = (PB - PA). For a disturbance that

Step-3

causes the frequency to decrease, this value should ideally be negative except for the contingent CONTROL AREA, in which case it is positive and conversely.

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If the control area has suffered the loss, then Load or generation lost by the control Step -4

area = PL. Otherwise, the loss (PL) is zero. Sign convention for Load Loss is negative (-) and Generation Loss positive (+).

Step-5

The Control Area Response = ∆P = (PB - PA) - PL

Step -6

The Frequency immediately before the disturbance = fA.

Step -7

The Frequency immediately after the disturbance = fB.

Step -8

Change in Interconnection Frequency from Point A to Point B = ∆f = (fB - fA)

Step -9

Frequency Response Characteristic (FRC) of the Control Area = ∆P/∆f

Step -10

Net Demand met by Control Area before the disturbance = PDEMAND

Step -11

Internal Generation of the Control Area before the disturbance = (PDEMAND-PA).

Step -12

Ideal Load Response assuming 4% per Hz = PIdeal Load = (0.04* PDEMAND). Assuming 5% droop means 5% (2.5 Hz) change in frequency causes 100% change in

Step -13

generation. So for 1 Hz change in frequency requires (1/2.5)*100% change in generation. Ideal generator Response = PIdeal gen = 0.4* (PDEMAND - PA).

Step -14

Step -15

Composite Ideal response = Pcomposite = (PIdeal Load + PIdeal gen) Percentage Ideal response = ((∆P/∆f)*100/ Pcomposite)

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5.4.

FRC Review

The FRC data received shall be reviewed for uniformity, completeness, and compliance to the instructions. The frequency response for the control areas shall be reviewed periodically (Quarterly or Half-yearly). National Load Despatch Centre shall submit the Frequency Response Characteristics of Control areas/Regions Quarterly to the Commission. i.

NLDC would assess the composite FRC for the five regional grids, Bhutan and Nepal.

ii.

RLDCs would assess the composite FRC for the Regional Entity control areas.

iii.

SLDCs would assess the composite FRC for intra state entity control areas.

5.5.

Duration of submission of Reports

BHUTAN NLDC Within three (3) working days of the incident.

NLDC NEPAL

Within Six (6) working days of the incident.

RLDCs

BANGALDESH

SLDC shall give FRC report within six (6) working days of the incident.

SLDC-1

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6. LIMITING FACTORS The factors affecting the accuracy of the calculation of the FRC are: a) Identification of the exact point of disturbance and interpretation of the time window to be measured. “Immediately before” and “Immediately after” are subject to interpretation. b) Limitation of the sampling rate of the data recorded by the SCADA system (normally 10 second samples are available in the SCADA). At times, there is also a loss in part of the telemetered data due to various reasons and this causes inaccuracies. Moreover some of the data points are received through ICCP from Sub-LDC/SLDC to RSCC which imposes an additional time delay. c) A large number of events must be captured and subjected to statistical treatment before a reasonably accurate figure can be obtained. This is also necessary to rule out the impact of high variability of the load. d) Both load and generation are continuously changing naturally. e) System size, generator loading, losses, distance of generators from the point of loss, load composition, number of generators in service at the time of the incident, type of generation, governor action, time of day, season and interconnections with the neighbors significantly influence FRC calculations. f) SPS, Under frequency relays (UFR) and df/dt relays are installed in all the regions to take care of contingencies. Such actions are in millisecond timeframe and are the first to provide relief by way of load shedding.

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STATE LOAD DESPATCH CENTRE

FRC -1

FREQUENCY RESPONSE CHARACTERISTIC (FRC) OF CONTROL AREA DATE:

CONTROL AREA:

EVENT :

REGION: Loss of generation (+)/ Load (-) in MW Dimension

Particulars 1. Actual net interchange immediately before the disturbance

PA

MW

2. Actual net interchange immediately after the disturbance

PB

MW

3. Change in Net interchange

(PB - PA)

MW

4. Generation Loss (+) / Load Throw off (-) during the Event

PL

MW

5. Control Area Response (∆P )

(PB - PA) - PL

MW

6. Frequency before the Event

fA

HZ

7. Frequency after the Event

fB

HZ

8. Change in Frequency (∆f )

(fB - fA)

HZ

9. Frequency Response Characteristic (FRC)

∆P/∆f

MW/HZ

10. Net System Demand met before the Event

PDEM

MW

11. Internal Generation before the Event (Pgen)

(PDEM - PA)

MW

12. Ideal load response assuming 4% per Hz (PIdeal Load)

0.04* PDEM

MW/Hz

13. Ideal generator response assuming 5% droop (PIdeal gen)

0.40* (PDEM - PA)

MW/Hz

14. Composite ideal response (Pcomposite)

PIdeal Load + PIdeal gen

Mw/Hz

15. Percentage of ideal response

(∆P/∆f)*100/ Pcomposite

%

TOTAL STATE

INTRA STATE ENTITY-1

NOTES : 1. Net Power delivered out of a Control Area (Export) is negative (-). 2. Net Power Import of the Control Area (Import) is positive (+).

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INTRA STATE ENTITY-2


FRC -2

REGIONAL LOAD DESPATCH CENTRE FREQUENCY RESPONSE CHARACTERISTIC (FRC) OF REGION DATE: EVENT : Dimension

Particulars 1. Actual net interchange immediately before the disturbance (PA)

MW

2. Actual net interchange immediately after the disturbance (PB)

MW

3. Change in Net interchange (PB - PA)

MW

4. Generation Loss (+) / Load Throw off (-) during the Event (PL)

MW

5. Control Area Response (∆P =(PB - PA) - PL )

MW

6. Frequency before the Event (FA)

HZ

7. Frequency after the Event (fB)

HZ

8. Change in Frequency (∆f = fB - fA)

HZ

9. Frequency Response Characteristic (FRC = ∆P/∆f)

MW/HZ

10. Net System Demand met before the Event (PDEM)

MW

11. Internal Generation before the Event (Pgen = PDEM - PA)

MW

12. Ideal load response assuming 4% per Hz (PIdeal Load =0.04* PDEM)

MW/Hz

13. Ideal generator response assuming 5% droop (PIdeal gen =0.40* (PDEM - PA))

MW/Hz

14. Composite ideal response (Pcomposite) =PIdeal Load + PIdeal gen

Mw/Hz

15. Percentage of ideal response = ((∆P/∆f)*100/ Pcomposite)

%

Region

Control Area-1

Control Area-2

Loss of generation (+)/ Load (-) in MW Control Control Control Control Area-3 Area-4 Area-5 Area-6

NOTES : 1. Net Power delivered out of the Region (Export) is negative (-). 2. Net Power received into the Region (Import) is positive (+).

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FRC -3 NATIONAL LOAD DESPATCH CENTRE FREQUENCY RESPONSE CHARACTERISTICS DATE & Time of the Event: EVENT ID:

EVENT :

; Loss of Generation(+)/Load(-) in MW Dimension

Particulars 1. Actual net interchange immediately before the disturbance (PA)

MW

2. Actual net interchange immediately after the disturbance (PB)

MW

3. Change in Net interchange (PB - PA)

MW

4. Generation Loss (+) / Load Throw off (-) during the Event (PL)

MW

5. Control Area Response (∆P =(PB - PA) - PL )

MW

6. Frequency before the Event (fA)

HZ

7. Frequency after the Event (fB)

HZ

8. Change in Frequency (∆f = fB - fA)

HZ

9. Frequency Response Characteristic (FRC = ∆P/∆f)

MW/HZ

10. Net System Demand met before the Event (PDEM)

MW

11. Internal Generation before the Event (Pgen = PDEM - PA)

MW

12. Ideal load response assuming 4% per Hz (PIdeal Load =0.04* PDEM)

MW/Hz

13. Ideal generator response assuming 5% droop (PIdeal gen =0.40* (PDEM-PA))

MW/Hz

14. Composite ideal response (Pcomposite) =PIdeal Load + PIdeal gen

Mw/Hz

15. Percentage of ideal response = ((∆P/∆f)*100/ Pcomposite)

%

INDIA

NEW GRID

SR GRID

NR

ER

WR

NOTES : 1. Net Power delivered out of the Region (Export) is negative (-). 2. Net Power received into the Region (Import) is positive (+).

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NER

BHUTAN


Annexure-I A. Regions under Jurisdiction of NLDC: (As on July-2012) Northern Region, Eastern Region, Western Region, Northeastern Region, Southern Region, Bhutan and Nepal.

B. Control Areas Under Jurisdiction of RLDCs Control Areas Under Jurisdiction of RLDCs 31 Salal

NRLDC

10

Punjab Haryana Rajastan Delhi Uttar Pradesh Uttarkhand Chandigarh Himachal Pradesh Jammu & Kashmir Singrauli

11

Rihand-1

41 Koteswar 42 Jhakri

12

Rihand-2

43 BBMB complex

13 14 15 16 17 18 19 20 21 22 23 24 25

Dadri-1 Dadri NCR Unchahar Dadri-Gas Anta Auraiyya Badarpur Tanda Faridabad Gas NAPS RAPP-B RAPP-C RAPP-A

44 Dehar 45 Pong

26

Jhajjar

27 28 29 30

Sree Cement Chamera-1 Chamera-2 Uri-1

11 VSTPS Stage-II 12 SIPAT Stage-I 13 SIPAT Stage-II 14 NSPCL 15 JPL,TAMNAR

1 2 3 4 5 6 7 8 9

NLDC

32 33 34 35 36 37 38

Bairasiul Tanakpur Dhauliganga Dulhasti Sewa-II AD Hydro Karcham Wangtoo

16 Lanco Pathadi 17 KAWAS 18 GANDHAR 19 SSP 20 CGPL 21 RGPPL 22 TAPS 23 KAPP

39 Malana-2

ERLDC

40 Tehri

WRLDC 1 2 3 4 5 6 7 8 9 10

Gujarat Maharastha Madhya Pradesh Chattisgarh Goa DD DNH KSTPS Stage-I KSTPS Stage-II

6

Nagaland

7 8 9 10 11 12 13

Tripura AGBPP AGTPP Khandong Kopili Doyang RHEP

14

Loktak

1 2

Bihar Jharkhand

1

Andhra Pradesh

3

DVC

2

Karnataka

4 5 6

Orissa

3

Kerala

West Bengal FSTPP* KhSTPP1 KhSTPP2 TSTPS-I TSTPS-II (SR) MPL Sterlite Teesta RHEP THPS CHPS

4 5 6 7 8 9 10 11

Tamilnadu Puducherry Ramagundam-NTPC Simhadri-NTPC Neyveli-II Neyveli-I Exp Kaiga MAPS

7 8 9 10 11 12 13 14 15 16

VSTPS Stage-I

SRLDC

NERLDC 1 2 3 4 5

Arunachal Pradesh Assam Manipur Meghalaya Mizoram


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Annexure-2 Illustrative Example for Calculation of FRC The example explains about how to calculate Frequency Response Characteristics of a Region. In this example Southern Region is taken for Illustrative Purpose only. Event: At 1748 hours on 01st May 2012, Pole-1 of Talcher–Kolar HVDC bipole got blocked due to HVDC line fault. The bipole was carrying 1976 MW from the NEW grid (Talcher) to Southern grid (Kolar). The Pole-2 came on Ground return mode and power came down to 125 MW. During this tripping, SPS operated at Kolar end resulting in load throw off or load loss of 990MW in Southern region i.e.., Andhra Pradesh – 223 MW, Karnataka – 350 MW, Kerala- 0 MW, Tamilnadu – 417 MW and Pondicherry- 0 MW.

50.4

50.2

Point-A

50

Point-B 49.8

Point-C 49.6

49.4

49.2

49 17:44:10 17:45:36 17:47:02 17:48:29 17:49:55 17:51:22 17:52:48 17:54:14 17:55:41 17:57:07 17:58:34

Figure-A: Frequency of Southern Region during Tripping of Talcher-Kolar Pole-1

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From the Figure-A, it can be noted that, Start Time (Point-A) = 17:48:20; Frequency = fA =49.74 Hz. End Time (Point-B) = 17:51:10; Frequency = fB = 49.26 Hz Sign Conventions: 

Sign convention for net power into a Control Area (Import) is positive (+)



Sign convention net power out of a Control Area (Export) is negative (-).



Sign convention for Load Loss/Load Throw off is negative (-)



Sign convention for Generation Loss positive (+).

TIME

SR FREQ

T-K FLOW

17:47:30 17:47:40 17:47:50 17:48:00 17:48:10 17:48:20 17:48:30 17:48:40 17:48:50 17:49:00 17:49:10 17:49:20 17:49:30 17:49:40 17:49:50 17:50:00 17:50:10 17:50:20 17:50:30 17:50:40 17:50:50 17:51:00 17:51:10 17:51:20 17:51:30 17:51:40 17:51:50 17:52:00 17:52:10 17:52:20 17:52:30

49.75976563 49.73535156 49.73535156 49.73535156 49.79589844 49.73535156 49.77148438 49.80761719 49.83203125 49.8203125 49.79589844 49.75976563 49.69824219 49.39453125 49.20019531 49.17578125 49.12695313 49.12695313 49.10253906 49.10253906 49.13964844 49.21191406 49.26074219 49.2734375 49.296875 49.30957031 49.34570313 49.37011719 49.40722656 49.44335938 49.46777344

1979 1979 1979 1976 1976 1976 1197 1197 1208 1220 1220 1220 1026 1026 821 125 125 114 114 117 117 117 117 121 121 117 117 117 117 123 123

GAZUWAKA FLOW 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 109 144 144 144 144 144 144 144 144 144 144

BHADRWATI

SR Import

701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 701 705 705 705 705 705 701 701 701 701 701 701

2789 2789 2789 2786 2786 2786 2007 2007 2018 2030 2030 2030 1836 1836 1631 935 935 925 925 927 931 966 966 970 970 962 962 962 962 968 968

Point-A

Point-B

Point-C

Table-2: SCADA data for Talcher-Kolar Pole-2 tripping on 01.05.2012 NLDC


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Step -1

Actual net interchange of Southern Region immediately before the disturbance i.e., Point – A (start time = 17:48:20) = PA = 2786 MW.

Step -2

Actual net interchange of Southern Region immediately after the disturbance i.e., at Point – B (End time = 17:51:10) = PB = 966 MW.

Step -3

The Net interchange of Southern Region= (PB - PA) = 966-2786 = -1820 MW.

Step -4

Due to SPS action there was a load throw off of 990 MW. So, Load throw off of Southern Region = PL = -990 MW.

Step -5

Southern Region Response = ∆P = (PB - PA) - PL = (966-2786) - (-990) = -830 MW.

Step -6

The Frequency immediately before the disturbance = fA =49.74 Hz.

Step -7

The Frequency immediately after the disturbance = fB = 49.26 Hz.

Step -8

Change in Frequency from Point A to Point B = ∆f = (fB - fA) =(49.26-49.74) = -0.48 Hz.

Step -9

Frequency Response Characteristic (FRC) of Southern Region = ∆P/∆f = (-830)/(-0.48) =1729 MW/Hz

Step -10

Net Demand met by Southern Region before the disturbance i.e., Point – A (start time = 17:48:20) = PDEMAND = 23728 MW.

Step -11

Internal Generation of Southern Region before the disturbance i.e., at Point – B (End time = 17:51:10) = PDEMAND - PA. = (23728-2786) = 20942MW.

Step -12

Ideal Load Response of Southern Region assuming 4% per Hz = PIdeal

Load

= (0.04* 23728) =949

MW/Hz. Step -13

Assuming 5% droop means 5%; Ideal generators Response of Southern Region = PIdeal gen = 0.4* (23728-2786) = 0.4*20942 = 8377 MW/Hz.

Step -14

Composite Ideal response = Pcomposite = (PIdeal Load + PIdeal gen)= (949.1+8376.8) = 9326 MW/Hz.

Step -15

Percentage Ideal response = ((∆P/∆f)*100/ Pcomposite) = ((-830/-0.48)*100/ 9326) =18.5%.

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Step by step procedure shown above is summarized in the Table-3: Dimension

Particulars 1. Actual net interchange immediately before the disturbance

PA

MW

2. Actual net interchange immediately after the disturbance

PB

MW

3. Change in Net interchange

(PB - PA)

MW

4. Generation Loss (+) / Load Throw off (-) during the Event

PL

MW

5. Control Area Response (∆P )

(PB - PA) - PL

MW

6. Frequency before the Event

fA

HZ

7. Frequency after the Event

fB

HZ

8. Change in Frequency (∆f )

(fB - fA)

HZ

9. Frequency Response Characteristic (FRC)

∆P/∆f

MW/HZ

10. Net System Demand met before the Event

PDEM

MW

11. Internal Generation before the Event (Pgen)

(PDEM - PA)

MW

12. Ideal load response assuming 4% per Hz (PIdeal Load)

0.04* PDEM

MW/Hz

13. Ideal generator response assuming 5% droop (PIdeal gen)

0.40* (PDEM - PA)

MW/Hz

14. Composite ideal response (Pcomposite)

PIdeal Load + PIdeal gen

Mw/Hz

15. Percentage of ideal response

(∆P/∆f)*100/ Pcomposite

%

Southern Region

2786 966 -1820 -990 -830 49.74 49.26 -0.48 1729 23728 20942 949 8377 9326 18.5%

Table-3: Summary of FRC of Southern Region for Talcher-Kolar Pole-1 tripping

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References: 1. http://www.cercind.gov.in/Regulations/Signed-IEGC.pdf,

Central

Electricity

Regulatory Commission (Indian Electricity Grid Code) Regulations, 2010. 2. http://www.wecc.biz/Standards/Development/wecc0044/Shared%20Documents/ FRR%20Report%203-10-09.doc,

“White

Paper

on

Frequency

Response

Standard,” by Reserve Issues Task Force, November 24, 2005. 3. http://www.nerc.com/docs/oc/rs/Frequency_Response_White_Paper.pdf

,

“Frequency Response Standard White Paper,” by Frequency Task Force of the NERC Resources Subcommittee, April 6, 2004. 4. http://www.nerc.com/docs/standards/sar/opman_12-13Mar08_Frequency ResponseCharacteristicSurveyTrainingDocument.pdf,

“Frequency

Response

Characteristic Survey Training Document,” January 1, 1989. 5. http://www.nrldc.org/docs/documents/Papers/frc.pdf , S. K. Soonee and S. C. Saxena, “Frequency Response Characteristics of an Interconnected Power System-A Case Study of Regional Grids in India,” 6th International R&D Conference on Sustainable Development of Water and Energy Resources-Needs and Challenges, Feb 13-16, 2007, Lucknow, Uttar Pradesh, India. 6. http://stage-icourseplayer.360training.com/courses/Course100718/nerc_cert_ prep_sco2/content/pdf/NERC_Hz_Training.pdf,

“NERC Training Document

Understand and Calculate Frequency Response,” by NERC Training Resources Working Group, February 20, 2003. 7. “Power System Stability and Control,” Page No: 581-623 by Prabha Kundur. 8. http://consultkirby.com/files/TM2003-41_Freq_Control.pdf, “Frequency Control Concerns In The North American Electric Power System,” B. J. Kirby, J. Dyer, C. Martinez, Dr. Rahmat A. Shoureshi, R. Guttromson and J. Dagle, December 2002.

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ANNEXURE III

Surge Impedance Loading(SIL) of Transmission Lines

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Annexure IV - Thermal Loading

Extracts from CEA ‘Manual on Transmission Planning Criteria- Jan 2013’

NLDC


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Annexure IV - Thermal Loading

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July 2013-Rev 0

Annexure V - NLDC Advisory on High Capacity 765kV Corridor

qrcrEfr€€d sfrqterq orzciterq ftltrrts Fratfrs +t Wf Frftrds urw rr6rq6 dq-fr)

POWER SYSTEM OPERATION CORPORATION LIMITED (A wholly owned subsidiary of POVI/ERGRID)

dfiq

ffiffrl-d

r{

q-trq-iT (rd (rtrqr, o-arEqr sil-q, orqlq-o : fr - 9, EgE n-m - 110 016 Registered & Gorporate Office : B - 9, Qutab lnstitutionalArea, Katwaria Sarai, New Delhi - 110 016 Website: www.nldc.in, www.nldcindia in, Tel. : 011-26536832,26524522,Fax:011-26524525. 26536901

NLDC/765 kV

Dated:8th May 2013

Sub: Operation of 765 kV transmission system in the NEW grid in the coming months Reliable operation of the high capacity corridor from Sipat in Chhattisgarh

to Moga in Punjab over the

755 kV Sipat-Bilaspur-Seoni-Bina-Gwalior-Agra-Jhatikara-Bhiwani-Moga route is very important in the coming months, particularly up to the end of September when Northern Region demand is expected to be high. This high capacity corridor would no doubt enhance the transfer capability from the West to North direction; however outage of any of the following links would significantly impact the transfer capability.

o o o o

765 kV Agra-Jhatikara One of the 765/400 kV 1500 MVA ICT at Agra 765 kV Gwalior-Agra one circuit 765 kV Bina-Gwalior one circuit

A self- contained note on the subject along with the details of the actions to be taken by the different agencies under varied conditions is enclosed.

Following actions are expected from RLDCs/NLDC:

i. ii.

Sensitizing stakeholders to the nature of the above operation of 765 kV corridors.

Taking

all precautions both for planned and emergency outages of the above sections including

arrangements for quick curtailment of transactions and manual actions for feeder opening.

iii.

Monitoring the quantum of loads wired for SPS action and taking up the issue of optimizing it appropriately.

iv.

Voltage control through suitable actions

of

reactor switching, reactive power absorption by

generators, line switching.

v.

Handling special situations such as load crash. The following actions are expected from POWERGRID end:

i.

Preventive maintenance and minimizing both planned and emergency outages on the above corridor (lines as well as bay shutdowns) so as to improve reliability as well as enhanced transfer capability.

ii.

Ensuring that overvoltage settings on the system are properly graded both in terms of magnitude and

iii.

time delay. Details of settings to be forwarded to NLDC. Commissioning automatic tripping of the 22O kV Gwalior (PG)-Malanpur (PG) D/C from Gwalior(PG) end in case of tripping of both circuits of 765 kV Gwalior-Agra and automatic tripping of the 22O kV Page 1 of 8

NLDC

tri

J'qf q-druGrid d National TdtrdProcedures for Operating Save Energy 76for of Benefit 198 of Self and Nation

July 2013-Rev 0


Gwalior(F,G)-Gwalior(MP) D/C frqm Gwalior( This feature would generally be Qf i Western Region load acting as a drag on

) end in case both the 765 kV Bina-Gwalior lines trip. from June to September and is to avoid a situation of Region in case of any tripping.

In situ teSting of System Protecfion (SPS) at Agra(PG) and Gwalior(PG) and continuously keeping it armed and healthy conflition. Sensitizing the operators at the different 765 substations on the strategic importance of the 765 kV network and the availability of re4l time data a the RLDCs/NLDC.

tv.

V.

Following agtions are required at RQgional Powe Committee level. i)

Sensitizing stakeholders to the strptegic im

ii)

Ensuring

that the outage plan is properly

of 755 kV corridors. so that the system is able to operate in

a

reliable fqphion. iii) Monitoring

the relief obtained

through constituents for any shortfall in loFd relief. iv) Ensure that all trippings in the trBnsmission

kV Gwalior-Agra SPS actions and taking up with

and the lessons learned and actions taken monitored.

inated across all utilities and its implementation

v)

Ensure thpt all defence plans sucfr as Under

are discussed at the Protection Committee level

uency Load Shedding (UFLS) scheme, df/dt and

SPS

are in plaqe.

Encl: as above

(V. K. Agrawal) Executive Director, NLDC Copy for kind information and necetsary action 1.)

