operating procedures of nr_2013-14.pdf

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Operating Procedure

For

Northern Region

[In compliance with Regulation 5.1 (f) of Indian Electricity Grid Code]

May 2013

Rev 0

Northern Regional Load DespatchCentre

18-A, Shaheed Jeet Singh Sansanwal Marg, Qutab Institutional Area

(Katwaria Sarai), New Delhi-110016

Ph: 011-26536832


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Table of Contents

1.0 GENERAL................................................................................................................................................................. 3

1.1 INTRODUCTION.................................................................................................................................................. 3

1.2 OBJECTIVE........................................................................................................................................................... 3

1.3 SCOPE ................................................................................................................................................................... 3

1.4 STRUCTURE OF OPERATING PROCEDURE................................................................................................... 31.5 OPERATING MANPOWER ................................................................................................................................. 5

1.6 MANAGEMENT OF OPERATING PROCEDURE ............................................................................................. 5

2.0 PLANNED OUTAGE COORDINATION.............................................................................................................. 6

2.1 OVERVIEW........................................................................................................................................................... 6

2.2 PLANNED OUTAGE COORDINATION PROCESS........................................................................................... 6

3.0 SWITCHING COORDINATION ........................................................................................................................... 8

3.1 OVERVIEW........................................................................................................................................................... 8

3.2 SWITCHING OF SYSTEM ELEMENTS FOR THE FIRST TIME ...................................................................... 8

3.3 SWITCHING OF IMPORTANT ELEMENTS ...................................................................................................... 8

3.4 OTHER PRECAUTIONS TO BE TAKEN DURING SWITCHING..................................................................... 9

4.0 FREQUENCY CONTROL .................................................................................................................................... 11

4.1 OVERVIEW......................................................................................................................................................... 11

4.2 PRIMARYRESPONSE....................................................................................................................................... 11

4.3 SUPPLEMENTARY CONTROL........................................................................................................................ 11

4.4 TERTIARY RESPONSE ..................................................................................................................................... 11

4.5 PREVENTIVE MEASURES DURING HIGH FREQUENCY CONDITIONS................................................... 12

4.6 PREVENTIVE MEASURES DURING LOW FREQUENCY CONDITIONS.................................................... 12

4.7 A, B, C MESSAGES ISSUED BY NRLDC ......................................................................................................... 13

4.8 DEFENCE PLAN FOR FREQUENCY CONTROL............................................................................................ 13

5.0 VOLTAGE CONTROL.......................................................................................................................................... 14

5.1 OVERVIEW......................................................................................................................................................... 14

5.2 VAR INTERCHANGE BY DRAWEE UTILITY................................................................................................ 14

5.3 SHUNT CAPACITOR BANK SWITCHING ...................................................................................................... 14

5.4 STATIC VAR COMPENSATOR OPERATION................................................................................................. 145.5 SWITCHING OF BUS REACTORS AND SWITCHABLE LINE REACTORS ................................................ 15

5.6 VAR GENERATION/ ABSORPTION BY GENERATING UNITS .................................................................. 15

5.7 CHANGING TRANSFORMER TAP POSITION ............................................................................................... 15

5.8 LOAD MANAGEMENT FOR CONTROLLING THE LOW VOLTAGE.......................................................... 15

5.9 HVDC FILTER BANK SWITCHING ................................................................................................................. 15

5.10 SWITCHING-OFF OF THE LINES IN CASE OF HIGH VOLTAGE ................................................................ 16

5.11 SUMMARY......................................................................................................................................................... 16

5.12 DEFENCE PLAN FOR VOLTAGE CONTROL................................................................................................. 16

6.0 CONGESTION MANAGEMENT AND ALLEVIATION.................................................................................. 17

6.1 GENERAL ........................................................................................................................................................... 17

6.2 PERMISSIBLE EQUIPMENT LOADING.......................................................................................................... 17

6.3 ASSESSMENT OF TRANSFER CAPABILITY................................................................................................. 17