Mep ber Secreta ry N RPC/WRPC/ERPC/SR

2l

ED (PS), POWERGRID, Gurgqon

3)

ED (NR-1), POWERGRID, Nery Delhi

4l ED (NVR-ll), POWERGRID, Vaflodara s)

ED (NVR-|), POWERGRID, Nagpur

6)

ED SRLDC, Bengaluru

7l

G

M WRLDC/N RLDC/ERLDC/]N

E

RLDC

Copy for kind information to:

8) Member (GO & D), CEA, NeW Delhi 9) CMD POWERGRTD 10) Director (Operations), POW$RG RlD, 11.) CEO POSOCO

Page 2 of 8

NLDC


July 2013-Rev 0


Power System Operation Corporation Limited National Load Despatch Centre New Delhi 8th May 2013 Sub: Operation of 765 kV transmission system in the NEW Grid In March 2013, the Bina‐Gwalior‐Agra section was upgraded to 765 kV level from the earlier 400 kV. On 29th April 2013, the 765 kV Agra‐Jhatikara line was commissioned. These developments have resulted in a 1600 kilometres stretch of high capacity 765 kV transmission highway from Sipat in Chhattisgarh to Moga in Punjab over Sipat‐Bilaspur‐Seoni‐Bina‐Gwalior‐Agra‐Jhatikara‐Bhiwani‐Moga route. 765 kV Sasan‐Satna‐Bina D/C is another vital infeed to Bina. This is an important transition that the entire grid is passing through. This high capacity corridor is expected to be loaded heavily during the June to September period when there is heavy power demand in the Northern Region due to weather beating and agricultural loads while the demand in Western Region is expected to be low. Secure operation of the system would become very important under these conditions. The following aspects would become important under these conditions: 1) Operational planning a. Evaluation of transfer capability of the network. b. Outage planning of the 765 kV high capacity corridor c. Over‐voltage settings of the 765 kV lines d. Minimizing forced or emergency outages e. Operation of underlying 400 kV and 220 kV network f. Operation of System Protection Scheme (SPS) during contingencies and settings thereof. g. Availability of real time data at WRLDC/NRLDC and NLDC. 2) Real time operation a. Handling emergency outages b. Curtailment of transactions c. Manual opening of feeders in case of contingency d. Voltage control e. Handling special situations such as load crash etc. in Northern Region Page 3 of 8

NLDC


July 2013-Rev 0


A. Operational Planning: i) Transfer capability in the West to North direction: The transfer capability has been assessed based on the network conditions in May 2013 and would be uploaded on NLDC website as well as periodically revised based on the system conditions. The Total Transfer Capability (TTC) in the West to North direction is expected to be of the order of 5700 MW which is considering the availability of all main 765 kV and 400 kV transmission elements and includes 1500 MW on the dedicated APL Mundra‐Mohindergarh HVDC bipole. Loading on the following important corridors needs close monitoring: 1) 765 kV Sipat‐Bilaspur Pooling station D/C: 2) 765 kV Bilaspur Pooling station‐Seoni D/C: 3) 765 kV Seoni‐Bina : 4) 765 kV Bina‐Gwalior D/C : 5) 765 kV Gwalior‐Agra D/C : 6) 765 kV Agra‐Jhatikara : 7) 765 kV Jhatikara‐Bhiwani : 8) 765 kV Bhiwani‐Moga : 9) 765 kV Sasan‐Satna D/C : 10) 765 kV Satna‐Bina D/C : 11) 765 kV Fatehpur‐Agra D/C : 12) 765/400 kV, 2 x 1500 MVA ICTs at Agra : There would be a reduction of transfer capability in case of outage of any one of the following sections: •

765 kV Agra‐Jhatikara

•

One of the 765/400 kV 1500 MVA ICT at Agra

•

765 kV Gwalior‐Agra one circuit

•

765 kV Bina‐Gwalior one circuit

Considering that studies involve various assumptions, there is a need for having adequate Transmission Reliability Margin (TRM) to take care of these uncertainties and accordingly a margin of 500 MW is being kept on WR‐NR corridor and 800‐1000 MW for import by NR as a whole. ii) Outage planning of the 765 kV transmission corridor: As the 765 kV Bina‐Gwalior‐Agra‐Jhatikara lines and the 765/400 kV ICTs at Agra have a major impact on security of the grid as well as economy transfers between the regions; outages on the above section need to be planned carefully after discussion at the different Regional Power Committee (RPC)/National Page 4 of 8

NLDC


July 2013-Rev 0


Power Committee (NPC) level. In cases of unforeseen changes in the maintenance program or any urgent requirement of outages, at least 48 hour notice needs to be given to RLDCs/NLDC by POWERGRID so that the outage is co‐ordinated and the grid security as well as open access transactions is regulated in a proper fashion. It is also important that 765 kV bay shutdowns at all the intermediate sub‐stations are coordinated so that there is no unintended tripping on this account. This is important as the number of 765 kV elements in many substations are less in number and ensuring that at least two parallel paths are available between the two 765 kV buses under all conditions becomes very important. In many of the trunk inter‐regional lines as well as important intra‐regional lines, there are a number of agencies such as State Transmission Utilities (STUs), Generating Companies who are responsible for line switching in/out who need to be sensitized on the need for quick execution of line switching instructions issued by RLDCs/NLDC and avoid any prolonged outage of the line sections. Availability of the 400 kV and 220 kV parallel network between Western and Northern Region would be important. iii) Over‐voltage settings of the 765 kV lines: POWERGRID might also ensure that the overvoltage settings of the 765 kV lines in the entire corridor above are properly graded in terms of magnitude as well as time delay so as to obviate inadvertent tripping on account of high voltage. Confirmation in this regard may please be forwarded by POWERGRID to NLDC along with the over‐voltage settings on each 765 kV line. iv) Minimizing forced or emergency outages: Considering the heavy power flow on the above sections, it is important that the monitoring of these lines through thermo vision scanning as well as condition monitoring of equipment at the substation level is intensified so that forced or emergency outages are minimized. POWERGRID may take actions accordingly. v) Underlying 400 kV and 220 kV network: The 765 kV Bina‐Gwalior‐Agra section has the following 220 kV section running in parallel and is the first instance of the 765 kV and 220 kV sections running in parallel without any 400 kV system. •

220 kV Bina(MP)‐Gwalior(MP) D/C

•

220 kV Gwalior (MP)‐Gwalior(PG) D/C

•

220 kV Gwalior (PG)‐Malanpur (MP) D/C Page 5 of 8

NLDC


July 2013-Rev 0


•

220 kV Malanpur(MP)‐Auraiya (NTPC) and

•

220 kV Malanpur (MP)‐Mehgaon (MP)‐Auraiya (NTPC)

The power flow in 220 kV section is less when the 765 kV system is running in parallel. Even when a single 765 kV line on the Bina‐Gwalior‐Agra section trips, the parallel line takes 80‐85% of the load and there is not much increase at the 220 kV level. However outage of both the 765 kV lines under heavy power flow conditions would lead to cascade outage of the appropriate 220 kV section. The following two options were analyzed. •

Keeping the 220 kV system in radial mode only viz. feeding Gwalior (MP) load from Bina (MP) and Malanpur (MP)/Mehgaon(MP) loads from Gwalior(PG) OR

•

Tripping the 220 kV Gwalior (PG)‐Gwalior (MP) D/C from Gwalior (PG) end in case the 765 kV Bina‐Gwalior D/C both circuits trip AND Tripping the 220 kV Gwalior (PG)‐Malanpur (PG) D/C from Gwalior (PG) end in case the 765 kV Gwalior‐Agra D/C trips.

Considering the overall reliability of the system and the voltage profile at Gwalior/Malanpur, it is recommended to operate the 220 kV system in parallel with the 765 kV system and go for the second option of automatic tripping of the respective 220 kV lines indicated above. The automatic tripping option would be required to ensure that in the rare eventuality of loss of West‐North corridor, the Western Region load at Gwalior/Malanpur should not act as a drag on Northern Region. vi) System Protection Scheme (SPS) settings at Agra and Gwalior and its testing: The present settings are ‘1000 MW each on 765 kV Gwalior‐Agra D/C line OR 1500 MW on S/C 765 kV Gwalior to Agra line leading to SPS action of load shedding in Northern Region. These settings would have to be optimized taking care of grid security as well as facilitating economy interchange. Further the SPS needs to be tested periodically and the identified load relief feeders should be telemetered to the NRLDC/WRLDC/NLDC at the earliest. vii) Availability of real time data at RLDCs/NLDC: Since power flow on the corridor is expected to be high, it is important that the monitoring at RLDCs/NLDC is effective. This is possible only is the real time data (both analog as well as digital) is available at the RLDCs. Page 6 of 8

NLDC


July 2013-Rev 0


B.

Real time operation: i)

Handling emergency outages:

In the rare eventuality that an emergency occurs on the 765 kV Bina‐Gwalior‐Agra‐Jhatikara corridor or the 765/400 kV Agra ICTs and when there is heavy transfer on the above corridor, the following actions might be required: o Imposition of congestion charge. o Curtailment of Short Term Open Access (STOA) as well as collective transactions. If required, even long term transactions from Sasan and CGPL Mundra to Northern Region would have to be curtailed as nearly 2500 MW reduction in power transfer in the West to North direction would be required. o Rescheduling of generation, particularly at hydro stations and costlier generation in Northern region needs to be carried out. o After the physical flows reduce in the West to North direction, the 765 kV affected line may be opened. Subsequent to this, a few 765 kV lines in the Western region would also need to be opened to control voltages (such as one circuit of 765 kV Satna‐Bina or 765 kV Seoni‐Bina and Bina‐Gwalior if Agra‐Gwalior section outage is there). o Under normal situation this process itself would take some time and this aspect needs to be kept in mind while permitting even planned shutdowns and reduction of TTC. o Before restoration of the circuit the above steps need to be repeated in the reverse order. ii) Curtailment of transactions:

iii)

The information system between the different agencies involved needs to be taken care of so that information regarding curtailments is disseminated to all concerned and physical actions for rescheduling generation or load is taken care of. Manual opening of feeders in case of contingency:

Pending the availability of any automatic defense plans or Grid Security Expert System (GSES), NRLDC would have a list of radial feeders with significant quantum of load which could be manually opened readily in case of contingencies under heavy transfers from Western Region to Northern Region. This would also help in case SPS does not provide adequate relief. Page 7 of 8

NLDC


July 2013-Rev 0


iv)

Voltage control:

v)

With 765 kV high capacity corridors in operation, the voltage profile would significantly depend on the line loadings. In case the loading is low, high voltages would be experienced. POWERGRID and other utilities are advised to ensure that all the bus reactors are available at both 765 kV and 400 kV level. RLDCs are advised to closely monitor the power plants reactive power absorption under such conditions. The HVDC power order settings and 765/400 kV transformer tap changing may also be employed to control the voltage. In case lightly loaded lines are opened to control high voltage then they must be restored at the earliest opportunity. In many instances it is seen that the line reactor of the line which is kept off is used as bus reactor. In case the line needs to be urgently taken into service, the process gets delayed as additional switching operations are required. Hence the line reactor of a line which is kept off might be taken into service as bus reactor only if the line is expected to be kept off for prolonged periods for which NLDC/WRLDC/NRLDC would advise appropriately. Handling special situations such as load crash in Northern Region:

Under such situations there would be flows in the reverse direction viz. Northern to Western region. Since the Northern Region would experience high voltage, the 765 kV network in Northern Region might have to be opened to control voltage. The power flow on HVDC Mundra‐Mohindergarh bipole might also need to be reduced in case the load crash is in Haryana. NRLDC would advise Haryana SLDC accordingly so that the schedule is revised. x‐‐‐‐‐x‐‐‐‐x

Page 8 of 8

NLDC


July 2013-Rev 0

ANNEXURE-VI - Congestion Formats

NLDC


July 2013-Rev 0

NLDC


July 2013-Rev 0

ANNEXURE-VI - Congestion Formats Format II

NLDC


July 2013-Rev 0

ANNEXURE-VI - Congestion Formats Format III

National/_________Regional Load Despatch Centre Notice Number: (NLDC/RLDC)/yyyy/mm/….

Date: dd/mm/yy Time of Issue: hh:mm

To

WARNING NOTICE The actual transfer of electricity on following corridors has crossed the ATC

Corridor/Control Area

ATC (MW)

Actual Flow (MW)

The following regional entities, which are downstream of the congested corridor, are advised to reduce their drawl/increase their generation to decongest the system: 1. … m. The following reginal entities, which are upstream of te congested corridor are advised to / increase their drawl/reduce their generation to decongest the system: 1. … n. Shift Charge Manager

This is a warning notice before levying of congestion charges and issued in accordance with the Central Electricity Regulatory Commission (Measures to relieve congestion in real time operation) Regulations, 2009 NLDC would send this notice to RLDC and RLDC would send this notice to regional entities

Note: Format may be changed as per requirement with prior approval of the Commission

NLDC


July 2013-Rev 0


Format for Notice for Application of Congestion Charge (Format IV)

NLDC


July 2013-Rev 0

ANNEXURE-VI - Congestion Formats Format V

National/_________Regional Load Despatch Centre

Notice Number: (NLDC/RLDC)/yyyy/mm/….

Date: dd/mm/yy Time of Issue: hh:mm

To

NOTICE FOR WITHDRAWAL OF CONGESTION CHARGE Congestion charge on Unscheduled Interchange (UI) energy that was applicable w.e.f hh.mm of dd/mm/yyyy vide Notice Number…… Issued at hh:mm of dd/mm/yyyy would be lifted w.e.f time block no. (hh:mm) of dd/mm/yyyy

Shift Charge Manager

Issued in accordance with the Central Electricity Regulatory Commission (Measures to relieve congestion in real time operation) Regulations, 2009

NLDC would send this notice to RLDC and RLDC would send this notice to regional entities

Note: Format may be changed as per requirement with prior approval of the Commission

NLDC


July 2013-Rev 0


NLDC


July 2013-Rev 0

ANNEXURE-VII UI RATE IMPLEMENTED AS PER CERC ORDER No.L-1(1)/2009-CERC Dt. 28.04.2010 & Its First & Second Amendment

The charges for Unscheduled Interchanges for all the time-blocks payable for over-drawal by the buyer or the beneficiary and under-injection by the generating station or the seller and receivable for underdrawal by the buyer or the beneficiary and over-injection by the generating station or the seller shall be worked out on the average frequency of the time-block at the rates given here under

Unscheduled Interchange Cap Rates The Cap Rate shall be 421.50 Paise/kWh for all generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel, in case when actual generation is higher or lower than the scheduled generation.

The UI Cap Rate shall be 450.00 Paise/kWh for the under drawls by the buyer or the beneficiaries in excess of 10% of the schedule or 250 MW whichever is less.

The UI Cap Rate shall be 450.00 Paise/kWh for the injection by the seller in excess of 120% of the schedule subject to a limit of ex-bus generation corresponding to 105% of the Installed Capacity of the station in a time block and 101% of the Installed Capacity over a day.

The UI Cap Rate shall be 165.00 Paise/kWh for the injection by a generating station other than the hydro generating station in excess of 105% of the Declared Capacity of the station in a time block or in excess of 101% of the average Declared Capacity over a day.

The UI Cap Rate shall be 165.00 Paise/kWh for the injection by the seller in excess of ex-bus generation corresponding to 105% of the Installed Capacity of the station in a time block or 101% of the Installed Capacity over a day shall not exceed the Cap Rate as specified in the Schedule 'A' of the UI regulations.

The cap rates for the infirm power injected into the grid by a unit of a generating station during the testing/commissioning prior to COD of unit shall be as follows corresponding to the fuel used for the generation: Domestic coal/ Lignite/Hydro (` / kWh sent out) : 1.65 NLDC


July 2013-Rev 0

APM gas as fuel (`/ kWh sent out) : 2.60 Imported Coal/RLNG (`/ kWh sent out) : 3.30 Liquid Fuel (` / kWh sent out) : 9.00

Additional Unscheduled Interchange Charges The Additional Unscheduled Interchange Charge for over-drawal of electricity for each time-block when grid frequency is "below 49.7 Hz" and up to "Not below 49.5 Hz" shall be equivalent to 20% of the Unscheduled Interchange Charge corresponding to grid frequency of "below 49.5 Hz". The Additional Unscheduled Interchange Charge for under-injection of electricity for each time-block when grid frequency is "below 49.7 Hz" and up to "Not below 49.5 Hz" shall be equivalent to 20% of the Unscheduled Interchange Charge of the corresponding grid frequency of "below 49.5 Hz":

Provided that the Additional Unscheduled Interchange Charge for over-drawal of electricity for each time-block when grid frequency is below 49.5 Hz and up to 49.2 Hz shall be equivalent to 40% of the Unscheduled Interchange Charge 900.0 Paise/kWh corresponding to the grid frequency of below 49.5 Hz. The Additional Unscheduled Interchange Charge for under-injection of electricity for each time-block when grid frequency is below 49.5 Hz and up to 49.2 Hz shall be equivalent to 40% of the Unscheduled Interchange Charge of 900.0 Paise/kWh corresponding to the grid frequency of below 49.5 Hz

Provided that the Additional Unscheduled Interchange Charge for over-drawal of electricity for each time-block when grid frequency is below 49.2 Hz shall be equivalent to 100% of the Unscheduled Interchange Charge 900.0 Paise/kWh corresponding to the grid frequency of below 49.5 Hz.

The Additional Unscheduled Interchange Charge for under-injection of electricity for each time-block when grid frequency is below 49.2 Hz shall be equivalent to 100% of the Unscheduled Interchange Charge of 900.0 Paise/kWh corresponding to the grid frequency of below 49.5 Hz.

The Additional Unscheduled Interchange Charge for under-injection of electricity during the time-block when grid frequency is below 49.7 Hz and up to 49.5 Hz for the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel shall be equivalent to 20% of the UI Cap Rate of 421.50 Paise/kWh:

Provided that the Additional Unscheduled Interchange Charge for under-injection of electricity during the time-block when grid frequency is below 49.5 Hz for the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel shall be equivalent to 40% of the UI Cap Rate of 421.50 Paise/kWh. NLDC


July 2013-Rev 0

UI RATE TABLE Average Frequency of the time block(Hz) Below Not Below -50.20 50.18 50.16 50.14 50.12 50.10 50.08 50.06 50.04 50.02 50.00 49.98 49.96 49.94 49.92 49.90 49.88 49.86 49.84 49.82 49.80 49.78 49.76 49.74 49.72 49.70 49.68 49.66 49.64 49.62 49.60 49.58 49.56 49.54 49.52 49.50

UI Rate (Paise per kWh)

50.20 50.18 50.16 50.14 50.12 50.10 50.08 50.06 50.04 50.02 50.00 49.98 49.96 49.94 49.92 49.90 49.88 49.86 49.84 49.82 49.80 49.78 49.76 49.74 49.72 49.70 49.68 49.66 49.64 49.62 49.60 49.58 49.56 49.54 49.52 49.50

0.00 16.50 33.00 49.50 66.00 82.50 99.00 115.50 132.00 148.50 165.00 193.50 222.00 250.50 279.00 307.50 336.00 364.50 393.00 421.50 450.00 478.13 506.25 534.38 562.50 590.63 618.75 646.88 675.00 703.13 731.25 759.38 787.50 815.63 843.75 871.88 900.00

(Each 0.02 Hz step is equivalent to 16.50 Paise/kWh in the 50.2-50.00 Hz frequency range, 28.50 Paise/kWh in 50 Hz to 49.8 Hz and 28.12 Paise/kwh in frequency in the below 49.8 Hz to 49.5 Hz range.)

NLDC


July 2013-Rev 0

Annexure VIII Important Elements under NLDC Perspective

INDEX

Sl.No 1 2 3

NLDC

Chapter Inter Regional Links

Page No 1

HVDC Links

4

765kV Lines

5

4

765kV Line Reactors

7

5

765kV ICT and Bus Reactors

9

6

Imporatnt Intra regional lines having Impact on Transfer capability

11

7

Trans National Links

19


94 of 198

July 2013-Rev 0


1. INTER REGIONAL LINK I/R LINK

Voltage Level

O & M by

Agency at End 1

Agency at End 2

line length in Km

Conductor Type

+/- 500 kV, 2 x 250 MW, Vindhyachal HVDC Back to Back

-

-

PG

PG

PG

-

-

HVDC Link

+/- 500 kV, 2x1250 MW, APL Mundra (WR) Mohindargarh (NR) HVDC Bipole

-

Bipole

APL

APL Mundra

APL Mohindargarh

1000

Quad Lapwing

Agra - Gwalior

1

S/C

PG

PG

PG

129

Quad Bersimis

Agra - Gwalior

2

S/C

PG

PG

PG

128

Quad Bersimis

Kankroli-Zerda

1

D/C

PG

PG

PG

234

Twin Moose

Bhinmal-Zerda

1

D/C

PG

PG

PG

143

Twin Moose

Kota-Badod

1

S/C

RRVPNL

MPSEB

191

ACSR Zebra

Modak-Badod

1

S/C

RRVPNL MPSEB

RRVPNL

MPSEB

151

ACSR Zebra

Auraiya-Mehgaon

1

S/C

UPPCL

MPSEB

146

ACSR Zebra

Auraiya-Malanpur

1

S/C

UPPCL MPSEB

UPPCL

MPSEB

113

ACSR Zebra

Udaipur -Neemuch

1

S/C

RRVPNL

MPSEB

131

ACSR Panther

Ranapratap Sagar-Gandhi Sagar

1

D/C

RRVPNL

MPSEB

30

ACSR Panther

Ranapratap Sagar-Gandhi Sagar

2

D/C

RRVPNL

MPSEB

30

ACSR Panther

Sawai Madhopur - Seopar Kalan

1

S/C

RRVPNL MPSEB

RRVPNL

MPSEB

47

ACSR Panther

Rihand-Morwa

1

S/C

UPPCL MPSEB

UPPCL

MPSEB

41

ACSR Panther

Lalitpur - Rajghat

1

S/C

UPPCL MPSEB

UPPCL

MPSEB

23

ACSR Panther

400KV

220KV

132KV

NLDC

Tower Circuit ID configuration S/C or D/C

HVDC Link

765KV

NR-WR

Inter Regional Lines

RRVPNL MPSEB RRVPNL MPSEB


95 of 198

July 2013-Rev 0


I/R LINK

Voltage Level

Inter Regional Lines +/- 500 kV, Sasaram HVDC Back

Agency at End 1

Agency at End 2

line length in Km

Conductor Type

-

PG

PG

PG

-

-

Saranath-Sasaram (400KV)

1

S/C

PG

PG

PG

76

Twin Moose

Allahabad - Sasaram (400KV)

1

S/C

PG

PG

PG

271

Twin Moose

765KV

Fatehpur-Sasaram/Gaya

1

S/C

PG

PG

PG

337+148=485

Quad Bersimis

765KV

Fatehpur-Sasaram

1

S/C

PG

PG

PG

337

Quad Bersimis

Gorakhpur-Muzaffarpur

1

D/C

PG

PG

PG

261

Quad Moose

Gorakhpur-Muzaffarpur

2

D/C

PG

PG

PG

261

Quad Moose

Balia-Patna

1

D/C

PG

PG

PG

198

Quad Moose

Balia-Patna

2

D/C

PG

PG

PG

198

Quad Moose

Balia-Patna

3

D/C

PG

PG

PG

185

Quad Moose

Balia-Patna

4

D/C

PG

PG

PG

185

Quad Moose

Balia- Biharshariff

1

D/C

PG

PG

PG

242

Quad Moose

Balia- Biharshariff

2

D/C

PG

PG

PG

242

Quad Moose

Balia- Sasaram

1

S/C

PG

PG

PG

238

80kM Quad Moose + 158kM Quad Bersimis

Sahupuri-Pusauli

1

S/C

UPPCL+ BSPHCL

UPPCL

PG

72

ACSR Zebra

Rihand-Sone nagar

1

S/C

UPPCL+ BSPHCL

UPPCL

BSPHCL

139

ACSR Panther

Rihand-Garwah

1

S/C

UPPCL+ JSEB

UPPCL

JSEB

30

ACSR Panther

Sahupuri-Karmanasa

1

S/C

UPPCL

BSPHCL

27

ACSR Panther

Chandauli-Karmanasa

1

S/C

UPPCL

BSPHCL

25

ACSR Panther

400KV

220KV

132KV

NLDC

O & M by

-

HVDC Link

NR-ER


to Back (500 MW) *

UPPCL+ BSPHCL


96 of 198

July 2013-Rev 0


I/R LINK


Voltage Level


O & M by

Agency at End 1

Agency at End 2

line length in Km

Conductor Type

HVDC Link

+/- 500 kV, Bhadravati HVDC Back to Back (2x500 MW)

-

-

PG

PG

PG

-

-

Kolhaphur-Chikkodi

1

D/C

MSETCL

KPTCL

65

ACSR Drake

Kolhaphur-Chikkodi

2

D/C

MSETCL

KPTCL

65

ACSR Drake

Ponda-Ambewadi

1

D/C

GOA/KPTCL

GOA

KPTCL

108

ACSR Drake

Xeldom-Ambewadi

2

D/C

GOA/KPTCL

GOA

KPTCL

108

ACSR Drake

Raigarh-Sterlite

1

D/C

PG / SEL

PG

SEL

147

Twin Moose

Raigarh-Sterlite

2

D/C

PG / SEL

PG

SEL

147

Twin Moose

Raigarh-Jharsuguda

1

D/C

PG

PG

PG

110

Twin Moose

Raigarh-Jharsuguda

2

D/C

PG

PG

PG

110

Twin Moose

Sipat-Ranchi

1

D/C

PG

PG

PG

405

Twin Moose

Sipat-Ranchi

2

D/C

PG

PG

PG

405

Twin Moose

Raigarh-Budhipadar

1

S/C

CSPTCL

GRIDCO

81

ACSR Zebra

Korba(East)-Budhipadar

2

D/C

CSPTCL

GRIDCO

180

ACSR Zebra

Korba(East)-Budhipadar

3

D/C

PG

CSPTCL

GRIDCO

180

ACSR Zebra

+/- 500 kV, Gajuwaka HVDC Back to Back ( 2 x 500MW)