6.4 MAJOR CORRIDORS/FLOW GATES IN NORTHERN REGION.................................................................... 186.5 MONITORING OF CONGESTION .................................................................................................................... 18

6.6 GENERATION RESCHEDULING..................................................................................................................... 18

6.7 CURTAILMENT OF SCHEDULED TRANSACTIONS.................................................................................... 18

6.8 PROCEDURE FOR RELIEVING CONGESTION ............................................................................................. 18

7.0 DEMAND MANAGEMENT.................................................................................................................................. 19

7.1 OVERVIEW......................................................................................................................................................... 19

7.2 DEMANDESTIMATION................................................................................................................................... 19

7.3 DEMAND CONTROL......................................................................................................................................... 20

7.4 PROTOCOL FOR HANDLING SUDDEN REDUCTION IN DEMAND........................................................... 21


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NRLDC: Operating Procedure for Northern Region-May-2013 Page 2 of45

8.0 SCHEDULING AND DESPATCH........................................................................................................................ 22

8.1 OVERVIEW......................................................................................................................................................... 22

8.2 JURISDICTION OF NRLDC............................................................................................................................... 22

8.3 APPLICATION FOR REGISTRATION AS REGIONAL ENTITY ................................................................... 22

8.4 SCHEDULING OF LONG TERM AND MEDIUM TERMCONTRACTS........................................................ 23

8.5 SCHEDULING OF HYDRO STATION:............................................................................................................. 24

8.6 SCHEDULING OF SHORT TERM CONTRACTS ............................................................................................ 24

8.7 TIME LINE FOR INFORMATION EXCHANGE FOR SCHEDULING............................................................ 24

8.8 TRANSMISSION LOSSES................................................................................................................................. 258.9 PEAKING ............................................................................................................................................................ 25

8.10 RAMP RATE....................................................................................................................................................... 258.11 CURTAILMENT ................................................................................................................................................. 25

8.12 REVISION OF SCHEDULES REQUESTED BY REGIONAL ENTITIES ........................................................ 25

8.13 REVISION IN SCHEDULE INITIATED BY NRLDC........................................................................................ 27

8.14 MODERATION OF SCHEDULE BY NRLDC................................................................................................... 27

8.15 STANDING INSTRUCTIONS BY SLDC TO NRLDC....................................................................................... 28

8.16 RESERVOIR FILING/DEPLETION FOR STORAGE TYPE HYDRO POWER STATIONS ........................... 28

8.17 IMPLEMENTED SCHEDULE ISSUED BY NRLDC......................................................................................... 28

8.18 MEDIA FOR EXCHANGE OF INFORMATION ............................................................................................... 29

9.0 SETTLEMENT SYSTEM...................................................................................................................................... 30

9.1 OVERVIEW......................................................................................................................................................... 30

9.2 SETTLEMENT PERIOD..................................................................................................................................... 30

9.3 INTERFACE METERING AND CONTROL AREA BOUNDARY................................................................... 30

9.4 TIME CORRECTION AND METER CALIBRATION ...................................................................................... 309.5 DATA PROCESSING.......................................................................................................................................... 30

9.6 ENERGY ACCOUNTING................................................................................................................................... 30

9.7 FORWARDING ENERGY DATA FROM NRLDC TO NRPC SECRETARIAT............................................... 31

9.8 ADDITIONAL DATA TO BE FORWARDED TO NRPC SECRETARIAT ...................................................... 31

10.0 DEFENCE MECHANISMS FOR THE SYSTEM............................................................................................... 32

10.1 GENERAL........................................................................................................................................................... 32

10.2 UNIT PROTECTION SYSTEM .......................................................................................................................... 32

10.3 FLAT FREQUENCY AND RATE OF CHANGE OF FREQUENCY RELAY LOAD SHEDDING SCHEME . 32

10.4 UNDER VOLTAGE LOAD SHEDDING SCHEME........................................................................................... 33

10.5 SYSTEM PROTECTION SCHEME.................................................................................................................... 33

10.6 ISLANDING SCHEME ....................................................................................................................................... 34