-

-

PG

PG

PG

-

-

+/- 500 kV, 2x1000 MW, Talcher(ER) -Kolar(SR) HVDC Bipole

-

Bipole

PG

PG

PG

1368

Quad Bersimis

Binaguri-Bongaigaon

1

D/C

PG

PG

PG

216

Twin Moose

Binaguri-Bongaigaon

2

D/C

PG

PG

PG

216

Twin Moose

220KV

Birpara-Salakati

1

D/C

PG

PG

PG

160

ACSR Zebra

220KV

Birpara-Salakati

2

D/C

PG

PG

PG

160

ACSR Zebra

WR-SR 220kV

400KV

WR-ER

220KV

ER-SR

HVDC Link

MSETCL/ KPTCL MSETCL/ KPTCL

CSPTCL/ GRIDCO CSPTCL/ GRIDCO

400KV ER-NER

*

NLDC

By passed * w.e.f 01.12.08

and operationalised periodically in HVDC mode to ensure healthiness of equipments


97 of 198

July 2013-Rev 0


2.HVDC LINKS ( EXCLUDING INTER REGIONAL LINKS)

Region

Voltage Level

Circuit ID

Tower configuration S/C or D/C

O & M by

RIHAND-DADRI BIPOLE

Pole 1

Bipole

PG

PG

RIHAND-DADRI BIPOLE

Pole 2

Bipole

PG

BALIA-BHIWADI BIPOLE

Pole 1

Bipole

BALIA-BHIWADI BIPOLE

Pole 2

CHANDRAPUR-PADGE BIPOLE CHANDRAPUR-PADGE BIPOLE


line length in Km

Conductor Type

PG

815

Quad Moose

PG

PG

815

Quad Moose

PG

PG

PG

780

Quad Moose

Bipole

PG

PG

PG

780

Quad Moose

Pole 1

Bipole

MSETCL

MSETCL MSETCL

752

Twin Moose

Pole 2

Bipole

MSETCL

MSETCL MSETCL

752

Twin Moose

Agency Agency at End 1 at End 2

+/- 500KV HVDC NR +/- 500KV HVDC

WR

NLDC

+/- 500KV HVDC


98 of 198

July 2013-Rev 0


3. 765kV LINES ( EXCLUDING INTER REGIONAL LINKS) Sl.No

Region

Voltage Level


Circuit ID


O & M by

Agency at Agency at End 1 End 2

line length in Km

Conductor Type

1

765KV

ANPARA C-UNNAO

1

S/C

UPPCL

LANCO

UPPCL

409

Quad Bersimis

2

765KV

BALIA-LUCKNOW

1

S/C

PG

PG

PG

316

Quad Bersimis

3

765 KV

FATEHPUR-AGRA

1

S/C

PG

PG

PG

178

Quad Bersimis

765KV

MOGA-BHIWANI(PG)

1

S/C

PG

PG

PG

273

Quad Bersimis

5

765KV

JHATIKARA-BHIWANI(PG)

1

S/C

PG

PG

PG

85

Quad Bersimis

6

765KV

AGRA-JHATIKARA

1

S/C

PG

PG

PG

245

Quad Bersimis

7

765KV

AGRA-MEERUT

1

S/C

PG

PG

PG

260

Quad Bersimis

4

NLDC

NR


99 of 198

July 2013-Rev 0


3. 765kV LINES ( EXCLUDING INTER REGIONAL LINKS) Sl.No

Region

Voltage Level


Circuit ID


O & M by

Agency at Agency at End 1 End 2

line length in Km

Conductor Type

8

765KV

SIPAT-BILASPUR 1

1

S/C

PG

NTPC

PG

22

Quad Bersimis

9

765KV

SIPAT-BILASPUR 2

2

S/C

PG

NTPC

PG

22

Quad Bersimis

10

765KV

SEONI-BILASPUR 1

1

S/C

PG

PG

PG

337

Quad Bersimis

11

765KV

SEONI-BILASPUR 2

2

S/C

PG

PG

PG

338

Quad Bersimis

12

765KV

SEONI-WARDHA 1

1

S/C

PG

PG

PG

268

Quad Bersimis

13

765KV

SEONI-WARDHA 2

2

S/C

PG

PG

PG

261

Quad Bersimis

765KV

SATNA-BINA 1

1

S/C

PG

PG

PG

274

Quad Bersimis

15

765KV

SATNA-BINA 2

2

S/C

PG

PG

PG

276

Quad Bersimis

16

765KV

SEONI-BINA 1

1

S/C

PG

PG

PG

292

Quad Bersimis

17

765KV

BINA-GWALIOR 1

1

S/C

PG

PG

PG

234

Quad Bersimis

18

765KV

BINA-GWALIOR 2

2

S/C

PG

PG

PG

235

Quad Bersimis

19

765KV

SASAN-SATNA 1

1

S/C

PG

SASAN UMPP

PG

243

Quad Bersimis

20

765KV

SASAN-SATNA 2

2

S/C

PG

SASAN UMPP

PG

246

Quad Bersimis

14

NLDC

WR


100 of 198

July 2013-Rev 0


4. 765kV - LINE REACTORS Sl. No

Region

1 2

INTER REGIONAL

Remarks

End 1

End 2

Ckt ID

End 1

End 2

Gaya

Fatehpur

1

1 x 240

1 x 330

Sasaram

Fatehpur

1

1 x 330

1 x 330

3

Agra

Gwalior

1

-

-

4

Agra

Gwalior

2

-

-

5

Fatehpur

Agra

1

1 x 330

1 x 240

6

Balia

Lucknow

1

1 x 240

1 x 240

7

Anpara

Unnao

1

1 x 330

1 x 330

Bhiwani

1

1 x 240

-

8

NLDC

Line Reactor (MVAR)

NAME OF THE LINE

NORTHERN Moga REGION

9

Bhiwani

Jhatikara

1

-

-

10

Agra

Jhatikara

1

-

1 x 240

11

Agra

Meerut

1

-

1 x 240


101 of 198

330 MVAR Mid point reactor at Sasaram

July 2013-Rev 0


Sl. No

NAME OF THE LINE

Line Reactor(MVAR)

End 1

End 2

Ckt ID

End 1

End 2

12

Sipat

Bilaspur

1

1 x 240

-

13

Sipat

Bilaspur

2

1 x 240

-

14

Bilaspur

Seoni

1

1 x 240

1 x 240

15

Bilaspur

Seoni

2

1 x 240

1 x 240

16

Seoni

Wardha

1

--

1 x 240

17

Seoni

Wardha

2

--

1 x 240

Seoni

Bina

1

1 x 240

1 x 240

19

Satna

Bina

1

1 x 240

1 x 240

20

Satna

Bina

2

1 x 240

1 x 240

21

Bina

Gwalior

1

1 x 240

1 x 240

22

Bina

Gwalior

2

1 x 240

1 x 240

23

Sasan

Satna

1

-

-

24

Sasan

Satna

2

-

-

18

NLDC

Region

WESTERN REGION


102 of 198

Remarks

July 2013-Rev 0


5. 765kV ICT AND BUS REACTORS Substation

765/400kV ICT

Bus Reactor MVAR

1

Fatehpur

1500 x 2=3000

1 x 330

2

Agra

1500 x 2=3000

2 x 240=480

3

Balia

1500 x 2=3000

3x 240=720

4

Lucknow

1500 x 2=3000

1 x 240

5

Moga

1500 x 2=3000

2 x 240=480

1000 x 2=2000

2 x 240=480

Sl. No

6

NLDC

Region

NORTHERN REGION Bhiwani

7

Jhatikara

1500 x 4=6000

1 x 240=240

8

Meerut

1500 x 2=3000

1 x 240

9

Anpara

1000 x 2=2000

1 x 189

10

Unnao

1000 x 2=2000

1 x 189


103 of 198

Remarks

July 2013-Rev 0


5. 765kV ICT AND BUS REACTORS Substation

765/400kV ICT

Bus Reactor MVAR

11

Gwalior

1500 x 2=3000

-

12

Sipat

1000 x 2=2000

1 x 240

13

Bilaspur

1500 x 3=4500

1 x 240

14

Seoni

1500 x 3=4500

1 x 240

Wardha

1500 x 3=4500

1 x 240

16

Bina

1000 x 2=2000

17

Satna

1000 x 2=2000

18

Sasan

1000 x 1=1000

-

Gaya

1500 x 3=4500

2 x 240=480

Sasaram

1500 x 1=1500

1 x 330

Sl. No

15

19 20

NLDC

Region

WESTERN REGION

EASTERN REGION

1 x 240 1 x 240


104 of 198

Remarks

July 2013-Rev 0


6. IMPORTANT INTRA REGIONAL LINES HAVING IMPACT ON TRANSFER CAPABILITY NORTHERN REGION SL VOLTAGE NO KV

FROM

TO

Tower Circuit configuration ID S/C or D/C

O & M by

Agency at End 1

Agency at End 2

LINE LENGTH Conductor Type CKMs

TTC / ATC impact

1

400

KANKROLI

RAPP - C & D

1

D/C

PG

PG

NPCIL

199

Twin Moose

WR-NR

2

400

KANKROLI

RAPP - C & D

2

D/C

PG

PG

NPCIL

199

Twin Moose

WR-NR

3

400

BHINMAL

KANKROLI

1

D/C

PG

PG

PG

202

Twin Moose

WR-NR

4

400

SINGRAULI STPS

HVDC VINDHYACHAL

1

S/C

PG

NTPC

PG

3

Twin Moose

WR-NR

5

400

SINGRAULI STPS

HVDC VINDHYACHAL

2

S/C

PG

NTPC

PG

5

Twin Moose

WR-NR

6

400

SINGRAULI STPS

ANPARA

1

S/C

PG

NTPC

PG

25

Twin Moose

WR-NR

7

400

BHIWANI PG

MOHINDERGARH

1

D/C

APL

PG

APL

50

Twin Moose

WR-NR

8

400

BHIWANI PG

MOHINDERGARH

2

D/C

APL

PG

APL

50

Twin Moose

WR-NR

9

400

DHANONDA

MOHINDERGARH

1

D/C

APL

HVPNL

APL

5

Quad Moose

WR-NR

10

400

DHANONDA

MOHINDERGARH

2

D/C

APL

HVPNL

APL

5

Quad Moose

WR-NR

NLDC


105 of 198

July 2013-Rev 0


WESTERN REGION SL VOLTAGE NO KV

FROM

TO


O & M by

Agency at End 1

Agency at End 2


TTC / ATC impact

1

400

BHILAI

KORADI

1

S/C

PG

CSPTCL

PG

272

Twin Moose

ER-W3

2

400

BHILAI

SEONI

1

S/C

MPPTCL/ CSPTCL

CSPTCL

PG

232

Twin Moose

ER-W3

3

400

BINA

SHUJALPUR

1

D/C

PG

PG

PG

198

Twin Moose

WR-NR

4

400

BINA

SHUJALPUR

2

D/C

PG

PG

PG

198

Twin Moose

WR-NR

5

400

RAIPUR

BHADRAVATI I

1

D/C

PG

PG

PG

333

Twin Moose

WR-SR

6

400

RAIPUR

BHADRAVATI II

2

D/C

PG

PG

PG

333

Twin Moose

WR-SR

7

400

RAIPUR

BHADRAVATI III

3

D/C

PG

PG

PG

345

Twin Moose

WR-SR

8

400

BHADRAVATI

BHILAI

1

S/C

PG

PG

CSPTCL

322

Twin Moose

WR-SR

9

400

SOJA

ZERDA

1

S/C

GETCO

GETCO

GETCO

135

Twin Moose

WR-NR

10

400

RANCHODPURA

ZERDA

1

D/C

GETCO

GETCO

GETCO

135

Twin Moose

WR-NR

11

400

RANCHODPURA

ZERDA

2

D/C

GETCO

GETCO

GETCO

135

Twin Moose

WR-NR

12

400

APL MUNDRA

SAMI

1

D/C

APL

APL

APL

282

Twin Moose

WR-NR

13

400

APL MUNDRA

SAMI

2

D/C

APL

APL

APL

282

Twin Moose

WR-NR

14

400

APL MUNDRA

HADALA

1

S/C

GETCO

APL

GETCO

238

Twin Moose

WR-NR

NLDC


106 of 198

July 2013-Rev 0

SL VOLTAGE NO KV

FROM

TO

Annexure VIII WESTERN REGION Important Elements under NLDC Perspective Tower Circuit Agency at O & M by configuration ID End 1 S/C or D/C

Agency at End 2


TTC / ATC impact

15

400

APL MUNDRA

VARSANA

1

S/C

GETCO

APL

GETCO

166

Twin Moose

WR-NR

16

400

CGPL

BACHHAU

1

D/C

PG

CGPL

PG

99

Triple snowbird

WR-NR

17

400

CGPL

BACHHAU

2

D/C

PG

CGPL

PG

99

Triple snowbird

WR-NR

18

400

CGPL

CHORANIA

1

D/C

PG

CGPL

GETCO

314

Triple snowbird

WR-NR

19

400

CGPL

CHORANIA

2

D/C

PG

CGPL

GETCO

314

Triple snowbird

WR-NR

20

400

CGPL

JETPUR

1

D/C

PG

CGPL

GETCO

-

Triple snowbird

WR-NR

21

400

CGPL

JETPUR

2

D/C

PG

CGPL

GETCO

-

Triple snowbird

WR-NR

22

400

RAIPUR

WARDHA

1

D/C

PG

PG

PG

373

Quad Moose

W3

23

400

RAIPUR

WARDHA

2

D/C

PG

PG

PG

373

Quad Moose

W3

24

400

WARDHA

AKOLA

1

D/C

PG

PG

MSETCL

324

Twin Moose

W3

25

400

WARDHA

AKOLA

2

D/C

PG

PG

MSETCL

324

Twin Moose

W3

26

220

GWALIOR PG

GWALIOR MP

1

D/C

MPPTCL

PG

MPPTCL

11

ACSR Zebra

WR-NR

27

220

GWALIOR PG

GWALIOR MP

2

D/C

MPPTCL

PG

MPPTCL

11

ACSR Zebra

WR-NR

28

220

GWALIOR PG

MALANPUR

1

D/C

MPPTCL

PG

MPPTCL

38

ACSR Zebra

WR-NR

29

220

GWALIOR PG

MALANPUR

2

D/C

MPPTCL

PG

MPPTCL

38

ACSR Zebra

WR-NR

30

220

GWALIOR MP

BINA MP

1

D/C

MPPTCL

MPPTCL

MPPTCL

246

ACSR Zebra

WR-NR

31

220

GWALIOR MP

BINA MP

2

D/C

MPPTCL

MPPTCL

MPPTCL

246

ACSR Zebra

WR-NR

NLDC


107 of 198

July 2013-Rev 0


SOUTHERN REGION SL VOLTAGE NO KV

FROM

TO


O & M by

Agency at End 1

Agency at End 2


TTC / ATC impact

1

400

RAMAGUNDAM

BHADRAVATI I

1

D/C

PG

NTPC

PG

178

Twin Moose

WR-SR

2

400

RAMAGUNDAM

BHADRAVATI II

2

D/C

PG

NTPC

PG

178

Twin Moose

WR-SR

3

400

JEYPORE

GAjUWAKA I

1

D/C

PG

PG

PG

220

Twin AAAC

ER-SR

4

400

JEYPORE

GAjUWAKA I I

2

D/C

PG

PG

PG

220

Twin AAAC

ER-SR

5

400

VIJAYAWADA

NELLORE I

1

D/C

PG

PG

PG

340

Twin Moose

ER-SR

6

400

VIJAYAWADA

NELLORE II

2

D/C

PG

PG

PG

340

Twin Moose

ER-SR

7

400

HOSUR

SALEM

1

S/C

PG

PG

PG

126

Twin Moose

S1-S2

8

400

SOMANAHALLI

SALEM

1

D/C

PG

PG

PG

181

Twin Moose

S1-S2

NLDC


108 of 198

July 2013-Rev 0


EASTERN REGION SL VOLTAGE NO KV

FROM

TO


O & M by

Agency at End 1

Agency at End 2


TTC / ATC impact

1

400

PURNEA

MUZAFFARPUR

1

D/C

Powerlinks

PG

PG

240

Quad Moose

ER-NER & ER-NR

2

400

PURNEA

MUZAFFARPUR

2

D/C

Powerlinks

PG

PG

240

Quad Moose

ER-NER & ER-NR

3

400

MALDA

PURNEA I

1

D/C

PG

PG

PG

167

Twin Moose

ER-NER & ER-NR

4

400

MALDA

PURNEA II

2

D/C

PG

PG

PG

167

Twin Moose

ER-NER & ER-NR

5

400

PURNEA

BINAGURI

1

D/C

PG

PG

PG

168

Twin Moose

ER-NER

6

400

PURNEA

BINAGURI

2

D/C

PG

PG

PG

168

Twin Moose

ER-NER

7

400

PURNEA

BINAGURI

3

D/C

PG

PG

PG

160

Quad Moose

ER-NER

8

400

PURNEA

BINAGURI

4

D/C

PG

PG

PG

160

Quad Moose

ER-NER

9

400

FARAKKA

MALDA

1

D/C

PG

NTPC

PG

40

Twin Moose

ER-NER & ER-NR

10

400

FARAKKA

MALDA

2

D/C

PG

NTPC

PG

40

Twin Moose

ER-NER & ER-NR

11

400

BIHARSHARIFF

SASARAM - I

1

D/C

PG

PG

PG

195

Twin Moose

ER-NR

12

400

BIHARSHARIFF

SASARAM - II

2

D/C

PG

PG

PG

195

Twin Moose

ER-NR

13

400

BIHARSHARIFF

SASARAM - III

3

D/C

PG

PG

PG

195

Quad Moose

ER-NR

14

400

FARAKKA

KAHALGAON I

1

D/C

PG

NTPC

NTPC

95

Twin Moose

ER-NR

15

400

FARAKKA

KAHALGAON II

2

D/C

PG

NTPC

NTPC

95

Twin Moose

ER-NR

16

400

FARAKKA

KAHALGAON III

3

D/C

PG

NTPC

NTPC

95

Twin Moose

ER-NR

17

400

FARAKKA

KAHALGAON IV

4

D/C

PG

NTPC

NTPC

95

Twin Moose

ER-NR

18

400

KAHALGAON

BIHARSHARIFF I

1

D/C

PG

NTPC

PG

201

Twin Moose

ER-NR

NLDC


109 of 198

July 2013-Rev 0



`

`

FROM

TO


O & M by

Agency at End 1

Agency at End 2


TTC / ATC impact

19

400

KAHALGAON

BIHARSHARIFF II

2

D/C

PG

NTPC

PG

201

Twin Moose

ER-NR

20

400

KAHALGAON

BANKA I

1

D/C

PG

NTPC

PG

47

Twin Moose

ER-NR

21

400

KAHALGAON

BANKA II

2

D/C

PG

NTPC

PG

47

Twin Moose

ER-NR

22

400

BANKA

BIHARSHARIFF I

1

D/C

PG

PG

PG

184

Twin Moose

ER-NR

23

400

BANKA

BIHARSHARIFF II

2

D/C

PG

PG

PG

184

Twin Moose

ER-NR

24

400

MAITHON

KAHALGAON I

1

D/C

PG

PG

NTPC

172

Twin Moose

ER-NR

25

400

MAITHON

KAHALGAON II

2

D/C

PG

PG

NTPC

172

Twin Moose

ER-NR

26

400

MAITHON

KODERMA

1

D/C

PG

PG

DVC

260

Quad Moose

ER-NR

27

400

MAITHON

KODERMA

2

D/C

PG

PG

DVC

260

Quad Moose

ER-NR

28

400

BARH

PATNA

1

D/C

PG

NTPC

PG

94

Quad Moose

ER-NR

29

400

BARH

PATNA

2

D/C

PG

NTPC

PG

94

Quad Moose

ER-NR

30

400

BARH

KAHALGAON I

1

D/C

PG

NTPC

NTPC

217

Quad Moose

ER-NR

31

400

BARH

KAHALGAON II

2

D/C

PG

NTPC

NTPC

217

Quad Moose

ER-NR

32

400

KODERMA

BIHARSHARIFF I

1

D/C

PG

DVC

PG

111

Quad Moose

ER-NR

33

400

KODERMA

BIHARSHARIFF II

2

D/C

PG

DVC

PG

111

Quad Moose

ER-NR

34

400

STERLITE

ROURKELA

1

D/C

D/C/SEL

SEL

PG

114

Twin Moose

ER-WR

35

400

STERLITE

ROURKELA

2

D/C

D/C/SEL

SEL

PG

114

Twin Moose

ER-WR

36

400

JHARSUGUDA

ROURKELA

1

D/C

PG

PG

PG

112

Twin Moose

ER-WR

37

400

JHARSUGUDA

ROURKELA

2

D/C

PG

PG

PG

112

Twin Moose

ER-WR

38

400

ROURKELA

JAMSHEDPUR

1

D/C

PG

PG

PG

174

Twin Moose

ER-WR

NLDC


110 of 198

July 2013-Rev 0



FROM

TO


O & M by

Agency at End 1

Agency at End 2


TTC / ATC impact

39

400

ROURKELA

JAMSHEDPUR

2

D/C

PG

PG

PG

174

Twin Moose

ER-WR

40

400

MAITHON

MEJIA B

1

D/C

PG

PG

DVC

84

Twin Moose

W3-ER

41

400

MAITHON

MEJIA B

2

D/C

PG

PG

DVC

84

Twin Moose

W3-ER

42

400

MAITHON

MEJIA B

3

S/C

PG

PG

DVC

97

Twin Moose

W3-ER

43

400

MAITHON

MPL

1

D/C

PG

PG

MPL

30

Twin Moose

W3-ER

44

400

MAITHON

MPL

2

D/C

PG

PG

MPL

30

Twin Moose

W3-ER

45

400

JEYPORE

BOLANGIR

1

S/C

PG

PG

PG

288

Twin Moose

ER-SR

46

400

BOLANGIR

ANGUL

1

S/C

PG

PG

PG

199

Twin Moose

ER-SR

47

400

ANGUL

MERAMUNDALI

1

S/C

PG

PG

OPTCL

25

Twin Moose

ER-SR

48

400

TALCHER

MERAMUNDALI

1

S/C

PG

NTPC

OPTCL

51

Twin Moose

ER-SR

49

400

TALCHER

GMR

1

S/C

PG

NTPC

GMR

46

Twin Moose

ER-SR

50

400

GMR

MERAMUNDALI

1

S/C

PG

GMR

OPTCL

8

Twin Moose

ER-SR

51

400

TALCHER

ROURKELA

1

D/C

NTPC

PG

PG

171

Twin Moose

ER-SR

52

400

TALCHER

ROURKELA

2

D/C

NTPC

PG

PG

171

Twin Moose

ER-SR

53

400

JEYPORE

INDRAVATI

1

S/C

PG

PG

PG

72

Twin Moose

ER-SR

54

400

RENGALI

KEONJHAR

1

S/C

PG

PG

PG

-

Twin Moose

ER-SR

55

400

KEONJHAR

BARIPADA

1

S/C

OPTCL

PG

PG

156

Twin Moose

ER-SR

56

400

BARIPADA

JAMSHEDPUR

1

S/C

PG

PG

PG

116

Twin Moose

ER-SR

57

400

KHARAGPUR

BARIPADA

1

S/C

WBSETCL & OPTCL

WBSETCL

PG

98

Twin Moose

ER-SR

58

400

KHARAGPUR

KOLAGHAT

1

S/C

WBSETCL

WBSETCL

WBSETCL

80

Twin Moose

ER-SR

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NORTH EASTERN REGION

SL VOLTAGE NO KV

FROM

TO


O & M by

Agency at End 1

Agency at End 2


TTC / ATC impact

1

400

BALIPARA

BONGAIGAON I

1

D/C

PG

PG

PG

290

Twin Moose

ER-NER

2

400

BALIPARA

BONGAIGAON II

2

D/C

PG

PG

PG

290

Twin Moose

ER-NER

3

400

MISA

BALIPARA I

1

D/C

PG

PG

PG

96

Twin Moose

ER-NER

4

400

MISA

BALIPARA II

2

D/C

PG

PG

PG

96

Twin Moose

ER-NER

5

400

BALIPARA

RANGANADI I

1

D/C

PG

PG

PG

166

Twin Moose

ER-NER

6

400

BALIPARA

RANGANADI II

2

D/C

PG

PG

PG

166

Twin Moose

ER-NER

7

400

PALLATANA

SILCHAR I

1

D/C

NETC

OTPC

PG

247

Twin Moose

ER-NER

8

400

PALLATANA

SILCHAR II

2

D/C

NETC

OTPC

PG

247

Twin Moose

ER-NER

9

400

SILCHAR II

KILLING

1

D/C

NETC/ MePTCL

OTPC

MePTCL

217

Twin Moose

ER-NER

10

220

BTPS

SALAKATI I

1

D/C

PG

AEGCL

PG

3

Twin Moose

ER-NER

11

220

BTPS

SALAKATI II

2

D/C

PG

AEGCL

PG

3

Twin Moose

ER-NER

12

220

BTPS

AGIA I

1

D/C

AEGCL

AEGCL

AEGCL

63

AAAC Zebra

ER-NER

13

220

BTPS

AGIA II

2

D/C

AEGCL

AEGCL

AEGCL

63

AAAC Zebra

ER-NER

14

220

AGIA

SARUSAJAI

1

D/C

AEGCL

AEGCL

AEGCL

131

AAAC Zebra

ER-NER

15

220

AGIA

BOKO

1

D/C

AEGCL

AEGCL

AEGCL

70

AAAC Zebra

ER-NER

16

220

BOKO

SARUSAJAI

1

D/C

AEGCL

AEGCL

AEGCL

61

AAAC Zebra

ER-NER

17

220

BALIPARA

SAMAGURI

1

S/C

PG/AEGCL

PG

AEGCL

65

AAAC Zebra

ER-NER

18

220

SAMAGURI

SARUSAJAI

1

D/C

AEGCL

AEGCL

AEGCL

130

AAAC Zebra

ER-NER

19

220

SAMAGURI

SARUSAJAI

2

D/C

AEGCL

AEGCL

AEGCL

130

AAAC Zebra

ER-NER

NLDC


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7.TRANS NATIONAL LINK Tower Circuit ID configuration S/C or D/C

I/R LINK

Voltage Level

O & M by

Agency at End 1

Agency at End 2

line length in Km

NR-Nepal

132 KV

Tanakpur-Mahendernagar

1

S/C

PG

NHPC

NEP

3

132 KV

Balmiknagar (BSEB)-Surajpura

1

S/C

BSEB

NEP

132 KV

Kataiya (BSEB)-Duhabi

1

S/C

BSEB

NEP

33 KV

Thakurganj (BSEB)-Bhadarpur

1

S/C

BSEB

NEP

33 KV

Raxaul (BSEB)-Birganj

1

S/C

BSEB

NEP

33 KV

Kataiya (BSEB) – Biratnagar

1

S/C

BSEB

NEP

33 KV

Jaynagr(BSEB)-Siraha

1

S/C

BSEB

NEP

33 KV

Kataiya (BSEB) – Rajbiraj

1

S/C

BSEB

NEP

33 KV

Sitamari (BSEB) – Jaleswar

1

S/C

BSEB

NEP

11 KV

Jogbani (BSEB)-Biratnagari

1

S/C

BSEB

NEP

11 KV

Bargania (BSEB) – Gaur

1

S/C

BSEB

NEP


Conductor Type

ER-Nepal

NLDC


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I/R LINK

NER-BHUTAN

ER-BHUTAN

NLDC

Voltage Level



O & M by

Agency at End 1

Agency at End 2

line length in Km

Conductor Type

132 KV

Salakati - Gelephu

1

S/C

PG

PG

Bhutan

49.2

ACSR Panther

132 KV

Rangia -Deothang

1

S/C

PG

AEGCL

Bhutan

49

ACSR Panther

11 KV

Bongaigaon -Gaylegphug

1

S/C

AEGCL

Bhutan

11 KV

Tamalpur -SamdrupJongkhar

1

S/C

AEGCL

Bhutan

11 KV

Dampuri-Daifan

1

S/C

AEGCL

Bhutan

400KV

Binaguri -Tala-I ( India portion)

1

D/C

PG

PG

THEP

115

Twin Moose

400KV

Binaguri -Tala- II ( India portion)

2

D/C

PG

PG

THEP

115

Twin Moose

400KV

Binaguri -Tala- IV ( India portion)

4

S/C

PG

PG

THEP

98

Twin Moose

400KV

Binaguri -Malbase-III (India portion)

1

S/C

PG

PG

THEP

121

Twin Moose

220KV

Birpara - Chukha - I (India portion)

1

D/C

PG

PG

Bhutan

38

ACSR Zebra

220KV

Birpara -Chukha - II (India portion)

2

D/C

PG

PG

Bhutan

38

ACSR Zebra

220KV

Birpara - Malbase ( India portion)

1

S/C

PG

PG

Bhutan

40

ACSR Zebra

11 KV

kalchini-phuntsholing

1

S/C

WBSETCL

Bhutan

11 KV

Jaldhaka-Sibsoo

1

S/C

WBSETCL

Bhutan

11 KV

Banarhat - Samchi

1

S/C

WBSETCL

Bhutan


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Annexure IX- Outage Planning Procedure

ANNEXURE IX

Draft Procedure for Transmission Elements Outage Planning

March 2013

The procedure aims to streamline the process of outage coordination between SLDCs, RLDCs, NLDC, RPCs and Indenting Agencies

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1. Introduction 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 coordination 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. Proper coordination of transmission element outage is important mainly due to the following factors: i. Reliability of operation of the All India grid ii. Certainty to the electricity markets. iii. Proper crew resource mobilization at the work sites to ensure that outage time is minimized. iv. Proper coordination of works by different entities to ensure that outage time is optimised.

Outage Coordination has been one of the important functions of Regional Power Committees (RPCs), Regional Load Despatch Centres (RLDCs) and National Load Despatch Centre (NLDC) and is the first stage of operational planning. As per Indian Electricity Grid Code (IEGC), the responsibility to undertake planning of outage of transmission system has been assigned to RPCs. The outages of the inter-state transmission lines and intra state elements which are important for the region are being coordinated by RLDCs. In the cases where the outages may have an impact across two or more regions, coordination is in consultation with NLDC. The relevant clauses of IEGC in this regard are quoted below: “2.4.2 The following functions which go to facilitate the stability and smooth operation of the systems are identified for the RPC: ………… (e) To undertake planning of outage of transmission system on annual / monthly basis.” “2.3 Role of RLDC

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2.3.1.1The Regional Load Despatch Centre shall be the apex body to ensure integrated operation of the power system in the concerned region” “2.2 Role of NLDC …….. (f) Coordination with Regional Power Committees for regional outage schedule in the national perspective to ensure optimal utilization of power resources.” 2. Objective At present, planned outages are being discussed in respective Operation Coordination Committee (OCC) meeting of RPCs and availed based on the actual grid conditions and/or any changes requested by transmission system owner or transmission element outage indenting agency. The approval of planned as well as emergency outages in the transmission network level in real time is being coordinated by RLDCs and NLDC based on system conditions. The procedure aims to streamline the process of outage coordination between SLDCs, RLDCs, NLDC, RPCs, owners of transmission assets and transmission element outage Indenting Agencies. As outage planning is an important part of operational planning, multi-layered checks would help in ensuring reliability of the power system. These checks need to be at the following levels:  Due diligence between the agencies involved in the transmission asset maintenance through bilateral discussion.  Study sub-committee of RPCs.  Operation Co-ordination sub-Committee of RPCs  Off-line simulations and planning at RLDCs/NLDC level  Real time check at RLDCs/NLDC level 3. Scope The procedure is applicable to RPCs, RLDCs, NLDC, SLDCs, STUs, load serving entities and indenting agency. It would be applicable once the annual outage

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plan is finalized by 31st December of each year for the next financial year by the RPCs as per the IEGC. 4. Procedure for discussing outages in OCC meeting. 4.1.

Indenting Agency: The agency which gives the requisition for outage of any transmission element shall be called Indenting Agency. Any of the following may request for outage of any transmission elements:

4.1.1. Transmission Licensees / State Transmission Utilities 4.1.2. Generating Companies 4.2.

Indenting Agency shall submit the proposed shutdown for the next calendar month latest by 3rd day of the current month to the RPC Secretariat as per Format IA / Format IB.

4.3.

In case of shutdown of inter-regional lines and intra-regional lines affecting the transfer capability of any inter regional corridor, the Indenting agency shall submit the shutdown proposal in both the concerned RPCs. To facilitate this broad list of such lines is indicated at Annexure II which will be reviewed and updated by NLDC from time to time. The indenting agency may do an internal screening of its outage plan centrally to avoid multiple outages in the same corridor simultaneously. Bilateral discussion between the agencies involved may also be done to minimize outage duration before submitting the outage plan to RPCs.

4.4.

RPC Secretariat shall compile all the received proposals and put up the same on its website by 5th day of the month as per Format IIA / Format IIB.

4.5.

System Study sub-committee of RPCs shall study the impact of these outages and based on its recommendations, RPC shall discuss proposed outages in the OCC meeting and prepare a list of approved transmission outages with the precautions to be taken. RPCs would attempt to schedule all their OCC meetings between 10th to 15th day of the month so that sufficient time is available both to the Study Committee before the OCC meetings as well as for RLDCs/NLDC

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(mainly to take care of further changes in the network topology and/or in load generation) after the OCC meeting. 4.6.

While approving the shutdowns it shall be ensured that outages in the same corridor shall not be approved simultaneously. It also need to be ensured that all other concerned entities should also complete their work during the shutdown period so as multiple shutdown of same element for work by multiple agencies are avoided. The multiple outages of the transmission element for the same work during the year may also be avoided.

4.7.

RPC shall send the list of approved transmission outages to SLDCs/RLDCs/NLDC within 3 days of the OCC meeting and preferably latest by 18th of the month as per Format IIIA / Format IIIB. The same shall also be displayed on RPC websites.

4.8.

Any shutdown proposal which requires approval of two RPCs shall be considered approved only if it is approved in both the RPCs.

4.9.

After the receipt of Format IIIA / Format IIIB from each RPC, NLDC in consultation with RLDCs may prepare a tentative readjusted timings/dates of transmission element outages for next month considering the principles set out in this procedure.

5. Approving Load Despatch Centre and Consenting Load Despatch Centre 5.1.

Approving Load Despatch Centre: The Load Despatch Centre responsible for approving any transmission outage shall be called Approving Load Despatch Centre.

5.2.

Consenting Load Despatch Centre: The agency whose consent is required by Approving Load Despatch Centre for approving any outage shall be called Consenting Load Despatch Centre.

5.3.

Once the RPCs approve the monthly outage plan, the responsibility of approval of outages shall be as under:

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Sl.No

Type of Outage

1

765 kV or above Lines

2

Inter-Regional Lines

3

HVDCs

4

International Interconnections

5

Intra-Regional Lines affecting transfer capability of any inter regional corridor. Intra-Regional Lines which does not affect transfer capability of any inter regional corridor and included in the list of important elements of RLDCs (excluding lines covered under sl no.1,3,4 and 5) All other lines (excluding sl no. 1,2,3,4,5,6)

6

7

Consenting Load Despatch Centre Concerned RLDCs Concerned RLDCs Concerned RLDCs Concerned RLDC

Approving Load Despatch Centre

Concerned RLDCs

NLDC

SLDCs

RLDCs

SLDC

SLDC

NLDC NLDC NLDC NLDC

6. Procedure for approval of outage on D-3 basis

6.1.

NLDC

Planned Outages which have been approved in the OCC meeting of a region shall be considered for approval by RLDCs/NLDC on D-3 basis. If an outage is to be availed on say 10th of the month, the indenting agency would forward such requests to the concerned RLDC on 7th of the month by 1000 hours. This practice is necessary to realize the seriousness and readiness of the agency which indented the outage request in the first place as it is observed that many outages are not


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availed as per the monthly schedule. In case the request for transmission element outage is not received within the timeline prescribed above, it will be assumed that the indenting agency is not availing the outage. 6.2.

Request for outages which are approved by OCC must be sent by the owner of the transmission asset at least 3 days in advance to respective RLDC by 1000 hours as per Format IV.

6.3.

In case the owner is not availing the OCC approved outage, the same shall be intimated to the respective RLDC at least 3 days in advance.

6.4.

Planned Outages which are approved in OCC meeting shall only be considered for approval on D-3 basis.

6.5.

Approval of Outage where Approving Authority is NLDC

6.5.1. RLDCs shall forward the request for shutdown along with their consent and observation as per Format V to NLDC/other concerned RLDCs with clear observations regarding possible constraints / contingency plan and consent including study results by 1000 hours of D-2 day. Other concerned RLDCs would forward their observations/consent/reservations by 1600 hours of D-2.

6.5.2. NLDC shall approve the outage along with the clear precautions/measures to be observed during the shutdown and inform all concerned RLDCs.

6.5.3. The proposed outages shall be reviewed on day ahead basis depending upon the system conditions and the outages shall be approved/refused latest by 1200 Hrs of D-1 day. A suggestive format for approval of outage is enclosed as Format VI.

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6.5.4. In case the outage is approved precautions/measures to be observed during the shutdown shall be stated. In case of refusal, clear reasons shall be stated by the RLDCs/NLDC. 6.5.5. Outages impacting the transfer capability of more than one corridor shall not be allowed simultaneously.

Sl No 1

2

3 4

6.6.

Activity Request of shutdown from Indenting agency to concerned RLDC. Forwarding request of shutdown requiring NLDC approval from RLDC to other concerned RLDCs and NLDC (along with the recommendations and study result) Comments of other RLDCs or NLDC Approval or Rejection of Request

Day D-3

Time 1000 hrs

D-2

1000 hrs

D-2

1800 hrs

D-1

1200 hrs

Approval of Outage where Approving Authority is RLDC

6.6.1. In case the indenting agency is a state entity, the request for transmission element outage shall be submitted to respective state load despatch centre (SLDC). SLDC shall forward the request for shutdown along with their consent and observation as per Format V to RLDC. 6.6.2. In all other cases, the request for transmission element outage shall be submitted to respective RLDC. 6.6.3. RLDC shall study the impact of proposed outages and approve / refuse the outage latest by 1200 Hrs of D-1 day. A copy of the

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approval / refusal shall also be sent to NLDC (for 400 kV and above lines). A suggestive format for approval / refusal of outage is enclosed as Format VI. 6.6.4.

In case the outage is approved precautions/measures to be observed during the shutdown shall be stated. In case of refusal, clear reasons shall be stated by the SLDCs/RLDC

6.6.5. Outages in the same corridor shall not be approved simultaneously shall be rescheduled accordingly.

6.7.

Approval of Outage where Approving Authority is SLDC

6.7.1. SLDC shall study the impact of proposed outages on the system and approve the outage latest by 1200 Hrs of D-1 day. The format VI as suggested above can be used for approval / refusal of outage. 6.7.2. Outages in the same corridor shall not be approved simultaneously and shall be rescheduled accordingly. 6.8.

In case of any system constraint or any other reason, approving authority may decline the proposed outage by giving the reasons for the same and tentative dates for the shutdown.

6.9.

In case, any approved outage is not availed in real time, the same may not be allowed again in that month. In such a scenario, indenting agency shall be required to submit a fresh proposal in the next OCC meeting.

6.10. A list of all approved outages for the next day must be available in the RLDCs/NLDC control room by 1900 hours with a copy of the study results and special precautions, if any. This would be studied by the night shift engineers so that the outage can be facilitated the next day morning.

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7. Approval of Emergency Outages 7.1.

All outages which are not approved in the OCC meeting but having impact on human and equipment safety and/or to meet any other emergency requirement or special conditions shall be considered under Emergency Outage category.

7.2.

The request for emergency outage shall be submitted along with the details like nature of emergency, impacts due to emergency situation, reasons and associated facts for not considering in the outage planning process.

7.3.

Emergency outages shall be allowed subject to system conditions and its severity. In this case, if required, planned outage may be deferred, if possible.

7.4.

Emergency outages shall be allowed immediately or within the short possible time, based on the severity of the emergency and system condition on instance to instance basis.

8. Availing Outages in real time 8.1.

The agencies involved shall ensure availing of outages as per the approved schedule time.

8.2.

On the day of outage, the outage availing agency shall seek the code for availing outage from respective RLDC(s) /NLDC (wherever applicable). The agencies involved shall endeavour to avail the outage with in 15 mintues of availing the code but not later than 30 minutes. In case, due to any contingency, the outage could not be availed within 30 minutes, a fresh code needs to be obtained by all concerned agencies stating the reason there of Record of scheduled and actual time of outage and restoration shall be maintained at RLDCs/NLDC.

8.3.

RLDCs shall prepare a monthly statement of scheduled and actual time of outage and restoration and forward the same to RPC latest

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by 05th day of the next month with a copy to NLDC. The format is enclosed as Format VIIA / Format VIIB. 8.4.

SLDCs shall prepare a monthly statement of scheduled and actual time of outage and restoration and forward the same to RPC latest by 05th day of the next month with a copy to concerned RLDC. The Format VIIA / Format VIIB as suggested above can be used for sending the report to RPCs.

8.5.

RLDCs/NLDC shall develop a separate web based portal for information exchange subsequently, which would dispense with the need for emails.

8.6.

As any deviation in the outage from the schedule can affect other planned outages as well as affect reliability and electricity markets, indenting agency must strictly adhere to the shutdown timings.

9. Normalisation of Outages 9.1.

All effort shall be made by the Indenting agency to normalise the shut down within approved time period so that the transmission element is normalised within the approved time period.

9.2.

On completion of the outage work, the outage availing agency shall seek the code for normalisation of elements from respective RLDC(s). The agencies involved shall endeavour to normalise the outage with in 15mintues of availing the code but not later than 30minutes. In case, due to any contingency, the normalisation could not be done with in 30minutes, a fresh code needs to be obtained by all concerned agencies stating the reason thereof.

9.3.

In case of extension of a shutdown, the Indenting agency would furnish the reasons of extension, and expected normalisation time to concerned RLDC/SLDC at least one hour before the scheduled normalisation time.

9.4.

Under such circumstances SLDCs/RLDCs/NLDC shall review the impact of such delay on the shutdown already approved

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transmission system and would reserve the right to review for according/cancellation of the shutdown. 9.5.

In case of repeated delay in normalisation of outages by any agency, the same shall be reported by SLDCs/RLDCs/NLDC to RPCs.

10. Request for charging new elements 10.1. Owner of the transmission asset shall submit the request for probable charging new elements for the next calendar month latest by 3rd day of the current month to the RPC Secretariat. 10.2. System Study sub-committee of RPCs shall study the impact of charging of new elements and based on its recommendations, RPC shall discuss the requests for charging new elements in the OCC meeting and prepare a list of new elements to be charged during the next calendar month along with the precautions to be taken. RPC shall send the list of new elements to be charged within 3 days of the OCC meeting and latest by 18th of the month. The same shall also be displayed on RPC websites. 10.3. The owner of the new transmission element shall inform the concerned SLDC / RLDC / NLDC about the charging of the element atleast 3 days in advance. 10.4. SLDCs / RLDCs / NLDC shall study the charging of all 400 kV and above new elements and prepare charging instructions which shall be forwarded to the asset owner along with the study results with a copy to NLD

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List of Formats 1

Format IA

Request For Transmission Element Outage

Indenting Agency

RPC

2

Format IB

Request For Bus, Bay, ICTs, Reactor, FACTS, FSCs, SVCs etc Outage

Indenting Agency

RPC

3

Format IIA

List of monthly proposed shutdowns of Transmission Lines

RPC

Website

4

Format IIB

List of monthly proposed shutdowns of Bus, Bay, ICTs, Reactor, FACTS, FSCs, SVCs etc

RPC

Website

5

Format IIIA

List of monthly approved shutdowns of Transmission Lines

RPC

NLDC/RLDC/SLDC

6

Format IIIB

List of monthly approved shutdowns of Bus, Bay, ICTs, Reactor, FACTS, FSCs, SVCs etc

RPC

NLDC/RLDC/SLDC

7

Format IV

Request for Transmission Element Outage

Indenting Agency

RLDC/SLDC

8

Format V

RLDC

NLDC

9

Format VI

Request for Transmission Element Outage Approval of Outage

RLDC / NLDC

Indenting Agency/RLDC

10

Format VIIA

Monthly Shutdown Report For Transmission Lines

SLDC/RLDC RPC

11

Format VIIB

Monthly Shutdown Report For For Bus, Bay, ICTs, Reactor, FACTS, FSCs, SVCs etc

SLDC/RLDC RPC

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Annexure X -UFR and df/dt settings ANNEXURE X All India UFR Status Region

NR

WR

STATES

48.8 Hz

48.6 Hz

48.2 Hz

Total

Punjab

180

220

400

800

Haryana

110

140

350

600

Rajasthan

120

150

425

695

Delhi

110

140

350

600

UP

190

240

475

905

Uttarakhand

30

30

100

160

HP

20

20

75

115

J&K

40

50

75

165

Chandigarh

0

10

0

10

Total*

800

1000

2250

4050

Gujarat

220

220

295

735

Chatisgarh

38

38

50

126

Maharashtra

550

550

730

1830

MP

152

152

205

509

Total

960

960

1280

3200

Bihar

88

82

123

293

Jharkhand

58

51

70

179

DVC

132

143

166

441

Odisha

161

159

210

529

WB( Incl CESC)

313

285

430

1028

Total

752

719

998

2469

48.8 Hz

48.5 Hz

48.2 Hz

Total

Arunachal Pradesh

3.5

3.5

3.5

10.5

Assam

35.8

15

20

70.8

Nagaland

3

3

3

9

Mizoram

5.1

5.1

5.1

15.3

Meghalaya

8

8

10

26

Tirupura

8

7

7

22

Manipur

5

STATES

NER

Total

68.4

5 41.6

48.6

Total for NEW Grid STATES

SR

158.6

9878 49 Hz

48.8 Hz

48.6 Hz

Total

Andhra Pradesh

887

1256

1424

3567

Karnataka

718

895

732

2345

Kerala

215

300

342

857

Pondicherry

21

36

36

93

48.8 Hz

48.5 Hz

48.2 Hz

Total

835

1036

1208

3079

2676

3523

3742

9941

Tamilnadu

Total for SR Grid ALL India Level

19819

* All the constituents would plan for 20% more quantum than the agreed for achieving full planned relief from UFRs as per24th TCC and 27th NRPC NLDC July 2013-Rev 0 meeting decision dt. 10-11-2012. NLDC Operating Procedures for National Grid July 2013 Rev 0 129 of 198

Annexure X -UFR and df/dt settings

ANNEXURE X AUTOMATIC UNDER FREQUENCY LOAD SHEDDING SCHEME IN NR State wise load relief to be provided by UFRs in NR is as given below:

STATES

Punjab Haryana Rajasthan Delhi UP Uttarakhand HP J&K Chandigarh TOTAL *

Peak MW Met 48.8 Hz 2008-09 7309 4791 6101 4034 8248 1267 1014 1380 279 29504

180 110 120 110 190 30 20 40 0 800

Load Relief in MW 48.6 Hz 48.2 Hz

220 140 150 140 240 30 20 50 10 1000

400 350 425 350 475 100 75 75 0 2250

Total

800 600 695 600 905 160 115 165 10 4050

* All the constituents would plan for 20% more quantum than the agreed for achieving full planned relief from UFRs as per24th TCC and 27th NRPC meeting decision dt. 10-11-2012. State wise load relief of df/dt relays is as given below.

STATES Punjab Haryana Rajasthan Delhi UP Uttarakhand HP J&K Chandigarh TOTAL

NLDC NLDC

Stage-I 49.9 Hz & 0.1 Hz/sec 430 280 330 250 500 70 50 90 0 2000

Load Relief in MW Stage-II Stage-III 49.9 Hz & 0.2 49.9 Hz & Hz/sec 0.3 Hz/sec 490 310 370 280 280 70 70 90 50 2010

490 310 370 280 280 70 70 90 50 2010

Total 1410 900 1070 810 1060 210 190 270 100 6020

Operating Procedures for National Grid Operating Procedures for National Grid 130 of 198

July

2013-Rev 0

July 2013 Rev 0


ANNEXURE X AUTOMATIC UNDER FREQUENCY LOAD SHEDDING SCHEME IN WR Discrete Relays (AUFLS) UFR Setting (Hz)

Time delay (Sec.)

Recommended Load Relief for WR (MW)

48.8

Inst.

48.6

Load Relief (MW) GETCO

MPPTCL

CSEB

MSETCL

960

220

152

38

550

Inst.

960

220

152

38

550

48.2

Inst.

1280

295

205

50

730

Total

Inst.