11.0 GRID INCIDENT, GRID DISTURBANCE AND REVIVAL............................................................................ 35

11.1 GENERAL ........................................................................................................................................................... 35

11.2 DEFINITION OF GRID INCIDENT AND GRID DISTURBANCE................................................................... 35

11.3 CATEGORISATION OF GRID DISTURBANCES............................................................................................ 35

11.4 DEFERENMENT OF PLANNED OUTAGE DURING GRID DISTURBANCE ............................................... 36

11.5 RESCHEDULING DURING GRID DISTURBANCE ........................................................................................ 36

11.6 SYSTEM REVIVAL............................................................................................................................................ 36

11.7 DECLARATION OF SYSTEM NORMALISATION POST GRID DISTURBANCE........................................ 37

12.0 EVENT INFORMATION AND REPORTING.................................................................................................... 38

12.1 OVERVIEW......................................................................................................................................................... 38

12.2 EVENT INFORMATION .................................................................................................................................... 38

12.3 REPORTING SYSTEM....................................................................................................................................... 38

13.0 DATA ACQUISITION AND COMMUNICATION SYSTEM........................................................................... 42

13.1 OVERVIEW......................................................................................................................................................... 4213.2 RECORDING INSTRUMENTS AND COMMUNICATION FACILITIES ....................................................... 42

13.3 CYBER SECURITY ............................................................................................................................................ 42

LIST OF ANNEXURES................................................................................................................................................... 44

REFERENCES ................................................................................................................................................................. 45


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CHAPTER 1

1.0 GENERAL

1.1 INTRODUCTION

The Northern Regional power system covers geographical areas in Jammu and Kashmir,

Punjab, Himachal Pradesh, Uttarakhand, Rajasthan, UT Chandigarh, Delhi, Haryana and Uttar

Pradesh. It comprises of fifty one (52) regional entities viz. 36 (thirty six) generating stations,

12 (twelve) buyers/Drawee Utilities and 4 (four) inter-state transmission licensees as on 15th

May 2012.

Regulation 5.1(f) of the Central Electricity Regulatory Commission (Indian Electricity Grid

Code) Regulations, 2010, stipulates that a set of detailed internal operating procedure for each

regional grid shall be developed and maintained by respective Regional Load Despatch

Centres, in consultation with the regional constituents. In compliance with the above

regulations, this document viz. Operating Procedures for Northern Region has been

prepared by the Northern Regional Load Despatch Centre in consultation with the regional

constituents of the Northern Region..

1.2 OBJECTIVE

The objective of this procedure is to compile various provisions in the statute and regulations

for guidance of the staff of the NRLDC, SLDC and regional entities in the Northern Region..

1.3 SCOPE

The Operating Procedures for Northern Region applies to the power system in Northern

Region. These procedures are to be read in conjunction with the Central Electricity Regulatory

Commission (Indian Electricity Grid Code) Regulations, 2010 and Central Electricity

Regulatory Commission (Indian Electricity Grid Code) (First Amendment) Regulations, 2012.

The Operating Procedures are without prejudice to the NRLDC s power to give directions and

exercise supervision and control as stated under Sections 28 and 29 of the Electricity Act,2003.

This document would come in force with immediate effect. It super cedes the Operating

Procedures issued earlier by NRLDC in May 2012.

1.4 STRUCTURE OF OPERATING PROCEDURE

The Operating Procedures for Northern Region consists of the following chapters.

1.4.1 Chapter-1: General

This chapter describes the objective, scope and structure of the Operating Procedures for

Northern Region.

1.4.2 Chapter-2: Planned Outage Coordination

This chapter describes the procedures for coordination of planned outage

1.4.3 Chapter-3: Switching Coordination

This chapter describes the protocol to be followed while coordinating switching operation in

the Regional grid.


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The details indicated in this document may not be exhaustive. They are intended to serve only

as a guideline for efficient system operation. In particular, these procedures do not cover the

tools required for efficient and effective system operation and analysis viz. Communication

Systems, Supervisory Control & Data Acquisition Systems (SCADA), Energy Management

Systems (EMS), and other recording and control equipment. It is expected that these

requirements would be provided by all concerned to enable efficient system operation.