3200

735

509

126

1830

Excludes load relief of Mumbai system under AUFLS (which is around 20% of MSETCL system)

Frequency Trend Relays (df/dt relays)

Settings (Hz/Sec)

Recommended Load Relief for WR (MW)

Implemented Load Relief (MW)

REGION

GETCO

MPPTCL

MSETCL

Mumbai

CSEB

49.2/0.4 (St-III)

2472

1001

392

686

273

120

49.0/0.2 (St-II)

2212

1001

393

687

91

40

48.8/0.01 (St-I)

3023

1521

546

825

91

40

Total

7707

3523

1331

2198

455

200

`

NLDC

NLDC



July 2013-Rev 0

July 2013 Rev 0


ANNEXURE X AUTOMATIC UNDER FREQUENCY LOAD SHEDDING SCHEME IN SR AUFR Settings: Presently available AUFR settings in Southern Region Grid are as follows: Frequency setting Load Relief (MW)

Andhra Pradesh Karnataka Kerala Pondicherry Total

Frequency setting Load Relief (MW)

Tamilnadu

Stage-1 49 Hz 887 718 215 21 1841 Stage-1 48.8 Hz

Stage-2 48.8 Hz 1256 895 300 36 2487 Stage-2 48.5 Hz

Stage-3 48.6 Hz 1424 732 342 36 2534 Stage-3 48.2 Hz

835

1036

1208

Total SR

Total 3567 2345 857 93 6862 Total 3079 9941

df/dt Settings: ALARM: Frequency <= 49.5 Hz and 0.3 Hz/sec fall of frequency (df/dt) Trip: Frequency <=49.3 Hz and 0.3 Hz/sec fall of frequency (df/dt) AUFR Settings: Presently available AUFR settings in Southern Region Grid are as follows: Setting

Load Relief (MW)

Setting Load Relief (MW)

NLDC NLDC

ALARM: Frequency <= 49.5 Hz and 0.3 Hz/sec fall of frequency (df/dt) Trip: Frequency <=49.3 Hz and 0.3 Hz/sec fall of frequency (df/dt)

Andhra Pradesh Stage B Karnataka Tamilnadu Kerala Total

1635 901 559 175 3270

ALARM: Frequency <= 49.8 Hz and 0.2 Hz/sec fall of frequency (df/dt) Trip: Frequency <=49.5 Hz and 0.2 Hz/sec fall of frequency (df/dt)

Andhra Pradesh Stage A Total SR

714 3984


July

2013-Rev 0

July 2013 Rev 0


ANNEXURE X AUTOMATIC UNDER FREQUENCY LOAD SHEDDING SCHEME IN ER

Constituents BSEB JSEB DVC OPTCL WB ( Incl CESC) TOTAL

NLDC NLDC

ALL FIG ARE IN MW. Stage-I (48.8 Hz, Inst. .) Stage-II (48.6 Hz, Inst. .) Stage-III (48.2 Hz, Inst. .) Emergency Agreed Actual Agreed Actual Agreed Actual (47.6 Hz, Inst.) 80 88 80 82 115 122.5 Nil 50 58 50 51 70 70 Nil 110 132.4 110 142.7 155 166.1 213 150 160.5 150 158.5 208 209.5 Nil 285 675

313 751.9

285 675

285 719.2

397 945


430 998.1

220 433

July 2013-Rev 0 July 2013 Rev 0


ANNEXURE X AUTOMATIC UNDER FREQUENCY LOAD SHEDDING SCHEME IN NER Sl. No 1

2

Name of States Ar. Pradesh

Assam

Name of feeder where UFR Installed 11 KV Banderdewa – Satyam Ispat

i) 132 KV Garmur (Jorhat – I) ii) 220 KV Samaguri (Rupahi) iii) 132 KV Panchgram (Hailakandi) iv) 132 KV Dhaligoan (Chapaguri)

Stage-wise & Frequency setting

Peak Load

Off – Peak Load

Stage – I (48.8 Hz)

3.5 MW

3.5 MW

Stage – II (48.5 Hz) Stage – III (48.2 Hz) Stage – I (48.8 Hz)

3.5 MW 3.5 MW 13 MW 8 MW

3.5 MW 3.5 MW 8 MW 6 MW

7 MW

5 MW

7.8 MW

4.5 MW 23.5 MW 4 MW 5 MW 9 MW 15 MW 5 MW 5 MW 5 MW 5 MW

220 KV Samaguri (Mirza) 33 kV Yurembum-Leimakhong 33 KV NEHU – Happy Valley 33 KV Nongstoin - Mairang 33 KV Rongkhon - Garobadha

Stage – I (48.8 Hz) Stage – I (48.8 Hz) Stage – II (48.5 Hz) Stage – III (48.2 Hz)

35.8 MW 8 MW 7 MW 15 MW 20 MW 5 MW 8 MW 8 MW 10 MW

33/11 KV Lower SS at Zuangtui

Stage – I (48.8 Hz)

5.1 MW

3.1 MW

33/11 KV Lower SS at Zuangtui

Stage – II (48.5 Hz)

5.1 MW

3.1 MW

33/11 KV Lower SS at Mualpui

Stage – III (48.2 Hz)

5.1 MW

3.1 MW

i) 132 KV Depota (Jamaguri) ii) 220 KV Mariani (Teok)

Total of Stage - I Stage – II (48.5 Hz) Total of Stage - II

3 4

Manipur Meghalaya

5

Mizoram

Quantum of load relief

6

Nagaland

132/66/33 KV Mokokchung SS 132/66/33 KV Nagarjan SS 132/66/33 KV Kohima SS

Stage – I (48.8 Hz) Stage – II (48.5 Hz) Stage – III (48.2 Hz)

3 MW 3 MW 3 MW

3 MW 3 MW 3 MW

7

Tirupura

33 KV Mohan Pir Feeder 33 KV Badharghat Feeder 33 KV Durjoy Nagar Feeder

Stage – I (48.8 Hz) Stage – II (48.5 Hz) Stage – III (48.2 Hz)

8 MW 7 MW 7 MW

8 MW 7 MW 7 MW

NLDC NLDC

Operating NationalGrid Grid OperatingProcedures Procedures for for National 134 of 198

July 2013-Rev July 2013 Rev 0 0


NLDC


July 2013 Rev 0

Annexure XI - SPS ANNEXURE XI

System Protection Schemes-All India level

1.

SUMMARY OF SYSTEM PROTECTION SCHEMES (SPS) All System protection schemes are proposed, discussed and getting approved in RPC meetings such as OCC, protection, TCC and RPC Board meetings. SPS which are approved, implementation is yet to commence and SPS which are proposed are in discussion stage. The Summary of System protection schemes both inter/Intra regional which are in service, and no of schemes Approved are detailed below SL. NO

REGION

No. of Schemes In service

No. of Schemes approved (yet to be operationalized)

No of schemes under discussion

1

NORTHERN REGION

12

15

1

2

EASTERN REGION

3

1

1

3

WESTERN REGION

4

2

3

4

SOUTHERN REGION

15

6

5

NORTH EASTERN REGION

1

TOTAL

35

Remarks Inclusive of ER-NR and WR-NR corridors Inclusive of ER-SR corridor Inclusive of WR-NR corridor Inclusive ER-SR corridor

1

24

6

65

The System protection schemes for Inter / intra-regional corridor (Region wise) divided in to three categories as stated below. i) SPS related to tripping of critical line / corridor

NLDC

ii)

SPS related to safe evacuation of Generation

iii)

SPS related to overloading of Transformers


-SPS -

July 2013-Rev 0

1

Annexure XI - SPS The Summary of SPS both inter/Intra regional which are in service, and no of schemes yet to be operationalized based on the following categories are detailed below S. Region No

Tripping of critical line(s) / corroder

Safe evacuation of generation

Overloading of transformers

In Under In Under In Under Approved Approved Approved TOTAL service discussion service discussion service discussion 1 Northern

6

4

2

Eastern

2

1

3 Western

1

2

4 Southern

5

4

5

North Eastern

1

TOTAL

15

1

1

1

5

-

5

6

1

1

5

3

2

9

6

4

2

1 11

3

28

21 2

11

5

3

9

8

65

Also the System protection schemes for inter/ intra-regional corridor (Region wise) categorised as stated below i) SPS related to Generation rejection

NLDC

ii)

SPS relate to Load rejection

iii)

SPS related to generation /load rejection

iv)

SPS related to HVDC controls

v)

SPS related to others


-SPS -

July 2013-Rev 0

2

Annexure XI - SPS

2.

SPS in Northern Region

SL. NO

Name of the Scheme

Implementi ng Agency

Status

Approved date

Remarks

Category type

SPS related to tripping of critical line / Corridor

In service

WRPC identified Korba, Vindhyachal, APL Mundra for 27-11-2010 backing down where wide band communication is available.

Load/ generation rejection

Adani power

In service

Partially implemented further Load 13-07-2012 shedding at NR needs to be identified.

Load Rejection

3

SPS for ER-NR corridor SPS for high capacity 400 kV MuzaffarpurGorakhpur D/C Inter-regional tie line related contingency

CTU

In service

15-12-2006

Implemented


4

SPS for 1500 MW HVDC RihandDadri Bipole related contingency

CTU

In service

29-06-2005

Implemented

Generation Rejection

5

SPS for HVDC Balia-Bhiwadi (phase I) single pole outage contingency


6

SPS for reliability of Uttarakhand power system (400 kV MoradabadKashipur)


1

2

7

NLDC

SPS for WR-NR corridor 400kV AgraGwalior & 1& 2 SPS for WR-NR corridor SPS for contingency due to tripping of HVDC MundraMahendergarh

SPS for HVDC Balia-Bhiwadi Bipole (phase II)

CTU

CTU

In service

15-04-2010

Backing down of generation is yet to be finalised in ER

PTCUL

In service

27-11-2010

Implemented

Approved

ERPC had forwarded its comments to 27-11-2010 NRPC proposing for backing down of generation, if

CTU


-SPS -


July 2013-Rev 0

3

Annexure XI - SPS SL. NO

Name of the Scheme


Status

Approved date

Remarks

any from KhSTPS-II and Barh STPS of NTPC only, instead of their proposal from FSTPS & KhSTPS-I. NTPC desired that this scheme be co-ordinated with islanding scheme being finalized for Delhi. NTPC agreed to submit the breakup 27-11-2010 details of the backing down at Dadri Th & CCGT. NRLDC in coordination with NRPC, NTPC has studied to re establish the requirement of SPS.

Category type

8

SPS for contingency due to tripping of multiple lines at Dadri

CTU

Approved

9

SPS for contingency due to multiple tripping at Bawana

CTU/DTL

Approved

27-11-2010

Review of SPS under discussion

Load rejection

10

SPS for 220 kV Salal- Jammu D/C outage contingency

CTU

Approved

27-11-2010

No information from PDD, J&K

Load rejection

Approved (Yet to be SPS Proposed for 11 CTU/PDD discussed Kashmir Valley in RPC meeting) SPS related to Safe evacuation of generation SPS for reliable evacuation of power from NJPS Karcham/ 12 In service and Baspa H.E.P Jhakri and Karcham wangtoo 13

NLDC

SPS for Reliable Evacuation of Ropar Generation

PSTCL/ PSPCL

Approved

A committee 13-01-2013 formed and approved.

04-02-2011

Work transferred from PSTCL to 27-11-2010 Ropar TPS. In May 2013 SPS


Implemented

-SPS -


Load rejection

Generation rejection


July 2013-Rev 0

4


Name of the Scheme


14

SPS for Reliable Evacuation of Paricha TPS Generation

15

SPS for Reliable Evacuation of Panipat TPS stage I & II Generation

16

SPS for Reliable Evacuation of Rosa Generation

17

SPS for contingency due to tripping of evacuating lines from Narora Atomic Power Station

Status

UPPTCL/U PVUNL

HVPNL/ HPGCL

UPPTCL/ Rosa TPS

UPPTCL

Approved

Approved date

Remarks

installed and commissioning in progress. Tender floated for procurement of 27-11-2010 SPS.

Category type


Approved

HVPNL intimated that HPGCL has decided not to 27-11-2010 install the SPS. SPS has been referred to CEA.


Approved

Approval of UPPTCL for 27-11-2010 installation of SPS at Rosa TPS expected.


Approved

As no response has been received for the tender enquiry floated, retendering has 11-05-2012 been done for procurement of SPS. Expected date of commissioning Sep 2013.



18

SPS for Transformers at Ballabgarh (PG) substation

CTU

In service

27-11-2010

Implemented

Load rejection

19

SPS for Transformers at Maharanibagh (PG) substation

CTU

In service

27-11-2010

Implemented

Load rejection

20

SPS for Transformers at Mandola (PG) substation

CTU

In service

27-11-2010

Implemented

Load rejection

NLDC


-SPS -

July 2013-Rev 0

5


Name of the Scheme


21

SPS for Transformers at Bamnauli (DTL) Substation

DTL

Status

Approved date

In service

27-11-2010

Remarks

Implemented

SPS at Bhiwadi dropped as with the commissioning of 27-11-2010 additional ICT, overloading of ICTs is not being experienced. RRVPNL has informed POWERGRID on 10.05.2013, a fresh list of 17 27-11-2010 feeders at 132 kV level having available load of 320MW for SPS of ICTs at Bassi.

22

SPS for Transformers at Bhiwadi(PG) substation

CTU

Approved

23

SPS for Transformers at Bassi(PG) substation

CTU

Approved

24

SPS for Transformers at Bawana (DTL) Substation

DTL

In service

27-11-2010

25

SPS for Transformers at Moradabad (UPPTCL) Substation

UPPTCL

Approved

27-11-2010

26

SPS for Transformers at Muradnagar (UPPTCL) Substation

UPPTCL

Approved

27

SPS for Transformers at Agra (UPPTCL)S/S

UPPTCL

Approved

As no response has been received for the tender enquiry floated, 27-11-2010 retendering has been done for procurement of SPS. Expected date of commissioning Sep 2013. 27-11-2010

28

SPS for Transformers at Bareilly (UPPTCL)SS

UPPTCL

Approved

27-11-2010

NLDC


Implemented

-SPS -

Category type Load rejection

Load rejection

Load rejection

Load rejection

Load rejection

Load rejection

Load rejection

Load rejection

July 2013-Rev 0

6

Annexure XI - SPS SPS of I/R regional link, HVDC llinks and some important Intra regional links are explained here. For all other SPS details, please refer respective RLDCs Operating Procedures.

SPS for WR-NR corridor - 765kV Agra-Gwalior & Bina-Gwalior

Case Case-1

Contingency

Action

Reduction of import by NR on 765 kV Agra-Gwalior ckt-I & II by more than 1000 MW but less than 1500 MW

Shed loads in Groups C and D in the Northern Region Action-1 Shed Loads in Groups C, D, E and F Action-2 Automatically back down 500 MW generation in Western Region in the shortest possible time

Case-2

Reduction of import by NR on 765 kV Agra-Gwalior ckt-I & II by more than or equal to 1500 MW

Case-3

Total steady state flow on 765 kV Gwalior to Agra in case both ckt is in service more than 2000 MW or b. flow on 765kV from Gwalior to Agra when only one ckt is in service more than 1500 MW for a period of 2 seconds OR Steady State voltage at 400/765 kV Agra less than 380 kV / 730 kV respectively for a period of 2 (two) seconds

Shed load in Group C and D

Remark: 1. The envisaged automatic backing down of generation in the WR for Case-2 is yet to be implemented. 2. Load Shedding shall be achieved within 500 ms, including all signal propagation/breaker opening time delay 3. Load shedding in Western Uttar Pradesh, Rajasthan, Punjab and Haryana area

NLDC


-SPS -

July 2013-Rev 0

7

Annexure XI - SPS

Fig 1 Load Details

NLDC


-SPS -

July 2013-Rev 0

8

Annexure XI - SPS SPS for ER-NR corridor SPS for high capacity 400 kV Muzaffarpur-Gorakhpur D/C Inter-regional tie line related contingency The 400 kV Muzaffarpur-Gorakhpur D/C is an important tie line between ER and NR. SPS Scheme logic:

Case-1 Contingency: Flow >1200 MW (ER to NR, measured at Gorakhpur) & D/C trips Action-1: Immediately Shed Loads in Groups in Groups A and D (of Fig 1 Load Details). Action 2: Ramp up the power flow from West to North by 100 MW (variable) to Northern Region through HVDC back-to-back stations at Vindhyachal at the maximum ramp rate possible (300 MW/Sec). Case-2 Contingency: Flow >1800 MW (ER to NR, measured at Gorakhpur) & stays above this value for more than 5 seconds. Action-1: Immediately Shed Loads in Groups in Groups C and D (of Fig 1 Load Details). Action 2: Ramp up the power flow from West to North by 100 MW (variable) to Northern Region through HVDC back-to-back stations at Vindhyachal at the maximum ramp rate possible (300 MW/Sec). Load Shedding shall be achieved within 500 ms, including all signal propagation/breaker opening time delay

NLDC


-SPS -

July 2013-Rev 0

9

Annexure XI - SPS SPS for WR-NR corridor SPS for contingency due to tripping of HVDC Mundra-Mahendergarh

Case-1 Contingency

Action-1

Action-2

Blocking of (one pole or Bipole) AND Reduction in power injection at Mahendergarh by more than 600 MW and upto 900 MW

Generation reduction of equivalent amount in Mundra Stage-III (WR) through the run back scheme

Shed 300 MW identified load in Northern Region within 500 ms (including all signal propagation / breaker opening time delay) Haryana: 150 MW, Punjab:50 MW, Rajasthan: 50 MW, UP: 50 MW

Case-2

Action-1

Action-2

Blocking of (one pole or Bipole) AND Reduction in power injection at Mahendergarh by more than 900 MW and upto 1250 MW


Shed 600 MW load identified in Northern Region within 500 ms (including all signal propagation / breaker opening time delay) Haryana: 300 MW, Punjab:100 MW, Rajasthan: 100 MW, UP: 100 MW

Case-3

Action-1

Action-2

Blocking of Bipole AND Reduction in power injection at Mahendergarh by more than 1250 MW and upto 2000 MW


Shed 1400 MW load identified in Northern Region within 500 ms (including all signal propagation / breaker opening time delay) Haryana: 600 MW, Punjab:200 MW, Rajasthan: 200 MW, UP: 200 MW, Delhi: 200 MW

Case-4

Action-1

Action-2

Blocking of Bipole AND Reduction in power injection at Mahendergarh by more than 2000MW


Shed 1900 MW load identified in Northern Region within 500 ms (including all signal propagation / breaker opening time delay) Haryana: 700 MW, Punjab:300 MW, Rajasthan: 300 MW, UP: 300 MW, Delhi: 300 MW

Load Details for tripping of HVDC Mundra-Mahendergarh

NLDC


-SPS -

July 2013-Rev 0

10

Annexure XI - SPS

NLDC


-SPS -

July 2013-Rev 0

11

Annexure XI - SPS Implemented System Protection Scheme (SPS) for HVDC Balia-Bhiwadi Bipole

Case

Case-1

Case-2

Case-3

Case-4

Contingency

Action

Tripping of pole resulting in power order reduction by more than 500 MW and upto 750 MW. (Measured at Bhiwadi)

Tripping of pole resulting in power order reduction by more than 750 MW and upto 1500 MW. (Measured at Bhiwadi)

Tripping of poles resulting in power order reduction above 1500 MW and upto 2000 MW.(Measured at Bhiwadi)

Tripping of poles resulting in power order reduction above 2000 MW. (Measured at Bhiwadi)

Shed Loads in Groups C & D (of Fig 1 Load Details). Action-1 Shed Loads in Groups A, B, C & D as Described (of Fig 1 Load Details). Action-2 Automatically back down generation by 250 MW at Singrauli-Rihand complex in Northern region and by 250 MW in the Eastern region at Kahalgaon in the shortest possible time Action-1 Shed loads in Groups A, B, C, D, E & F (of Fig 1 Load Details). Action-2 Automatically back down generation by 750 MW at Singrauli-Rihand complex in northern region and by 750 MW in the eastern region at Kahalgaon/ Barh/ Farakka in the shortest possible time. Action 1 Shed loads in Groups A, B, C, D, E, F & G(of Fig 1 Load Details). Action 2 Automatically back down generation by 750 MW at Singrauli-Rihand complex in northern region and by 750 MW in the eastern region at Kahalgaon/ Barh/ Farakka in the shortest possible time.

Remark: 1. The envisaged automatic backing down of generation in the Singrauli-Rihand complex for Case-2 is yet to be implemented. 2. Load Shedding shall be achieved within 500 ms, including all signal propagation/breaker opening time delay

NLDC


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July 2013-Rev 0

12

Annexure XI - SPS SPS for 1500 MW HVDC Rihand-Dadri bipole related contingency: The 1500 MW HVDC Rihand-Dadri bipole is the major high capacity link between the pit head generating stations in south – east part of northern region (NR) and the load centres in the central and western part of NR. Outage of this high capacity link results in overloading of the parallel AC network. In order to take care of any contingency due to outage of this high capacity link, scheme has been developed to carry out the automatic backing down of generation at the sending end and load shedding at the receiving end. For the purpose of load shedding the loads have been distributed in different groups say group- A, B, C & D. Details of the corrective action logic for different cases are as explained below.

SPS Scheme logic: Case-1 Contingency: Tripping of any or both poles resulting in power order reduction by 750 MW and above. Action 1: Immediately Shed Loads in Groups A, B, C & D.( Fig 1 Load Details) And Action 2: Reduce generation at Singrauli/Rihand by 500 MW in the fastest possible time And Action 3: Ramp down the power flow from West to North by 100 MW (variable) at Vindhyachal HVDC station at the maximum rame rate possible ( 300 MW/Sec) Case-2 Contingency: Tripping of any or both poles resulting in power order reduction above 500MW but less than 750MW .

Action 1: Immediately Shed Loads in Groups C & D .( Fig 1 Load Details) And Action 2: Ramp down the power flow from West to North by 100 MW (variable) to Northern Region through HVDC back-to-back stations at Vindhyachal at the maximum ramp rate possible (300 MW/Sec).

NLDC


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July 2013-Rev 0

13

Annexure XI - SPS

Figure 2 : Load details for HVDC Rihand-Dadri SPS

NLDC


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July 2013-Rev 0

14

Annexure XI - SPS SPS for reliable evacuation of power from NJPS and Baspa H.E.P and Karcham wangtoo Scheme logic Case

Contingency

Action

Case-1

Load on any of the lines at Jhakri exceeds 800 MW

Trip 2 units of Wangtoo HPS

Case-2

400 kV bus voltage at Wangtoo drops below 395 kV


Case-3

Any two lines of Jhakri

Case-4

Both 400 kV Wangtoo-Abdullapur lines at Wangtoo trip

NLDC

Trip 2 units of Jhakri and 2 units of Wangtoo HPS



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July 2013-Rev 0

15

Annexure XI - SPS SPS RELATED TO OVERLOADING OF INTERCONNECTING TRANSFORMERS SPS Scheme general logic: The SPS would shed load in groups depending on no. of ICTs in operation. In order to achieve it, loads for shedding by SPS would be divided into number of groups. The no. of groups would be one less than the no. of transformers operating in parallel. Count the no. of ICTs operating in parallel Case

Contingency

Action

Case-1

Loading on the ICT is more than 85 % and no. of ICTs operating in parallel is 4 and 1 out of these 4 ICT trips

Shed load in one of the identified groups

Case-2



Case-3



Scheme Ref

Location

Transformation Capacity

Identified feeders for tripping

SPS/NR/TRF/01

Ballabgarh

4 x 315 MVA = 1260 MVA

220kV Samaypur-Palwal ckt-1 220kV Samaypur-Palwal ckt-2

SPS/NR/TRF/02

Maharanibagh

2x315 + 2x500 MVA = 1630 MVA

220kV Maharanibagh -Masjid Moth ckt-1 220kV Maharanibagh - Sarita vihar 220kV Maharanibagh -AIIMS Trauma center ckt-1 220kV Maharanibagh - Electric lane

SPS/NR/TRF/03

Mandaula

4 x 315 MVA = 1260 MVA

220kV Mandola-Gopalpur 220kV MandolaNarela ckt-1&2

SPS/NR/TRF/04

Bamnauli

4 x 315 MVA = 1260 MVA

220kV Bamnauli-Papankalan ckt-1 220kV Bamnauli-Papankalan ckt-2

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Annexure XI - SPS

3. SPS in Eastern Region SL . N O

Name of the Scheme


Status

Date

Remarks

Category type


1

SPS for corridor

ER-SR

NTPC

In service

Implemented


SEL

In service

Implemented


Approved

Confirmation yet to be received from SEL


Under Discussion


SPS for Talcher – Kolar HVDC Bipole at Talcher end

2

3

SPS for Sterlite Energy Limited (SEL)

Modified SPS for SEL

SEL

16-11-2012

SPS related to Safe evacuation of generation

4.