1.5 OPERATING MANPOWER

The control rooms of all SLDCs, power plants, grid substations as well as any other control

centres of regional constituents shall be manned round the clock by qualified and adequately

trained manpower who would remain vigilant and cooperative at all the times so as to

maintain the system safety and security and operate it in a most optimum manner.

1.6 MANAGEMENT OF OPERATING PROCEDURE

The Operating Procedure shall be maintained by NRLDC and would be reviewed annually or

earlier in case significant changes taking place in the system warrant a review. Comments and

suggestions on the document may be sent to the following address:General Manager

Northern Regional Load Despatch Centre

18-A, Qutub Institutional Area

Shaheed Jeet Singh Sansanwal Marg

New Delhi-110016

*****


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CHAPTER-2

2.0 PLANNED OUTAGE COORDINATION

2.1 OVERVIEW

All electrical equipments may require to be taken out of service for routine or emergency

maintenance to prevent damage and failure. Outage of power system elements may also be

required to facilitate network augmentation related activities. Since outages in the system have

an effect on the network adequacy and security, they need to be planned and coordinated

carefully. Planning of outage is to be done in line with regulation 5.7.4 of the IEGC. This

chapter elaborates the procedure for availing outage of important elements in the system.

2.2 PLANNED OUTAGE COORDINATION PROCESS

Requisitions for planned shutdown shall be routed through NRPC as given in Regulation 5.7.4

of IEGC. The annual outage plan for Northern Region shall be finalized by NRPC Secretariat

in consultation with NLDC and NRLDC. The same shall be uploaded by NRPC on its website.

The above outage plan shall be reviewed by NRPC Secretariat on quarterly and monthly basis

in coordination with all parties.

Shutdown requisitions approved by NRPC/OCC shall be forwarded to NRLDC at least 3 days

prior to the date on which the shutdown is to be availed. If any deviation is required, the same

shall be with prior permission of NRLDC. Requisitions for shutdown timing shall be planned

properly and works shall be completed within approved shutdown timings.

2.2.1 Re-scheduling of approved outage plan

In the event of any requirement to re-schedule any planned shutdown or to avail an emergency

/ unforeseen shutdown not anticipated earlier, the concerned entity shall forward a request to

NRLDC indicating the nature of emergency or the reason for deferment. NRLDC would

approve such unforeseen outages / re-scheduling of an already planned outage based on the

exigency of the case vis--vis system conditions. In case, any spill over to the next monthoccurs on account of the deferment, the same would have to be brought to the notice of the

Operation Co-ordination Committee by the concerned entity.

On daily basis, NRLDC would review the outage schedule for the next two days and in case of

any contingency or conditions described in regulation 5.7.4 (f & g) of the IEGC, defer any

planned outage as deemed fit clearly stating the reasons thereof. NRLDC/NLDC may defer the

requested planned outage in case of

(i) Grid disturbance

(ii) System isolation

(iii) Partial blackout in a state

(iv) Any other event in the system that may have an adverse impact on the system securityby the proposed outage

The revised dates in such cases would be finalised in consultation with the concerned utilities.

Deviations from planned outages /shutdown shall compile on monthly basis along with reason

for deviations.


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2.2.2 Final approval from NRLDC

In line with the regulation 5.7.4 (i) each user, CTU and STU in Northern Region shall obtain

the final approval in the form of an operation code from NRLDC prior to availing an outage.

All preparatory works for maintenance must be done well in advance before availing the code

so as to avoid any idling time. Such requests shall be forwarded to the NRLDC control room

sufficiently in advance so as to provide adequate time for carrying out the adjustments in the

network/despatch (if required) for facilitating the outage.

Similarly, an operation code would have to be obtained from NRLDC before reviving the

element after shut down.