Interim arrangement for evacuation of TEESTA –III generation

NHPC

In service

5

SPS for Chuzachen Generation Unit

GatiInfrastructu re

Under Discussion

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Annexure XI - SPS SPS for Talcher – Kolar HVDC Bipole - SPS at Talcher (SPS 450 & SPS 1000) Talcher Super thermal power station having a capacity of 3000MW( 6x500 MW) is located in Orissa of Eastern Region. The station was commissioned with 2x500MW capacity and subsequently its second stage was commissioned and station capacity was augmented to 3000MW with commissioning of its further 4x 500MW machines. The station is the largest capacity station in the region. However, the capacity of the entire stage II ( 4x500 MW) was allocated to the beneficiaries of southern region. Subsequently, 10% of the capacity was allocated to the Orissa, in Eastern region. For evacuation of Talcher STPS –II generation to Southern Region, +/- 500kV HVDC bipole transmission system was commissioned right upto the load centre of Southern Region at Kolar. The HVDC substation at Talcher has two pole blocks 1000MW capacity each(subsequently augmented to 1250MW ). The very basic design of the evacuation system of Talcher stage II to SR poses a major threat to Eastern Region and subsequently to the New Grid as any sudden forced outage of one or both the poles would mean that Eastern Grid has to initially absorb a jerk of load throw off to the tune of 18002000MW . The surplus power would get wheeled through Talcher-Rourkella 400kV D/C and Rengali – Baripada-Kolaghat S/C. During monsoon as such these corridors remain heavily loaded and such contingency of pole block at Talcher would lead to a definite cascade tripping leading to isolation /possible collapse of Orissa system including TSTPP station. In order to avoid such contingency two automatic special protection schemes were envisaged and have been implemented at Talcher Super Thermal power station. The 1st scheme as commonly known as SPS 450 was first implemented and subsequently a further improvised 2nd scheme was devised as known as SPS 1000 scheme. Both the schemes and their modalities of arming and disarming is described below: SPS 450: This scheme was originally implemented with a view that Eastern and Western Region would absorb a jerk of 450 MW therefore rest of the generation as available at Talcher stage II generation must be shed in order avoid a cascade tripping of the network. However, during monsoon, from Eastern Regional point of view at times absorbing even 450MW under N-1 contingency criteria of TalcherRourkella 400kV D/C Line becomes critical when major generation at Talcher stage II must be shed in order to avoid further criticality of the Grid. Further under any critical outage condition in the rest of the New Grid outage of HVDC bipole might pose a serious threat when it might necessitate arming of SPS 450 scheme with due coordination with NLDC. Under this mode of SPS the power injection to N-E-W grid is limited to 450 MW. The actual generation by the generators is considered for building the logic.

Logic for single pole tripping: This logic is based on the assumption that during the tripping of one pole of HVDC the other available pole will automatically ramp up to 1250 MW. The logic is built using power relays and the logic adopted is detailed below. One pole trips AND Total Power injected by generators is more than 1700 MW THEN Tripp one of the selected unit (Presently unit six selected) instantly Logic for Bipole tripping Presently this logic is built using power relays and the logic adopted is detailed below. If Both Poles trip

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Annexure XI - SPS AND Power injected by Generators is more than 1100 MW THEN Trip two nos of selected units( presently unit six and three are selected) IF The total power injected by the generators is still more than 550 MW for more than 250 milliseconds THEN Trip Unit 4 SPS 1000: Post formation of the NEW Grid this scheme was subsequently envisaged in order to minimise shedding of generation at Talcher STPP. The basic philosophy of this scheme is to absorb 1000MW in place of 450 MW as the Grid size increased. However, as one of the prerequisites for arming this scheme Eastern Regional operator has to ensure that sufficient evacuation margin( approx 1000 MW) is available at the AC evacuation system of TSTPP. Under this mode of SPS the power injection to N-E-W grid is limited to 1000 MW. The actual injection to the HVDC system (by measuring the flow on four a/c lines between TSTPS and Talcher HVDC station) is considered for building the logic. Under SPS 1000 scheme no generation shedding is required for a single pole tripping. For contingencies of both pole tripping and for single pole tripping with the HVDC system going to ground return mode, generation shedding will be done. Extent of generation shedding depends on the actual power flow through the HVDC link and to limit the actual injection to N-E-W grid to 1000 MW.

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Annexure XI - SPS

NLDC


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Annexure XI - SPS HVDC INTER TRIP SCHEME (SPS 1000) Sl number

Condition

Action

IF THE HVDC POWER FLOW IS MORE THAN 1600 MW & BOTH POLE BLOCKED

Unit 6

Trip

Unit 5

Unload by 150 MW

Unit 4

Unload by 150 MW

IF THE HVDC POWER FLOW IS BETWEEN 1450 MW TO 1600 MW & BOTH POLE BLOCKED

Unit 6

Trip

Unit 5

Unload by 150 MW

Unit 4

No effect

IF THE HVDC POWER FLOW IS MORE THAN 1600 MW & ONE POLE BLOCKED WITH REMAINING POLE ON GROUND RETURN MODE

Unit 6

Trip

Unit 5

Unload by 150 MW

Unit 4

No effect


Unit 6 Unit 5

Unload by 150 MW Unload by 150 MW

Unit 4

Unload by 150 MW

Unit 6

Unload by 150 MW

Unit 5

Unload by 150 MW

Unit 4

Unload by 150 MW

Unit 6 Unit 5 Unit 4

Unload by 150 MW No effect Unload by 150 MW

Unit 6

Unload by 150 MW

Unit 5

No effect

Unit 4

Unload by 150 MW

Unit 6

Unload by 150 MW

8


Unit 5 Unit 4

No effect No effect

Unit 6

Unload by 150 MW

9

IF THE HVDC POWER FLOW IS MORE BETWEEN 1000 MW TO 1150 MW & ONE POLE BLOCKED WITH REMAINING POLE ON

Unit 5

No effect

Unit 4

No effect

1

2

3

4

5

IF THE HVDC POWER FLOW IS MORE BETWEEN 1450 MW TO 1600 MW & ONE POLE BLOCKED WITH REMAINING POLE ON GROUND RETURN MODE

6


7

IF THE HVDC POWER FLOW IS MORE BETWEEN 1300 MW TO 1450 MW & ONE POLE BLOCKED WITH REMAINING POLE ON GROUND RETURN MODE

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Annexure XI - SPS

4. SPS in Western Region SL. NO

Name of the Scheme

Implementin g Agency

Status

Date

Remarks

Category Type

SPS related to Safe evacuation of generation Implemented

1

SPS at LANCO (Pathadi)

2

SPS at JPL (TAMNAR)

3

SPS at Adani Power Ltd, MUNDRA

APL

In service

4

SPS at BALCO

M/s BALCO

Approved

Approved but still under discussion


5

SPS at 220kV Korba Complex

Approved



LANCO

In service

Aug 2010 Implemented

JPL

In service

Sep 2011 Implemented Aug 2011

Generation rejection Generation rejection Generation rejection

SPS related to tripping of critical line / Corridor 6

SPS at HVDC APL Bi-pole (2x1250MW) SPS for Tripping of Agra-Gwalior-Bina lines

APL

In service

CTU

Approved

CTU/ NTPC /Lanco/ JPL

DD

Jul 2012

8

9

SPS for tripping 400 kV S/C Sugen-Vapi line and Vapi ICTs

NLDC

HVDC control

WRPC identified Korba, Vindhyachal, APL Mundra for backing down where wide band communication is available.


Approved



Approved

Under Implementation

7

SPS at Sipat Power Station for Tripping of 765kV Sipat-BilaspurSeoni line

Implemented


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Annexure XI - SPS

The SPS of Adani Power Ltd (APL), (4x330MW+5x660MW), MUNDRA WRLDC operating procedure may be referred for the remaining SPS schemes.  Adani Power Ltd, Mundra (4x330MW+5x660MW) has its generation and transmission scheme in 3 stages. The generation at APL, Mundra is as follows: Stage 1: 4X330MW=1320MW Stage 2: 2X660MW=1320MW Stage 3: 3X660MW=1980MW  The associated transmission scheme is as follows: Stage 1: 220kV Mundra-Nanikhakhar D/C 220kV Mundra-Tappar D/C 400kV Mundra-Hadala S/C 400kV APL-Versana-Hadala S/C 400kV Mundra-Sami-Dehgam D/C Stage 2: 400kV Mundra -Zerda 2X D/C Stage 3: 2X1250MW +/- 500kV APL,Mundra-Mohindergarh HVDC bipole. LILO of 400kV Bahadurgarh(PG)-Bhiwani (BBMB) 400kV Mohindergarh-Danauda D/C 400kV Mohindergarh Bhiwani D/C  All the generating units are synchronized and the transmission lines of stage-1 are commissioned and +/- 500kV HVDC at APL is under testing.  Special Protection Scheme was commissioned by APL for mitigating any contingency arising out of additional evacuation of generation from Unit#6 ,7,8&9 from APL, Mundra.

SPS settings

400kV APLVarsana Line and 400kV APL-Hadala Line

400kV MundraSami-Dehgam Line with FSC

400D/C MundraSami-Dehgam Line without FSC

Stage-1 :Alarm

500MW(680Amp) (Time Delay:10Sec)



#Stage-2

Above 600MW Backing down in 10minutes

*Stage-2a: Trip 330MW unit

700MW(960Amp) Time Delay:4Sec)



Stage-3: Trip 660MW unit(Unit5 to Unit-9)




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Annexure XI - SPS 5.

SPS in Southern Region The Details of System protection schemes of Southern region as detailed below are enclosed at Annexure IV

SL. NO

Name of the Scheme

Implementing Agency

Status

Date

Remarks

Category Type


1

SPS for ER-SR corridor SPS for Talcher – Kolar HVDC Bipole - at Kolar

CTU

In service

Implemented

HVDC control & Load rejection

2

SPS for HiriyurNeelamangala line

KPTCL

In service

Implemented

Load rejection

3

SPS at 220kV Neelamangala

KPTCL

In service

Implemented

Load rejection

4

SPS at Salem

TNEB

In service

Implemented

Load rejection

5

SPS at HVDC Kolar ( SPSExtension)

In service

HVDC Kolar Trip Signal 3 SPS was completed successfully on 05.06.2013

Load rejection

6

7

NLDC

SPS for 400kV Vijayawada-Nellore line

SPS for 220kV Chittur-Tiruvalam

CTU

CTU

APTRANSCO

Approved

Approved

As there was no generation by IPPs in Vemagiri Complex and there was no progress in implementation.It 09.07.10 was suggested that if IPPs did not agree, the signal could be wired for tripping of the breakers at Vemagiri end. APTRANSCO informed that 18.07.20 SPS may get 12 delayed from the earlier schedule


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Load rejection

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Name of the Scheme

Implementing Agency

Status

Date

Remarks

Category Type

of August 2013.

8

SPS for 220kV SulurpetGummidipoondi

9

SPS for 400kV Nellore-Alamatti DC

APTRANSCO

CTU

Approved

18.07.20 Under 12 implementation

Approved

18.07.20 Under 12 implementation

Load rejection

Generation Backdown

SPS related to Safe evacuation of generation

APTRANSCO

In service

Implemented


SPS at Nagjheri Power House

KPTCL

In service

Implemented


12

SPS at UPCL

LANCO

In service

Implemented


13

SPS at Varahi

KPTCL

In service

Implemented


CTU

In service

Mock Exercise of Kudamkulam SPS Mechanism (Trip Signal 1 & 2) was completed successfully on 05.06.2013

Load rejection

KPTCL

In service

Implemented

Load rejection

10

SPS at Muddanur

11

14

SPS at Kudankulam APS

15

SPS at JSW

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Name of the Scheme

Implementing Agency

Status

Date

Remarks

Category Type


16

SPS for Madakathara ICT

KSEB

In service

Implemented

Load rejection

17

SPS for Hosur ICT

CTU

In service

Implemented

Load rejection

18

SPS for Mamidipalli ICT / Ghanapur ICT

APTRANSCO

In service

Implemented

Load rejection

19

SPS for Hoody ICT

KPTCL

In service

Implemented

Load rejection

20

SPS for Somanahalli and Mysore ICT

CTU

Approved

Under implementation.

Load rejection

21

SPS for Thirunelveli and Checkanoorani ICT

NLDC

CTU

Approved


Under implementation. Expected in Aug 2013

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Annexure XI - SPS SPS for Talcher – Kolar HVDC Bipole - SPS at Kolar Talcher – Kolar HVDC link is a 2000 MW asynchronous link between Eastern and Southern regions. The outage of Talcher – Kolar causes wide fluctuations in power transmission between Karnataka and Andhra Pradesh system (Cuddapa-Kolar). Further Power system in India works on a floating frequency range of 49 to 50.5 Hz. as of now we do not have either spinning reserve or the primary control of generation (most of the generators does not run on Free governor Mode of operation) resulting in sharp drop in frequency during generation loss/tie line tripping. Therefore when the SR grid is operating at lower end of the operating band tripping of HVDC Talcher-Kolar link will result in sharp drop in the operating frequency and may also result in cascade tripping of the generating units. To avoid such incidence of grid instability a system protection scheme has been implemented for fast load relief during contingency of tripping of single pole/ Bipole of the HVDC link. Such inter trip Implementation of the scheme The scheme was implemented in two stages. In the first stage the logic was implemented on 20/04/2003 and was in service till 24/03/2006. In the Second stage improved version of the scheme was implemented on 24/03/2006 to take care of increased power flow on the Talcher Kolar HVDC link and to overcome some deficiencies of the existing scheme 1st stage of Implementation In the first stage, matching with the generation of Talcher stage II generation at that time, the scheme was designed to give a load relief of about 500 to 600MW by shedding the loads in the nearby substations of Andhra Pradesh, Karnataka, and Tamilnadu detailed below.

Yeraguntala Kolar Hosur Salem Sriperumbudu Somanahalli Hoody r L o ss/reduction of power was sensed at Kolar and the trip signal was generated by the SPS based on the logics explained below was sent to the above mentioned stations through PLCC: MODE OF OPERATION

POWER SIGNAL

LEVEL

FOR GENERATING

INTERTRIP

MONO POLAR

>400 MW AND THE POLE TRIPS

BI-POLAR

IF BOTH POLE ARE CARRYING > 800 MW EACH AND ONE POLE TRIPS

BI-POLAR

IF POWER FLOW ON EACH > 200 MW AND BOTH POLE TRIP

The scheme successfully worked for most of the time except for few occasions. 2nd stage of Implementation Improved version of the scheme was required to be implemented due to the following reasons    

NLDC

Increase in the flow on Talcher –Kolar HVDC link due to commissioning of all the generators at Talcher stage II it was required to increase the quantum of load shedding. The deficiencies noticed in the 1st stage implementation were to be rectified immediately since the improper operation during high power flow would affect the power system badly Due to non availability of sufficient sheddable loads in the substation surrounding Kolar it was required to send tripping signals to far locations using wideband communication links. To avoid excess load shedding than required two signals were requires to be generated to match the outage of single pole, Bi pole etc.


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Annexure XI - SPS LOGIC AT KOLAR FOR INITIATING SIGNALS Trip Signal 1 Trip Signal 1 would be initiated to obtain a relief of around 700 MW from the stations listed in the below table under any one of the following two conditions: (i) If loss of power flow on the HVDC link at any instant compared with the power flow 2 seconds prior to current instant is more than 500 MW but less than or equal to 1000 MW. (ii) If one of the HVDC pole block on a line fault and the power flow on the HVDC link just prior to that instant was more than 1000 MW but less than or equal to 1500 MW. Trip Signal 2 Trip Signal 2 would be initiated to obtain an additional relief of around 800 MW (in addition to 700 MW as stated above) from the stations listed in the below table under any one of the following two conditions: (i) If loss of power flow on the HVDC link at any instant compared with the power flow 2 seconds prior to current instant is more than 1000 MW. (ii) If one of the HVDC pole block on a line fault and the power flow on the HVDC link just prior to that instant was more than 1500 MW. Note: In the event of occurrence of Trip signal 2, the total relief would be of the order of around 1500 MW, consisting of around 700 MW from the stations listed under Trip signal 1 and additional 800 MW from the stations listed under Trip signal 2

Block Diagram A simple block diagram depicting the logic for generation of Trip Signal 1 and Trip Signal 2 transmission of such signal to the respective locations is given below

and

SIGNAL A

REDUCTION IN POWER

OR

> 500&<1000MW

OR

TRIP SIGNAL 1

POWER FLOW >1000&<1500MW

N D A

DC LINE FAULT

Kolar Inter Trip Logic Diagram N D A

POWER FLOW > 1500MW

OR

TRIP SIGNAL 2

REDUCTION IN POWER > 1000MW

AND

SIGNAL B

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Annexure XI - SPS

LOGISTICS FOR OBTAINING RELIEF AT DIFFERENT LOCATIONS On the basis of above stated logic Trip Signal 1 and Trip signal 2 is extended to the following substations through wideband /PLCC: List of Substations to which Trip Signal I will be sent STATE

SUBSTATIONS

A.P Karnataka

Chinakampalli Kolar ICT Hoody Hosur Sriperumbudur Salem

Tamil Nadu

RELIEF (MW) 150 250 300

REMARKS Signal through wide band. Through local pilot wiring Through PLCC Through PLCC Signal through wide band. signal through wide band.

List of Substations to which Trip Signal II will be sent

STATE

SUBSTATIONS

RELIEF (MW)

REMARKS

A.P

Gooty Switching Stn Ananthapur Somayajulapalli Kurnool Somanahalli Trichur North Kozhikode Madurai Karaikudi Thiruvarur Trichy 230 Ingur

200

Signal will be sent through wide band

Karnataka Kerala Tamil Nadu

200 200 200

Performance of the scheme since implementation till date indicate that the operation of the scheme has improved compared to the 1st stage implementation

3rd stage of Implementation : The Talcher-Kolar HVDC is being operated on extended mode of operation on real time. Hence the 3rd signal is planned & logic diagram is shown below. Trip signal-3, which trips 500 MW loads in case of tripping of HVDC Talcher-Kolar one or bipole tripping and power flow on HVDC poles is more than 2000 MW. It is Under advanced stage of Commissioning.

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Annexure XI - SPS

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Annexure XI - SPS SPS at Kudankulam Nuclear power plant In case of tripping one or two units at Kudankulam nuclear power plant, trip signal-1 or Trip signal-1&2 will be generated depending on number of units tripping. Trip signal-1:793 MW and Trip Signal-2:710 MW List of Substations to which Trip Signal I will be sent

STATE

SUBSTATIONS

RELIEF (MW)

REMARKS

A.P

Chinakampalli

150

Signal through wide band.

Karnataka

Kolar ICT Hoody Hosur Sriperumbudur Salem

250

Through local pilot wiring Through PLCC Through PLCC Signal through wide band. signal through wide band.

Tamil Nadu

300

List of Substations to which Trip Signal II will be sent

STATE

SUBSTATIONS

RELIEF (MW)

A.P

Gooty Switching Stn Ananthapur Somayajulapalli Kurnool

200

Karnataka

Somanahalli

200

Kerala

Tamil Nadu

NLDC

Trichur North Kozhikode Madurai Karaikudi Thiruvarur Trichy 230 Ingur

200

REMARKS

Signal will be sent through wide band

200


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Annexure XI - SPS

6. SPS in North Eastern Region The Details of System protection schemes of North Eastern region

SL. NO

1

2

NLDC

Name of the Scheme

Implementing Agency

Status

SPS for Meghalaya System to ensure security of Capital load of Meghalaya.

Meghalaya

In case of tripping of 400 kV SilcharKilling or 400 kV SilcharPalatana D/C or Palatana Machines,

Remarks

Category Type

In service

Implemented

Load rejection

Under Discussion

Under Discussion

Load rejection/ Gen reduction

Date


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Annexure XII Islanding Schemes

ANNEXURE XII

List of Islanding Schemes Northern Region 1)

NAPS Islanding Scheme - Implemented

2)

RAPS ‘A’ Islanding Scheme - Implemented

3)

RAPS ’B’ Islanding Scheme - Implemented

4)

Islanding schemes of Delhi, Punjab & Uttar Pradesh –Under discussion stage.

1. NAPS Islanding Scheme

NLDC

Operating Procedures for National Grid - Islanding Schemes 168 of 198

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2. RAPS ‘A’ Islanding Scheme

RAPS-A: The frequency setting and time delay for islanding and units coming to house loads are given in table 1: Table 1:

Islanding House Loading

RAPP-A Frequency Hz. 47.5 47.5 47.1

Time Delay Sec. Instantaneous 10 seconds Instantaneous

RAPP ‘A’ islands at 47.5 Hz instantaneous The following conditions are envisaged: 1

2 3 The 4 5

NLDC

When only one machine is generating at RAPP ‘A’, matching load will be provided by Debari alone. Under this condition, 220 kV RAPP ‘A’ – Kota-I & III lines shall trip at 47.5 Hz (with Kota-II already connected to RAPP ‘B’). Thus Kota loads are automatically disconnected from RAPP ‘A’. When both the machines of RAPP ‘A’ are generating, matching load will be provided by Debari, part Kota, Modak and Jhalawar. At a later date if the load of Modak and Jhalawar is fed directly from KTPS, equivalent matching load on 220 kV Kota Sakatpura shall be provided on any 132 kV Outgoing feeder on radial mode to provide load generation balance. The loads shall be regulated such that Debari load is equal to Unit-II generation minus 35 MW. The following arrangements are to be kept at RAPP ‘A’, 220 KV GSSs of Debari, Sakatpura (Kota), Jhalalwar & Modak stations to ensure smooth functioning of the Islanding Scheme. The operating status of UFR relay like Block, Operative and Normally Open required to be kept for successful islanding has been also indicated.


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Annexure XII Islanding Schemes At RAPS-A: The status of feeder with setting of U/F relays is kept as under:

AT 220 KV GSS DEBARI 1. 132 kV loads from Debari will be regulated through under frequency relay set at 47.5 Hz and the trippings shall be blocked/operative as per the load requirement. 2. 132 kV Banswara - Nimbahera will be kept permanently open at Pratapgarh.

The status of feeders with setting of U/F Relay is kept as under:

The following arrangements are being kept at 220 kV Kota Sakatpura: 1. 220 kV Bus ‘D’ is to be kept as dedicated for RAPP ‘A’ Island. 220 kV Bus Coupler between A to D will be operative at under frequency setting of 47.5 Hz so that Bus D remains connected to RAPP ‘A’. 132 kV RPS-Kota Circuit (direct) will be kept on 132 kV Bus of Transformer No. 4 connected to Bus ‘D’, which will provide RPS Hydel support to the island, if required. 2. 100 MVA Transformer No. 4 shall be always kept on Bus ‘D’ 220 kV Jhalawar & Modak shall also remain connected on Bus ’D’. Transformer No. 4 will provide load of 132 kV Bundi, 132 kV SWM-II, Gopal Mill, 132/33 kV 100MVA Transformer No. 2 20/25 MVA for the Island. The U/F tripping on these loads will be set at 47.5 Hz and shall be kept operative/blocked as per load requirement to be monitored by L.D.

NLDC


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Annexure XII Islanding Schemes 3. 220 kV Kota (I)-RAPP ’A’ connected on Bus ‘D’ will be Blocked/Operative at 47.5 Hz as per generation available at RAPP ‘A’. 4. 220 kV Kota (III) -RAPP ‘A’ will be on any Bus A, B or C with U/F relay operative at 47.5 Hz. 5. 220 kV RAPP ‘B’-Kota-II will also be on any Bus A, B or C with U/F relay operative at 47.7 Hz. 6. The synchronization of island may be done at RPS with MP Power on 132 kV Gandhi Sagar line-II or at Kota (S) with 220 kV Ujjain-Kota if required. MP power will be available through 220 kV Ujjain-Kota (II) but this circuit will be normally open at Kota. Status of U/F relays and setting on the feeders will be as under: AT RPS Hydel 1. One unit (machine No.4) will be kept on main Bus ‘B’ which is Islanding Bus and 3 units on 132 kV main Bus ‘A’. 132 kV Gandhi Sagar Circuit-II will be on Bus B and shall be kept normally open at RPS end. This may be utilized to further synchronise the Island with MP to stabilize the island system, if required.

2. 132 kV RPS-Kota (Direct ckt.) will also be on main Bus ‘B’ included in the Island. 3. 132 kV RPS-Bhilwara I & II will be on Bus ‘A’. The under frequency relay settings will be as under:-

AT 220 kV MODAK

All loads will be kept connected. AT 220 kV JHALWAR All loads will be kept connected.

NLDC


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.

3. RAPS-B Islanding Scheme RAPS-B: The frequency setting and time delay for islanding and units coming to house loads are given in table: Table 2:

Islanding shall take place at 47.7 Hz with 5 sec. delay or 47.5 Hz instantaneous. 1. At RAPP ‘B’, the total generation of Unit-III & IV is expected to be around 400 MW. RAPP-B machines will be islanded separately with matching load of 180- 200 MW. This load is to be provided from Chittor, Nimbahera & Bhilwara. 2. No Under Frequency Relays are required for 220 kV Chittor-Nimbahera line and 220 kV RAPP ‘B’ – Chittor (Chittor end) on both the circuits. Loads of 132 kV GSS Hamirgarh, Sawa, M/s Aditya Cement, M/s BCW, M/s CCW & M/s HZL shall be fed from 220 kV Chittorgarh. 3. The operating status of UFR relay like Block, Operative and Normally Open required to be kept for successful islanding has been also indicated. 4. The settings of under frequency relays in the above Island are to be kept as under: AT RAPS-B End:

AT 220 KV GSS CHITTORGARH The U/F Relays of 220 kV Chittorgarh-Bhilwara (both ends) will be made operative by LD if the requirement of load is indicated by RAPP authorities to be around 100-120 MW (one unit), otherwise this relay will be kept blocked so as to provide islanding load of 180-200 MW.

NLDC


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5


AT 220 kV GSS DEBARI

AT 220 kV GSS SAKATPURA KOTA The under frequency relay on 220 kV Kota-RAPP ‘B’ (II circuit) which will normally remain on Bus ‘C’, will be set at 47.7 Hz (Inst.) and will remain operative. AT 220 kV GSS NIMBAHERA Loads of 132 kV Bhinder, Mangalwad, Chhoti Sadri and Pratapgarh shall be fed rom Nimbahera and shall not be transferred to other GSSs without approval of SE(SO&LD). AT 220 kV GSS BHILWARA Bus arrangement on 220 kV side will be as under: On 220 kV Main Bus (A+Bus III). 220 kV Bhilwara-Kota-I 220 kV Bhilwara-Kota-II 220 kV Bhilwara-Bali-Sirohi 220 kV Bhilwara-Kankroli-Sirohi 220 kV Bhilwara-Anta-I 220 kV Bhilwara-Anta-II 220 kV Bhilwara-Beawar 220 kV Bhilwara-Jodhpur On 220 kV Main Bus (B+C) (Islanding bus). 220 kV Side of220/132 kV, 100 MVA Transformer No.1. 220 kV Side of 220/132 kV Transformer No.2 220 kV Bhilwara-Chittorgarh AT RPS POWER STATION

132 kV RPS-Bhilwara-I & II will be connected on Bus A.

AT 220 KV GSS BEAWAR i.

132 kV Beawar-Bhilwara Via Asind

Operative

47.7 Hz (Inst.)

AT 132 kV GSS KHARCHI

NLDC


-

July 2013-Rev 0

6


Western Region 1)

MUMBAI (TPC & REL) Power System.

2)

GIPCL Islanding Scheme in Gujarat

3)

Kakrapara Islanding Scheme OF N.P.C

1. MUMBAI (TPC & REL) POWER SYSTEM 1.1

Islanding scheme for the Mumbai Metropolis, Island can meet the load of 1800 MW with generation at Trombay(1330MW), Bhira(150 MW), Bhivpuri (72MW), Khopoli (72 MW), Bhira PSG (150 MW) of TPC and Dahanu (2x250 MW) of REL.

1.2

The first level of separation of TPC+REL system from MSETCL system at 47.9 Hz with

the

tripping of:

    

110kV Kalyan(TPC)-Kalwa(MSETCL) at Kalyan(TPC) 110kV Borivali(TPC)-Borivali(MSETCL) D/C at Borivali(TPC) 220kV Borivali(TPC)=Borivali(MSETCL)-I 110kV Salsette(TPC)-Kalyan(TPC)-Kalwa(MSETCL) at Salsette and Kalyan substations of TPC 220kV Trombay(TPC)-Trombay(MSETCL) D/C at Trombay(TPC)

1.3

The second level of separation of TPC system from MSETCL system at 47.9Hz under reverse power condition (with flow from TPC to MSETCL) with the tripping of:  110kV Trombay(TPC)-Trombay(MSETCL) D/C at Trombay TPC  110kV Kalwa-Kalyan S/C  220kV Kalwa(MSETCL)-Salsette(TPC) D/C at Salsette (TPC)

1.4

The separation of REL system from MSETCL system shall also take place at 47.9 Hz with reverse power condition of power flowing from REL to MSETCL with the tripping of:  220kV Boisar-Versova  220kV Boisar-Dahanu.

1.5

In the event of failure of primary protection for islanding, backup RPUF relay set at 47.9 Hz with 0.5 seconds time delay is set to trip the same breaker. LBB protection is provided to take care of stuck breaker condition.

1.6

TPC system separates from REL system when 220kV Borivali (TPC)-Aarey(REL) D/C interconnections open at 47.7 Hz under reverse power condition (with power flow from TPC to REL).In addition to this REL separates from TPC at 47.6 Hz.

1.7

In REL system, UF load shedding is done to ensure that the system remains connected with TPC system and survives after separation from TPC.

1.8

AUFLS (discrete) of about 800 MW set at 47.9 Hz is provided at TPC to ensure load generation balance in TPC subsequent to islanding. In addition, there is frequency trend relays set at 49.0 Hz at 0.5 Hz/sec in TPC system to ensure successful islanding.

NLDC


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July 2013-Rev 0

7


NLDC


-

July 2013-Rev 0

8

Annexure XII Islanding Schemes 2. GIPCL ISLANDING SCHEME IN GUJARAT The islanding scheme to save about 145 MW generation at GIPCL Stage-I  132kV Vatwa-Ranasan D/C  The 100MW gas based station islands with radial load of Vatwa (Ahmedabad) The islanding takes place at 47.6 Hz. 3. Kakrapara Islanding Scheme OF N.P.C 3.1 Islanding scheme to save the units (2x220MW) at Kakrapara Atomic Power station along with the loads of Vapi. Islanding caters to 300-350 MW load of Vapi in Gujarat and UTs of DD & DNH. 3.2 Separation points  220kV Kakrapar - Haldarwa  220kV Tarapur - Vapi  220kV Navsari - Vapi  220kV Kakrapar – Vav 3.3 Frequency setting at Kakrapara & Vapi 47.8 Hz with 0.6 seconds delay or 48 Hz with 0.8 Hz/sec rate. Remarks: Presently the scheme is not kept in operation.

NLDC


-

July 2013-Rev 0

9


Southern Region 1)

The islanding scheme of Ramagundam with about 1800 MW of loads at Ramagundam and Hyderabad area

Eastern Region 1)

CHPC (Bhutan) - One machine (84 MW) along with Thimpu Load gets island with opening of bus coupler breaker

2)

CESC - The entire system gets islanded at Kasba ( the synchronizing point)

3)

NALCO(CPP in Orissa system)

4)

ICCL(CPP within Orissa system)

5)

RSP (CPP in Orissa system)

6)

Bhushan Power & Steel (CPP in Orissa system)

7)

Arya ISPAT and power Ltd. (CPP in Orissa system)

8)

Maithon Ispat Limited (CPP in Orissa system)

9)

IFFCO (CPP in Orissa system)

10) Hindalco(CPP in Orissa system) 11) IMFA (CPP in Orissa system) 12) IBTPS 13) VAL (CPP in Orissa system)

North Eastern Region 1)

Proposed Island 1 will be comprising of generation of AGBPP, NTPS & LTPS with Upper Assam & Deomali Load

2)

Proposed Island 2 will be comprising of generation of AGTPP, Rokhia, Baramura & Gumti with Tripura load.

Operating Procedures of respective RLDC may be reviewed for complete details of the islanding schemes listed above

NLDC


-

July 2013-Rev 0

10

Annexure XIII

NLDC


July 2013 Rev 0

ANNEXURE XIV - POWER MAPS

NLDC


July 2013 Rev 0


NLDC


July 2013 Rev 0


POWER MAP OF WESTERN REGION 400 kV Lines and Major 220/132 kV Lines AS ON 31.03.2013

To Jaipur

Mehgaon To Sawai SambalgarhJora Motijheel Madhopur NR Mahalgaon

RAJASTHAN

To Mohindergarh

TO KOTA TO Modak Gandhisagar

To Kankroli

GUJARAT Deodhar

Zerda(Kansari)

Agathala

TO Auraiya

Malanpur Gwalior

UTTAR PRADESH

Seopur To R.P.Sagar

To Bhinmal Dhanera Tharad

Agra

Neemuch

Palanpur Kheralu

Marhikheda Shivpuri Pichhore Matatila Guna

Rajghat

Chhatarpur Tikamgarh Bijawar

Bansagar-I Kotar Satna Rewa

To Rihand

TO SINGRAULI STPS(N.R.)

Vindhyachal pooling Stn

Bansagar-II 2 x 250 MW Morwa Bina Maihar Suwasra Bansagar-IV Mathasur (Bhutia) JHARKHAND Mandsour Bina(PG) Sidhi Hatia Vindhyachal STPS Rajgarh Vijapur Badod Daloda Kymore Bansagar-III 765KV LINE CHARGED Agiyol Sagar Sasan Katni ON 400KV Waidhan Agar Nakhatrana JPBINA Jaora Dehgam Damoh Varsana Vidisha Dhansura Dhrarngadhra Chhatral Anjar MAHAN Nanikhakar Halwad Ratlam Nagda Pirana(PG) Sujalpur Anupur(MP) Lunawada Kadana APL CGPL Morbi RanchodpuraGandhinagar Ujjain MADHYA PRADESH Birsinghpur Bhopal Wanakbori Suzlon-suthri Godhra Astha Barmana Jabalpur Kotma Manendragarh ViramgamBhat Pirana(T) Bareli 4 Essar Jamnagar Reliance Wankaner Chorania Kasor Badnagar 5 Dewas Halol Gadarwara Sikka Vadinar Amarkantak Kotamikala Vishramgarh Jabalupr (PG) Piparia Ambikapur Indore Itarsi Naghedi Hadala Limbdi Karamsad Asoj Hasdeo Bango Khambolia Mandla Handia To Ranchi Lakhnadone Bargi Korba(W) Pithampur Paliad Dhuvaran Wagodia BALCO Bhatia GPEC Narsinghpur Burwaha Vandana Jambuva Pathhalgaon Ranchi Seoni Dhanduka Maneshari SSP Rajgarh Korba (E) Extn. Indira Sagar Gondal Enercon Korba (E) KSTPS Jhanor GPEC 2 Omkareshwar Ranavav Moti-paneli Jetpur Nimrani Bilpr 1 Amreli Dhasa Vartej Birsa Budhipadar JPL Tamnar Khandwa 6 Satpura Sardargadh Chhindwara Mopka Khapaswami Julwania Chegaon Sterlite Raigarh Balaghat Kosmba Savarkundla Palithane Halderwa Sipat Betul Chincholi Kakrapar Raita ROURKELA Bhatapara Khagone Boregaon Keshod Visavadar GPPL Otha Utran 3 Raigarh Pench Pandurna Ukai(H) Kawas Dhokadwa Bhusawal-II Kanhan Bhandara Sugen Kalmeshwar BHILAI Urla Kovaya KORADI GSEG Rajnandgaon 7 Ukai(T) ACB Ambazari Kodinar Una Essar Jalgaon Amravati Navsari(Getco) Khaparkheda Malkapur Vav Mauda Lanco Pathadi Bhilad Bhusawal Dongargarh RAIPUR Diu(D&D) Nandgaonpeth Paras Pipavav KWPCL Mota Vidarbha Ambheta GSEG Navsari GIS(PG) KSK Eldabad Butibori Badnera IEPL NSPCL Torrent ORISSA Malegaon Vapi Rajim Magarwada Wardha Bhugaon Akola Dhule (D & D) Dalli-rajara Chalisagaon Hinganghat Karadpada Gurur Khadoli Yawatmal MAHARASHTRA Warora Bhadravati (DNH) Nasik Gujarat Manmad Tarapur Tirora Aur’bad Boisar 1 Achhalia Pusad Ghatghar Aur’bad(PG) 2 Zagadia Kharghar Dahanu(BSES) Jalna Bableshwar CHANDRAPUR GMR EMCO 3 Kim Navi Mumbai Borivali Hingoli 4 Ranasan 5 Parbhani Kalwa 2 x 500 MW Nanded Pune(GIS) 5 Kapadwanj Padghe Barsoor 6 Ahmadnagar Trombay Pune(PG) 6 Mangrol Jagdalpur Beed 7 (Surat LPP) 4 Uran Chinchwad Parli( PG) 7 Sachin Lonikhand Kirandul Nagothane 2 Kandalgaon TO RAMAGUNDAM 3 Parli 1 Latur Baramati Osmanabad Udgir Lonand Maharashtra ANDHRA PRADESH Ujani 1 Jejuri 2 Theur Sholapur Koyna IV TO L. SILERU 3 Parvati New Koyna Karad 4 Chakan Sholapur(PG) L E G E N D Vita 5. Alephata Dabhol 6. Ranjangaon Miraj HYDRO POWER STATIONS 7. Apta Kolhapur Jaigad THERMAL - COAL Chikodi To Raichur KARNATAKA

Akrimota

Panendro

Kukma

WelspanRadhanpur

Sankhari

Chitrod Sami Mehsana Jamla Tappar Bachhau Nardipur(Soja)

Uno-sugen

Ichhapur

A

R

A

A B I

N

C

HH

AT T

ISG

A S E

AR

H

Mahasamund

- GAS

Gadinglez Tillari

Mapusa

GOA

To Belgaum Mahalaxmi

NUCLEAR POWER STATION 765 KV TRANSMISSION LINES

Amona

To Nagjhari Ponda

400 KV TRANSMISSION LINES 220 KV TRANSMISSION LINES 132 KV TRANSMISSION LINES TR. LINES UNDER PLAN UPTO MAR.2012

Prepared by: WRLDC,Mumbai

NLDC

500kV HVDC Bipole MAP NOT TO SCALE


July 2013 Rev 0


TO CH AND RAPUR

TO TALCHER

N IR MAL

MA CHK UND R AMAGU NDAM

B HIMGAL ME DA RAM MALA YA LA PALLY SA LIVAGU D URS HED

DICHIPALLY K AMA REDDY

TE KK ALI GANG ARAM B HIMGHA NPUR

49

GA JWEL MINPUR

SIDD IPET

P ALA KURTHY

HA LAB ARGA

W ARA NGAL GUN ROCK

MED CHAL 3 HUMNA BAD S HA NKA RAPALLY 2 1

S HA DNA GAR GU LBARGA SE DAM

9

8

W K P ALLI

HW P LOW ER S ILERU KTP S - V

NA RKE TPALLI

D ONKA RAI K ALPAKA

R C VARAM

11

N BE IL

KHA MMAM

19

L&T KUD ITINI NA GJHARI SUZLON(W) GOOTY RTSS PULIV ENDULA HA VERI JINDAL P ENNA B R'PALLI BMM TADIP ATRI MYDU KUR ITTAGI MUDDA NUR KODA SALLI NELLORE PS K AD RA ANA NTPUR THIMMAP URAM NILAGUNDA NELLORE KAD APA K ALYA NDURG R ANIB ENNUR YE RRA GUNTLA KA RW AR K AIGA K ONDA PURAM C HINA KAMPALLY GUTTUR SIRSI RAMA GIRI 69 CH ITRA DURGA R LY S.KOPPA S HAR AVATI S HAP URAM TALA GUPPA TALLAK 34 DA VA NAGERE RA JAMPET K ODUR S HIMOGA HIRIYUR

GAP

12

K V KOTA

20

GA RIVIDI A NRA K AL. SA RDA P EN DURTHI GA ZUWAKA GVP VS P MRS B RANDIX A BHIJEET ALLOY

23

56

15

22

TO Y ANAM 17 18

B HIMAV ARAM

ME ENA KSHI S IMH APURI K RISH NAP ATNAM NE LLORE (MAN UBOLU)

J OG HIRIYU R (PG) HIND UPUR EN ERC ON SU LURPET LDPH S.TAIL RACE CHIKK AMA GALUR KA LIKIRI R ENIGUNTA MAD HUGIRI GOW RIBIDANUR NCTPS STG2 63 P ALAMA NERU HAS SAN VA RAHI HOS KOTE 62 61 N CTPS 58 NAGARI H ASS AN KIB BAN AHALLI 33 KIADB ALMA THY 64 44 K OLAR ENN ORE OR O 36 DB PURA K AD UR T C R PA TNA B B GA S/G M R VASAVI CHIT B IAL KOLAR MOSUR MA NALI 45 TOND IARPET 71 30 GOP ALPURA 31 B ASIN B RIDGE GAS VA LLUR C HINTAMANI 29 K UDRE MUKH NITTUR 27 53 MY LA PORE KE MAR K ALAV INDAPAT TU KU NIGAL 46 B 'PET THIRUV ALAM 59 43 70 HOODY KOY AMBEDU 51MA LUR NPCL 60 32 SA RJAP URA 26 28 25 52 H N'P URA K.R.P ET UPCL K AD PERI YELE HANKA HYUNDAI 48 57 KAV OOR THA RAMANI HOS UR O RAGA DAM PUTTUR 24 S IRUSERI KO NAJE SP KOIL K ITS PARK B IDADI S OMANA HALLI VINNA MANGALAM A RNI S .V.CHA TRAM MA NJES HWAR V ID YA NAGAR B HAVANI K UB ANUR HA ROHALLI K ALPA KKAM KA RIMAN GALAM KAS AR KODE TUBIN AKERE K'NA GARA A CHA RA PAKKAM SA MA LPATTY MY SORE KA NAK APURA T V MALAI BA STHIPURA BA HOOR V AGA MANGALA SING ARA PETTAI T K HALLI TALIPA RAMBA VILLUP URAM TH ONDA MANATHAM HO OTA GALLI VILLIANUR METTU R AUTO KA NHIRODE NE YV ELI TS 1 MADU VA NAHALLI KA DA KOLA CUDD ALORE (K A NNUR) SA LEM KUTTIADI EXT. NE YV ELI TS 2 SA IL DE VIA KURCHI K ANIA MPET CR NA GAR METTUR TUNNEL NE YV ELI TS 2 (Exp) MA LCO VATA KARA KU TTIADI K UTHUMUNDA SALEM EAC HEN GADU ST-CMS N EY VE LI TPS 1 (Exp) P YK ARA GOBI MTPS UP AA TTI U NJANAI K OZH IKODE ARE AK ODE K UNDA H 1 PE RA MB ALUR P UDA NCHA NDAI IN GUR KUND AH 2 KUN DAH 4 K AD ALAN GUDI N ALLALAM

MALA PP ARAMBA

NALLAMA NAICKE NPAT TY

IDU KKI

PA LOM NE W PA LOM

A MUTHAP URAM SA TH UR

S AB RIGIRI K AK KAD E DA PPON

STER LITE KA YA THAR

K AY AMKULAM 37

ED AMON 39

38

POTHE NCODE 40

41

42

P ARU TH IPARA P ARA SSALA

P ARA MAKUDI VA LATHUR (KA VA NOOR) ARK AY

S R PUDUR

S IP COT IND BHA RATH TUTICORIN JV TUTICORIN AUTO THIR UNE LVELI S AN KANERI

K OODA NKULAM

K UZHITHURAI

GACHIBOWLI

4. 5. 6.

MOULALI MALKARAM GHANAPUR

10.

KONDAPALLI

13.

JEGRUPADU

15. 16. 17.

SPECTRUM KAKINADA VEMAGIRI

19. 20. 21. 22.

BOM MUR NIDADAVOLU PEDAPURAM BSES

25. 26. 27.

ITPL HSR LAYOUT NRS

29. 30. 31. 32.

PEENYA HEB BAL WH ITEFIELD TATAGUNI

34. 35.

HONALI MUNIRABAD

37. 38. 39. 40. 41. 42.

KUNDARA VIRANAM KO DIKURCHI KO DAYAR TRIV ANDRUM UD AYATHUR

44. 45.

KILPURK DOBSPET

47.

VTS STAGE IV

KON ASE EMA

16

M'R ABAD

PU GALUR KUND AH 3 THU DIYALUR P P NALLUR SUZLON SAMA YP URAM PALLA DAM A RAS UR ABAN W ALAYAR TR ICHY K UTTA LAM O K MAN DAPAM SH ORANUR THA NJAVUR MADU KK ARAI SA DAY AMP ALAYAM TH IR UVARUR ANA IKA DAVU PA LA KKAD U DULMALPET TRICHY KAR AMBA YAM P ONNA PU RAM R N PURAM KOV IL KALAPAL U DUMA LPET ALIYAR PU DUK OTTAI TR ICHUR KA DA MP ARAI SEMB ATTI BSES S HOLAYAR KA RAIK UDI NEW ALAGA RKOIL IDA MA LYAR K ALAMA SSERY KOC HI P ASU MALAI LOW ER K ARA IKUDI MA DUR AI PCL P ERIYAR B RAMH APURAM THE NI MA DURAI A MB ALA MUGAL PER IYAR (CH ECK AN URANI)

2.

PA RWA DA GMR (BARGE)

13

PUTTANGADI MIRY ALGUDA 14 LA NCO BH IMA DOLE GUDE MDODDI C HILLA KALLU 10 MAH ABO OB NAGAR CHE LLA KURTHI GA UTAMI BIJA PUR 47 JURA LA HY TO KOLHAPUR K M PALLY V TS MA HAB OOB NAGAR N UNNA N S AGAR KA LW AK URTHY B ALUTILIS B B AGE WADI G UDIVADA N ARA SA RAOPET JU RALA GUNA DALA K UDA CHI NTPD D INDI C HIKKODI RE NTA CHINTALA R EGUMA NAGADDA TAD IK ONDA V AJR AMATTI A TH ANI ALMATTI W ANA RP ARTHY P ARC HUR MA HALINGPUR R AICHU R(RTPS) SLB PH BA GALK OTE SR IS AILAM RBPH B RAH MA NA KOTKUR LIN GAS UGUR INDAL RAICHUR MALYALA SIND HAPUR B ELGAUM A P CA RBIDES MAR KA PUR KA NA BHA RGI LYT KU SHTAGI NA NS URALLA K URN OOL JS W GHA TA PRABHA M K HUBLI 55 POD ILI ONGO LE B'GUDUR LAK KA SAG ARAM SOU NDATTI KA LYAN I STEEL NARE NDR A-PG S OMA YA JULAPALLY 54 HAMPI K AMB ALAPADU GA DAG 65 66 35 NA NDYAL P ONDA AMB EWNADI ARE NDR A-KP T B DAM D HONE ENE RCON HUBLI B TPS ALIPUR BIDNAL S UPA RE GULAPADUGOOTY LINGAPUR 68

50

21

SHA HA PUR

67

DFARM

S ITA RAMP ATANAM

4 6 GHAN APUR 7

MA MID IPALLI

TAND UR

A RAKU UPP ER S ILERU

MANU GURU KTPS K TP S VI

B HONGIRI

72

TO B AR ASUR

K AKA TIYA BHOOP ALA PPALLY

5

SHA HA BAD

INDI

TO JEY PORE TO B ALIMELA

B ELLA MP ALLY V EMNUR JAGTIYAL

IN DEX LEGEND

49.

NAGARAM

51. 52. 53. 54. 55.

HAL EDC KORATHUR KRISHN AGIRI SETTIPALLY

57. 58. 59.

NIM HANS ATHIPATTU NOKIA

63. 64. 65. 66. 67. 68.

KAMAKSHI SURYA DEV RSS STEELS HRG STEELS D'D ESH X INDIA

70. 71. 72.