2.2.3 Safety measures and switching operations during outage

The operation code issued by NRLDC for opening / revival of the transmission element

signifies such approval only from the system point of view notwithstanding anything contained

in respect of safety measures and other switching operations to be carried out locally. The

related line / substation personnel would be responsible for ensuring all safety precautions to

be followed while opening / closing of any element to avoid any threat to operating personnel

and equipment.

2.2.4 Timely return of shutdown

During the period of shutdown, the User/STU/CTU/licensee shall keep NRLDC apprised

regarding the status of work and the likely time of return of the shut down. All efforts shall be

made by the constituents for timely return of shutdowns and delays if any shall immediately be

reported to NRLDC along with the reasons and likely time of return of shut down.

Where it is foreseen that return of Permit To Work (PTW) could be delayed due to physical

distance involved in case of a transmission line, mobile phones would be used for

communication with the substation to minimise the outage period. It shall be the responsibilityof utility requesting the shutdown to ascertain that all work has been completed within the

stipulated time and the transmission element can be safely taken back into service.

2.2.5 Maintenance work on opportunity basis

Any maintenance work on opportunity basis proposed to be carried out by related agencies

during the period of shutdown already approved by NRLDC would need the approval of

NRLDC. The same if approved would also be intimated by NRLDC to the agency, which

initially applied for the planned shutdown. On a monthly basis, a list of all shutdowns that have

been taken on opportunity basis shall be compiled. The delay or extension in returning the

shutdown attributable to such opportunity shutdown shall also be indicated separately.

Note: Procedure for Transmission Elements Outage Planning is under discussion and will

withstand all the above after it get finalized.

*****


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CHAPTER-3

3.0 SWITCHING COORDINATION

3.1 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 of the Northern Regional Grid is carried out on a User/STU system, the

Users, SLDC, STU, CTU, licensee shall inform NRLDC, in case the Northern Regional grid

may, or will experience an operational effect.

3.2 SWITCHING OF SYSTEM ELEMENTS FOR THE FIRST TIME

In line with Regulation 6 (1) of the Central Electricity Authority (Grid Standards) regulations

2010, no entity shall introduce an element in the ISTS of Northern Grid without the

concurrence of NRLDC in the form of an operation code. In case a new power system element

in Northern 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 NRLDC with regards to registration as regional entity

Signed Connection Agreement if applicable

Availability of telemetry of station/Element at the NRLDC/SLDC

Availability of voice communication with the station at NRLDC/SLDC

Interface meter installed and tested by downloading data and forwarding it to NRLDC

Single Line Diagram

Healthiness of Protection System/Protection Setting

Statutory clearance has already been obtained

3.3 SWITCHING OF IMPORTANT ELEMENTS

In line with regulation 5.2 (a, b, c), of the IEGC no part of the Northern 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 NRLDC.

Important elements of the regional grid, which have a bearing on the network security, is

compiled and issued by NRLDC as a separate document [IEGC 5.2 (c)]. The regional entities,

users, STU, CTU, licensee shall obtain operation code from NRLDC before carrying out any

switching operation on any of the important elements of the Northern Regional grid. Shutdown of any 400 kV bus at substation needs approval of NRLDC.

In respect of double main and transfer switching scheme at 400 kV substations, NRLDC 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 NRLDC.

However, while availing such shutdowns or carrying out switching operations it must be


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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

NRLDC.

In line with the recommendations of the NRPC Protection Sub-committee vide Summary

Record of Discussion of the 13th

protection sub-committee meeting held on 28th

January,

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/NRLDC.

Emergency switching if any have to be carried out and immediately informed to NRLDC

within a reasonable time, of ten minutes. Likewise, tripping of any of these important elements

should also be informed to NRLDC within a reasonable time indicating the likely time of

restoration. In case of single phase to ground fault (with low fault current level say


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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 breakerdiverting 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.

NRLDCs approval would be required for taking this facility out of service. Likewise,

in case any transfer breaker at any 400 kV substations having two main and transfer bus

scheme is engaged, the same would be informed to NRLDC.