A STATION CPRI HIAL

DISCRIPTION 400 KV LINE 400 KV LINE CHARGED AT 220 KV 220 KV LINE HVDC LINE 110/132 KV LINE 66 KV LINE HYDEL POWER STATION THERMAL POWER STATION NUCLEAR POWER STATION

NLDC


July 2013 Rev 0


TO CHANDRAPUR

GMR (BARGE) (BA RGE)

TO TA LCHER TO JEYPORE

RA MA GUNDAM DICHIPA LLY K AKATIYA BHOOPALAPPALLY

GAJWEL

GAZUWAKA

WARANGAL

KALPAKA K TPS VI

M ALKA RAM

S IMHADRI STG1

SHANKARAPALLY SIMHA DRI STG2 GHANAPUR MAMIDIPALLI

K ONASEEMA K HAMMAM GVK (JEGRUPADU EXTN) VEMA GIRI

LANCO GAUTAMI VTS

M AHA BOOB NAGAR

GMR V EMAGIRI NUNNA

N SA GAR

S RISA ILAM RA ICHUR

K URNO OL NA RE NDRA

MUNIRABAD

B TPS

GOOTY

JINDAL MEENA KSHI

NELLORE PS NELLORE

K ADAPA KAIGA TALAGUPPA

GUTTUR

S IMHAPURI K RISHNAPA TNAM NELLORE (MA NUB OLU)

HIRIYUR (PG)

NCTPS STG2

HAS SAN

NCTPS NELAMANGALA OOR

ALMATHY

E NNORE

T

CHIT

K OLAR

V ALLUR K ALAV INDA PATTU

HOODY

DUR

MBA

ERA

UP CL

SRIP

HOS UR B IDADI

S .V.CHA TRAM

S OMA NAHALLI

M YS ORE

NEYVELI TS 1 S ALEM

NEYVELI TS 2 NEYVELI TS 2 (Exp) S T-CMS

MTPS

NEYVE LI TPS 1 (Exp)

P UGALUR A RA SUR

P ALAKKAD

TRICHY UDUMA LPET

TRICHUR

K ARAIKUDI K OCHI M ADURAI (CHE CKA NURANI)

EDAMON

P OTHE NCODE

TUTICORIN THIRUNELV ELI

KOODANK ULAM

NLDC


July 2013 Rev 0


400KV NETWORK IN SR WITH LINES AND BUS REACTORS 50

RAMAGUNDAM

(178)

CH’PUR

~

BOOPALAPALLY

~

50

(267)

(267)

(99)

(197) (197)

~

(150)

(172)

(108) (156)

(108)

(156)

(151)

63

(110)

50

NELLORE 80

CHITTOOR

MADRAS

50

BANGALORE

KALAVINDAPATTU

63

(145)

(54) I MYSORE

50

50

(35) BIDADI 63

50

50

50 63

II

ARASUR

I

63 50

63

63

NEYVELI TS-2 (Exp)

UDUMALPET 63 50 63

PALLAKAD

-

NEYVELI TS2 NEYVELI TS-I (Exp)

- LINE REACTOR CONVERTABLE INTO BUS REACTOR (Non-Switchable) - LINE REACTOR CONVERTABLE INTO BUS REACTOR (Switchable)

63

50

TRICHY

50

KARAIKUDI 80 II

50

(160)

63 63 I

63

MADURAI

(160)

TIRUNELVELI

*

63

*63

63

- BUS REACTOR - FIXED SERIES COMPENSATOR

(153)

63

(162)

I

(162)

THRISSUR II

LINE REACTOR (Non Switchable & Non Convertible)

- SWITCHABLE LINE REACTOR ( Non – Convertible)

50

PUGALUR

63 50

TRIVANDRUM

NCTPS STG2 63

PONDY

HASSAN MTPS STG 3

63

(7)

63 50

COCHIN

(34)

SV CHATRAM

HOSUR

50 SALEM 80

ALMATHY (338)

63

HOODY (17) 63

50

(144)

KOLAR

MEPL

NELLORE PS (3.8) (37) KRISHNAPATNAM

VALLUR

50

50

TALAGUPPA

KURNOOL 63

NELMANGALA 50

50

63

50

(194)

50

50

CUDDAPAH

63

40%

(290)

(85)

50

50

63(AP)

SEPL

50

50

63

63

(40)

HIRIYUR

~

SRISAILAM

40%

50

63

40% 80

GUTTUR 50

50

(31)

(163)

III

(31)

63

GOOTY

JINDAL 50

63

(340)

KAIGA (163)

40%

50

63

MUNIRABAD

50 63

50

(340)

63

GMR

(227)

BTPS

63

VTS STG IV

50 50

50 RAICHUR

GAUTAMI

NUNNA

63

(2)

80

(140)

LKPPL

50

63

MB’NAGAR

GVK

(39)

50

N'SAGAR

50

(7)

MMD'PALLI

GAZUWAKA

VEMAGIRI

KHAMMAM

50

80

KONASEEMA

50

63

NARENDRA

63

63

63

80

63

(26)

MALKARAM

~

WARANGAL (118)

50

SHANKERPALLY

SIMHADRI

KTPS VI (364)

GAJWEL

50

TO JEYPORE

~

63

(12)

50

63

(220)

50

HYDERABAD

KALPAKA

(178)

(148)

DITCHIPALLY

63

50

50

KUDANKULAM 80

TUTICORN

* Early Commissioned Line Reactors of Cochin line is being used as Bus Reactors.

63 SRLDC, BANGALORE April 2013

NLDC


July 2013 Rev 0


N A T U H B

M A S S A N O A G I A G N O B A R A P R IB B W I R U G I L I IH R US G I L I H S

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पावर मैप पबीर् ू क्षेत्र


NLDC


July 2013 Rev 0


POWER MAP OF NORTH EAST REGIONAL GRID

China Along

v

Daporizo

Doomdooma

Ziro Tinsukia

Bhutan

Ranganadi

Naharlugan

Dhemaji

13

Margherita

Dibrugarh

AGBPP

Maran Bhalukpong

Khupi

Bhutan

Motonga(Bhutan)

Gelyphu(Bhutan)

Salakati

West Bengal

Gauripur

Kukurmara

BTPS (NTPC)

9

Sarusajai

Dimapur

Boko Rongkhon

8 4

3 Mawngap

Nangalbibra

6

2

Diphu

Langpi

7

Meluri Kopili

NEIGRIHMS

Khleihriat(S)

1

Nongstoin Mawlai Cherapunjee

19

Assam 1. Jogigopa 2. Dhaligaon 3. Nalbari 4. Bornagar 5. Sipajhar 6. Sisugram 7. CTPS

NLDC

8. Narengi 9. Rowta 10. Baghjap 11. Depota 12. Pavoi 13. NLakhimpur

11

6

Loktak Churachandpur

Bairabi

Ningthonkhong Kakching

Kolasib

9 10

Luangmual

9 Udaipur

Aizawl Zuangtui

Palatana

Saitual

14.- Bokaghat 15. Jorhat 16. LTPS 17. NTPS 18. Mariani 19. Panchgram 20. Panchgram(New)

Important Lines (in ckm) 1. 400 kV Misa-Balipara D/C - 190 2. 400 kV Balipara-Bongaigaon D/C - 580 3. 400 kV Balipara - Ranganadi D/C - 332 4. 400 kV Bongaigaon - Binaguri D/C - 436

Kumarghat

P.K. Bari Rokhia

Yaingangpokpi

Kongba

1

2 8

Imphal(S) Imphal Rengpang

Silchar

AGTPP 7

Karong

Haflong

Jiribam

3 4

20

Srikona Pailapool

Dullavcherra

Bangladesh

Kohima

Khleihriat

Leshka

Badarpur

5

Dimapur (S)

Khandong

Lumshnong

Meghalaya 1. Umiam 2. Umiam St I 3. Umiam St II 4. Umiam St III 5. Umiam St IV 6. Umtru 7. EPIP II (Norbong) 8. EPIP I (Raja) 9. Killing (Byrnihat)

Sankardevnagar

Haflong NEHU

Bangladesh Tripura 1. Dharmanagar 2. Kailashahar 3. Kamalpur 4. Dhalabil 5. Agartala 6. Bodhjangnagar 7. Jirania 8. Baramura 9. Teliamura 10. Ambasa 11 Surjamaninagar

Kiphire

Bokajan

Misa

Agia 5

Doyang Wokha

10

1

Golaghat

8

2

BTPS

Deomali

Mokokchung

18 Samaguri

Kahilipara 6

3

16

11

7

5

4

Bongaigaon

17

Nazira

14

12

21

Rangia

Birpara(ER)

Gossaigaon

Gohpur

Balipara 9

Binaguri(ER)

Sibsagar Majuli 15 Mariani(PG)

Nirjuli

Serchhip (Bukpui)

Bangladesh

Khawiva (Lunglei)


1. 220 kV Misa - Dimapur D/C - 247 2. 220 kV Misa - Mariani S/C - 220 3. 220 kV Misa- AGBPP S/C - 382.9 4. 220 kV Misa - Samaguri D/C - 68.8 5. 220 kV MIsa - Kopili T/C - 221.4 6. 220 kV Samaguri - Mariani S/C - 168 7. 220 kV Mariani - AGBPP S/C - 162.9 8. 220 kV Balipara - Samaguri S/C - 65 9 - 220 kV Sarusajai - Samaguri D/C - 247 10. 220 kV Bongaigaon - Salakati S/C - 1 11. 220 kV Salakati - BTPS D/C - 8 12. 220 kV Sarusajai - Langpi D/C - 216.4

NEEPCO (in MW) Ranganadi - 3x135 Doyang - 3x25 AGBPP - 4x33.6+2x35+3x30 AGTPP - 4x21 Khandong - 2x25 Kopili - 4x50 Kopili St II - 2x25 NHPC (in MW) Loktak - 3x35 LEGEND 400 kV 220 kV 132 kV Hydro Thermal POWERGRID NEEPCO NHPC Assam Meghalaya Tripura Others

July 2013 Rev 0

Revised on 03-May-13

2 x1500 MVA ICT

ANNEXURE XIV - POWER MAPS 2 x1500 MVA ICT

765kV GRID MAP

240 MVA L/R

MEERUT

MOGA 2x 240 MVAR B/R

2 x1000 MVA ICT 189 MVAR B/R 330 MVAR L/R

AGRA

I - 129 kM

II- 128 kM

2 x1000 MVA ICT 2 x 240 MVAR B/R

2 x1500 MVA ICT 240 MVAR B/R 240MVAR L/R

UNNAO

2 x1500 MVA ICT 2x 240 MVAR B/R 240 MVAR L/R

BHIWANI

LUCKNOW

1 X 240 MVAR B/R 1x 240 MVAR L/R

2 x1000 MVA ICT 189 MVAR B/R 330 MVAR L/R ANPARA C

2 x1500 MVA ICT FATEHPUR 330 MVAR B/R 3 x 330 MVAR L/R

GWALIOR 2 x1500 MVA ICT 2 x 240 MVAR L/R

4x1500 MVA ICT 1x 240 MVAR B/R 1x 240 MVAR L/R

I - 234 kM

II- 235 kM

JHATIKARA

BINA 2 x1000 MVA ICT 5 x 240MVAR L/R 1x 240 MVAR B/R

2 x1500 MVA ICT 2 x 240 MVAR B/R 240 MVAR L/R * USED AS B/R

BALIA

*

1 x 1500 MVA ICT 1 x 330 MVAR B/R 330 MVAR L/R

SATNA 2 x1000 MVA ICT 2 x 240MVAR L/R 240 MVAR B/R

SASARAM 330 MVAR Mid Point REACTOR

SASAN

I - 274 kM

1 x1000 MVA ICT II - 276 kM

BILASPUR 292 kM

SEONI

3 x1500 MVA ICT 240 MVAR B/R 2x 240 MVAR L/R

GAYA 3 x1500 MVA ICT 2 x 240 MVAR B/R 240 MVAR L/R

I - 337 kM

I - 22 kM

II - 338 kM

II - 22 kM

INDORE 3 x1500 MVA ICT 240 MVAR B/R 3x 240 MVAR L/R

1 x1500 MVA ICT

SIPAT 2 x1000 MVA ICT 2 x 240MVAR L/R 240 MVAR B/R

WARDHA

NLDC

3 x1500 MVA ICT 240 MVAR B/R 2 x 240 MVAR L/R


400kV 765kV charged at 765kV

July 2013 FutureRev 0


NLDC


July 2013 Rev 0


Nepal Electricity Authority, Fiscal Year 2006/07 - A Year in Review

67

A year in Review

FY 2006/07

NEA July 2013 Rev 0 Operating Procedures for National Grid 190 of 198 NLDC


NLDC


July 2013 Rev 0

Annexure XV- Glossary and Definitions ANNEXURE XV

Glossary and Definitions a) "Act" means the Electricity Act, 2003 as amended from time to time; b) "Ancillary Services" means in relation to power system (or grid) operation, the services necessary to support the power system (or grid) operation in maintaining power quality, reliability and security of the grid, eg. active power support for load following, reactive power support, black start, etc; c) "Automatic Voltage Regulator (AVR)" means a continuously acting automatic excitation control system to control the voltage of a Generating Unit measured at the generator terminals; d) "Available Transfer Capability (ATC)" means the transfer capability of the inter-control area transmission system available for scheduling commercial transactions (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; e) "Beneficiary" means a person who has a share in an ISGS f) "Bilateral Transaction" means a transaction for exchange of energy (MWh) between a specified buyer and a specified seller, directly or through a trading licensee or discovered at Power Exchange through anonymous bidding, from a specified point of injection to a specified point of drawal for a fixed or varying quantum of power (MW) for any time period during a month; g) "Black Start Procedure" means the procedure necessary to recover from a partial or a total blackout in the region; h) "BIS" means the Bureau of Indian Standards; i) "Bulk Consumer" means any Consumer who avails supply at voltage of 33 kV or above; j) "Capacitor" means an electrical facility provided for generation of reactive power; k) "Central Generating Station" means the generating stations owned by the companies owned or controlled by the Central Government; l) "Central Transmission Utility (CTU)" means any Government company, which the Central Government may notify under sub-section (1) of Section 38 of the Act; m) "Collective Transaction" means a set of transactions discovered in power exchange through anonymous, simultaneous competitive bidding by buyers and sellers; n) "Congestion" means a situation where the demand for transmission capacity exceeds the Available Transfer Capability; o) "Connection Agreement" means an Agreement between CTU, inter-state transmission licensee other than CTU (if any) and any person setting out the terms relating to a connection to and/or use of the Inter State Transmission System; NLDC


July 2013-Rev 0

Annexure XV- Glossary and Definitions p) "Connection Point" means a point at which a Plant and/ or Apparatus connects to the Transmission /Distribution System; q) "Connectivity" means the state of getting connected to the inter-State transmission system by a generating station, including a captive generating plant, a bulk consumer or an inter-State transmission licensee; r) "Control Area" means an electrical system bounded by interconnections (tie lines), metering and telemetry which controls its generation and/or load to maintain its interchange schedule with other control areas whenever required to do so and contributes to frequency regulation of the synchronously operating system; s) "Demand" means the demand of Active Power in MW and Reactive Power in MVAr of electricity unless otherwise specified; t) "Demand response" means reduction in electricity usage by end customers fromtheir normal consumption pattern, manually or automatically, in response to high UIcharges being incurred by the State due to overdrawal by the State at low frequency,or in response to congestion charges being incurred by the State for creatingtransmission congestion, or for alleviating a system contingency, for which such consumers could be given a financial incentive or lower tariff; u) "Despatch Schedule" means the ex-power plant net MW and MWh output of a generating station, scheduled to be exported to the Grid from time to time; v) "Disturbance Recorder (DR)" means a device provided to record the behavior of the pre-selected digital and analog values of the system parameters during an Event; w) "Data Acquisition System (DAS)" means a system provided to record the sequence of operation in time, of the relays/equipments as well as the measurement of pre-selected system parameters; x) "Drawal Schedule" means the summation of the station-wise ex-power plant drawal schedules from all ISGS and drawal from/injection to regional grid consequent to other long term access, medium term and short term open access transactions; y) "DVC" means the Damodar Valley Corporation established under sub-section (1) of Section 3 of the Damodar Valley Corporation Act, 1948;

z) "Entitlement" means a Share of a beneficiary (in MW / MWh) in the installed capacity/output capability of an ISGS; aa) "Event" means an unscheduled or unplanned occurrence on a Grid including faults, incidents and breakdowns; bb) "Event Logging Facilities" means a device provided to record the chronological sequence of operations, of the relays and other equipment; cc) "Ex-Power Plant" means net MW/MWh output of a generating station, after deducting auxiliary consumption and transformation losses;

NLDC


July 2013-Rev 0

Annexure XV- Glossary and Definitions dd) "Fault Locator (FL)" means a device provided at the end of a transmission line to measure/ indicate the distance at which a line fault may have occurred; ee) "Flexible Alternating Current Transmission System(FACTS)" means a power electronics based system and other static equipment that provide control of one or more AC transmission system parameters to enhance controllability and increase power transfer capability; ff) "Force Majeure" means any event which is beyond the control of the persons involved which they could not foresee or with a reasonable amount of diligence could not have foreseen or which could not be prevented and which substantially affects the performance by person such being the following including but not limited to :a) Acts of God, natural phenomena, floods, droughts, earthquakes and epidemics; b) Enemy acts of any Government domestic or foreign, war declared or undeclared, hostilities, priorities, quarantines, embargoes; c) Riot or Civil Commotion; d) Grid's failure not attributable to the person. gg) "Forced Outage" means an outage of a Generating Unit or a transmission facility due to a fault or other reasons which has not been planned; gg(i) “ Frequency Response Characteristic” is defined as the automatic, sustained change in the power consumption by load or output of generators that occurs immediately after a change in the control area’s load-generation balance and which is in a direction to oppose a change in the Interconnection’s frequency. hh) "Generating Company" means any company or body corporate or association or body of individuals, whether incorporated or not, or artificial juridical person, which owns or operates or maintains a generating station. ii) "Generating Unit" means an electrical Generating Unit coupled to a turbine within a Power Station together with all Plant and Apparatus at that Power Station which relates exclusively to the operation of that turbo-generator; jj) "Good Utility Practices" means any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period which could have been expected to accomplish the desired results at a reasonable cost consistent with good business practices, reliably, safely and with expedition; kk) "Governor Droop" means in relation to the operation of the governor of a Generating Unit, the percentage drop in system frequency which would cause the Generating Unit under restricted/free governor action to change its output from zero to full load; ll) "Grid Standards" means the standards specified by the Authority under clause (d) of the Section 73 of the Act; mm) "Extra High Voltage (EHV)" means where the voltage exceeds 33,000 volts under normal conditions, subject, however, to the percentage variation allowed by the Authority; nn) "Independent Power Producer (IPP)" means a generating company not owned/ controlled by the Central/State Government;

NLDC


July 2013-Rev 0

Annexure XV- Glossary and Definitions oo) "Indian Electricity Grid Code (IEGC) or Grid Code" means these regulations specifying the philosophy and the responsibilities for planning and operation of Indian power system ; pp) "Inter-State Generating Station (ISGS)" means a Central generating station or other generating station, in which two or more states have Shares; qq) "Inter State Transmission System (ISTS)" means i) Any system for the conveyance of electricity by means of a main transmission line from the territory of one State to another State ii) The conveyance of electricity across the territory of an intervening State as well as conveyance within the State which is incidental to such inter-state transmission of energy (iii) The transmission of electricity within the territory of State on a system built, owned, operated, maintained or controlled by CTU; rr) "Licensee" means a person who has been granted a license under Section 14 of the Act; ss) "Load" means the MW/MWh /MVAR/MVARh consumed by a utility/ installation; tt) "Long-term Access" means the right to use the inter-State transmission system for a period exceeding 12 years but not exceeding 25 years; uu) "Long-term customer" means a person who has been granted long-term access and includes a person who has been allocated central sector generation that is electricity supply from a generating station owned or controlled by the Central Government; vv) "Maximum Continuous Rating (MCR)" means the maximum continuous output in MW at the generator terminals guaranteed by the manufacturer at rated parameters; ww) "Medium-term Open Access" means the right to use the inter- State transmission system for a period exceeding 3 months but not exceeding 3 years; xx) "Medium-term customer" means a person who has been granted medium term open access: yy) "National Grid" means the entire inter-connected electric power network of the country; zz) "Net Drawal Schedule" means the drawal schedule of a Regional Entity after deducting the apportioned transmission losses (estimated); aaa) "NLDC" means the Centre established under sub-section (1) of Section 26 of the Act; bbb) "Operation" means a scheduled or planned action relating to the operation of a System; ccc) "Operation Coordination Sub- Committee (OCC)" means a sub-committee of RPC with members from all the regional entities which decides the operational aspects of the Regional Grid; ddd) "Operating range" means the operating range of frequency and voltage as specified under the operating code (Part-5) of IEGC eee) "Pool Account" means regional account for (i) Payments regarding unscheduled-interchanges (UI Account) or NLDC


July 2013-Rev 0

Annexure XV- Glossary and Definitions (ii) Reactive energy exchanges (Reactive Energy Account) (iii) Congestion Charge (iv) Renewable Regulatory charge, as the case may be; fff) "POWERGRID" means Power Grid Corporation of India Limited which has been notified as CTU. ggg) "Power Exchange" means the power exchange which has been granted registration in accordance with CERC (Power Market Regulations), 2010 as amended from time to time; hhh) "Power System" means all aspects of generation, transmission, distribution and supply of electricity and includes one or more of the following, namely: (a) generating stations; (b) transmission or main transmission lines; (c) sub-stations; (d) tie-lines; (e) load despatch activities; (f) mains or distribution mains; (g) electric supply lines; (h) overhead lines; (i) service lines; (j) works; iii) "Protection Coordination Sub-Committee" means a sub-committee of RPC with members from all the regional entities which decide on the protection aspects of the Regional Grid; jjj) "Reactor" means an electrical facility specifically designed to absorb Reactive Power; kkk) "Regional Entity" means such persons who are in the RLDC control area and whose metering and energy accounting is done at the regional level; lll) "Regional .Power Committee (RPC)" means a Committee established by resolution by the Central Government for a specific region for facilitating the integrated operation of the power systems in that region; mmm) "RPC Secretariat" means the Secretariat of the RPC. nnn) "Regional Energy Account (REA)" means a regional energy account prepared on monthly basis by the RPC Secretariat for the billing and settlement of 'Capacity Charge', 'Energy Charge' and transmission charges; nnn(i) “Reliability Co-Ordinator” means officials in RLDCs/ NLDC designated to help in secure, safe and efficient operation of the power system by discharging the following functions: 1. 2. 3. 4.

Assessment of the Transfer Capability and advise the margins for STOA accordingly Co-ordinate outage of transmission network Analysis of abnormal events in the system and its bearing on system security Maintain a close liaison with the operation staff and provide inputs for effective decision making in realtime on matters related to grid security 5. Co-ordinate with each other so as to have the same big picture of the pan lndia grid.

NLDC


July 2013-Rev 0

Annexure XV- Glossary and Definitions ooo) "Regional Grid" means the entire synchronously connected electric power network of the concerned Region; ppp) "Regional Load Despatch Centre (RLDC)" means the Centre established under sub-section (1) of Section 27 of the Act; qqq) "Share" means percentage share of a beneficiary in an ISGS either notified by Government of India or agreed through contracts and implemented through long term access; rrr) "Short-term Open Access" means open access for a period up to one (1) month at one time; sss) "Spinning Reserve" means part loaded generating capacity with some reserve margin that is synchronized to the system and is ready to provide increased generation at short notice pursuant to dispatch instruction or instantaneously in response to a frequency drop; ttt) "Standing Committee for Transmission Planning" means a Committee constituted by the CEA to discuss, review and finalise the proposals for expansion or modification in the ISTS and associated intra-state systems; uuu) "SEB" means State Electricity Board which term includes State Electricity Department; vvv) "SERC" means State Electricity Regulatory Commission www) "State Load Despatch Centre (SLDC)" means the Centre established under subsection (1) of Section 31 of the Act; xxx) "State Transmission Utility (STU)" means the Board or the Government Company specified as such by the State Government under sub-section (1) of Section 39 of the Act; yyy) "Static VAR Compensator (SVC)" means an electrical facility designed for the purpose of generating or absorbing Reactive Power; zzz) "Technical Coordination Committee (TCC)" means the committee set up by RPC to coordinate the technical and commercial aspects of the operation of the regional grid; aaaa) "Time Block" means block of 15 minutes each for which Special Energy Meters record values of specified electrical parameters with first time block starting at 00.00 Hrs; bbbb) "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; cccc) "Transmission License" means a License granted under Section 14 of the Act to transmit electricity; dddd) "Transmission Planning Criteria" means the policy, standards and guidelines issued by the CEA for the planning and design of the Transmission system; eeee) "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; NLDC


July 2013-Rev 0

Annexure XV- Glossary and Definitions ffff) "Unscheduled Interchange (UI)" means in a time block for a generating station or a seller means its total actual generation minus its total scheduled generation and for a beneficiary or buyer means its total actual drawal minus its total scheduled drawal; gggg) "User" means a person such as a Generating Company including Captive Generating Plant or Transmission Licensee (other than the Central Transmission Utility and State Transmission utility) or Distribution Licensee or Bulk Consumer, whose electrical plant is connected to the ISTS at a voltage level 33kV and above. Words and expressions used in these regulations and not defined herein but defined in the Act shall have the meaning assigned to them under the Act.

NLDC


July 2013-Rev 0

Rgmo Operation Procedure

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