(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 NRLDC 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 NRLDC, and ifthere is a probability of further delay same code could be revalidated by NRLDC within

that half an hour. The utility obtaining at one end shall intimate the other end utility.

*****


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CHAPTER- 4

4.0 FREQUENCY CONTROL

4.1 OVERVIEW

The nominal frequency of operation in Indian grid is 50.0 Hz. All the regional entities would

make all possible efforts to ensure that the grid frequency is maintained within the band

specified in Indian Electricity Grid Code.

The regional entities shall regulate their generation and/or consumers load so as to maintain

their actual interchange with the grid close to the schedule. Sudden reduction in generating unit

output by more than one hundred (100) MW unless, under an emergency condition or, to

prevent an imminent damage to the equipment, shall be avoided, particularly when frequency

is falling below 49.7 Hz. 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. [IEGC 5.2 (j)]

4.2 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.

4.3 SUPPLEMENTARY CONTROL

All regional entities shall provide supplementary control in line with regulation 5.2 (i) of

IEGC. The frequency linked dispatch guidelines for providing supplementary control are

enclosed as Annex-II.

In line with regulation 6.4.5 of IEGC, the regional grids shall be operated as power pools with

decentralized scheduling and despatch, in which the States shall have operational autonomy.

Further in line with regulation 6.4.6, the regional entities are allowed to deviate from theirinterchange schedule as long as such deviations do not cause system parameters to deteriorate

beyond permissible limits and/or do not lead to unacceptable line loading.

4.4 TERTIARY RESPONSE

In line with IEGC regulation 5.4.2 (a) SLDC/SEB/distribution licensee and bulk consumer

shall initiate action to restrict the drawal of its control area, from the grid, within the net drawal

schedule whenever the system frequency falls to 49.8 Hz. Each SLDC shall regulate the load /

own generation under its control so that it may not draw more than its net drawal schedule

during low frequency conditions and less than its drawal schedule during high frequency

conditions.

Regional entity generating stations shall maintain generation such that it may not generate less

than its generation schedule during low frequency conditions and more than its generation

schedule during high frequency conditions. In case any state constituent is likely to face power

shortage situation despite requisitioning its full entitlement from long term bilateral contracts,

then it shall endeavour to enter into a bilateral agreement with the other state constituents

having a power surplus and vice-versa. In any case, during low frequency conditions no state

would carry out overdrawal.


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4.5 PREVENTIVE MEASURES DURING HIGH FREQUENCY CONDITIONS

In case the frequency is high (above 50.2 Hz) and is in increasing trend then the following

actions may be taken in order of priority:

1. Lifting of planned load shedding, curtailments if any

2. Generation reduction at hydro stations having storage capability

3. Generation backing down in coal fired thermal stations to ~ 70% & Gas station to 50-

60% (Refer Annex-III (A)) within state control area (in case it is under drawing) as per

merit order based on variable charges

4. Downward revision of requisitions from ISGS as per merit order on request of

beneficiaries

5. Downward revision of generation schedule in thermal stations by NRLDC to technical

minimum

6. Reduction in generation in nuclear stations to the extent possible

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.

While the grid frequency is higher than 50.2 Hz, the MW generation at no generating station

(irrespective of type and ownership) shall be increased. Provided that when the frequency hasrisen from a previous lower level to 50.2 Hz. or higher, and due to normal governor action, the

MW output of a generating unit has fallen to a level requiring oil support or which results in

unstable operation of the unit, then the MW output may be increased to the lowest level:

At which oil support is not required, and

At which the unit can operate in a stable and safe manner.

Similarly, no generating unit shall be synchronised with the grid while the grid frequency is

above 50.2 Hz. or higher, except with the specific concurrence of NRLDC and in case of

nuclear units, which may have to be re-synchronised to prevent poisoning out of the reactor.

NRLDC would separately issue frequency linked despatch guidelines to be followed by each

power station.

In line with regulation 5.2 (u), NRLDC shall make all efforts to evacuate the available solar

and wind power and treat as a must run station. However NRLDC may instruct the solar/wind

generator (in case it is a regional entity) to back down generation on consideration of grid

security or safety of any equipment or personnel is endangered and solar/wind generator shall

comply with the same.

High frequency conditions in the grid are generally accompanied by high voltage. Requisite

measures to control over voltage may also have to be taken. The chapter on voltage control

may be referred for this.

4.6 PREVENTIVE MEASURES DURING LOW FREQUENCY CONDITIONS

There are detailed provisions in the IEGC with regard to demand control. All efforts must be

made to avoid situation of low frequency. The chapter on demand estimation and control may

be referred for this purpose. However in case the frequency is low (below 49.7 Hz) and is in

decreasing trend then the following actions may be taken:


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Increase in generation wherever margins are available

Upward revision in requisition in ISGS (to the extent un-dispatched) on request of

beneficiaries

Increase in generation by coal/gas fired stations within State control area (if it is over

drawing) as per merit order based on variable charges

Suo moto increase in despatch schedule of ISGS (in case un-despatched) by NRLDC

Suo moto demand curtailment by State control areas

Demand regulation by NRLDC by switching radial feeders (List of feeders as given by

respective utility is enclosed in Annex-III (B)

Low frequency conditions are generally associated with low voltage. Requisite measures to

control low voltage may also have to be taken. The chapter on voltage control may be referred

for this.

4.7 A, B, C MESSAGES ISSUED BY NRLDC

NRLDC shall issue overdrawal messages (A, B, C) based on values appearing in SCADA. The

logic for issuance of message A, B and C and the format in which these messages shall be

issued is enclosed as Annex IV.

4.8 DEFENCE PLAN FOR FREQUENCY CONTROL

The details may be referred in Chapter on Defence Plan.

*****


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CHAPTER- 5

5.0 VOLTAGE CONTROL

5.1 OVERVIEW

As defined in the IEGC section 5.2 (s), and para 5.3 of the Manual on Transmission Planning

Criteria (Jan 2013), the operating range of the voltage at various voltage levels of grid is as

follows:

Table 1: Voltage operating range

Voltage in kV(rms)

Normal rating Emergency rating

Nominal Maximum Minimum Maximum Minimum

765 800 728 800 713

400 420 380 420 372

220 245 200 245 194

132 145 120 145 119

110 121 99 123 97

66 72 60 72.5 5933 36 30

The maximum and minimum values in the above table are the outer limits and all the

constituents would endeavour to maintain the voltage level well within the above limits.

5.2 VAR INTERCHANGE BY DRAWEE UTILITY

The drawee utilities/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 minimise the VAR drawal at interchange point when the

voltage at that point is below nominal value and shall not return VARs when the voltage is

above the nominal value. In fact the beneficiaries are expected to provide local VARcompensation 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.

5.3 SHUNT CAPACITOR BANK SWITCHING

The switching of capacitor banks shall be as per the guidelines for switching capacitor banks

formulated by the Operation Coordination subcommittee. These are enclosed as Annex-V.

However if the voltage at the bus on which capacitor is connected is 1.1 per unit or higher the

capacitor shall necessarily be switched off.

5.4 STATIC VAR COMPENSATOR OPERATION

Static VAR compensator shall normally be operated in susceptance control mode. The setting

for SVC voltage reference shall be +/- 5% of 400 kV and shall be selected in consultation with

NRLDC. If required the SVC shall be operated in voltage control mode or VAR control mode

in consultation with NRLDC.


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5.5 SWITCHING OF BUS REACTORS AND SWITCHABLE LINE REACTORS

Bus reactors at 400 kV shall be taken into service whenever bus voltage exceeds 405 kV and

they shall be taken out of service when voltage is below 395 kV. Standing instruction may be

issued to the operating personnel at the substation. There may be exception with permission of

NRLDC

NRLDC shall issue operating code for switching of switchable line reactors.

5.6 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 supergrid voltage and to bring it

towards the 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 limits of the respective generating units [IEGC 6.6.6].

The On-Load Tap Changers (OLTCs) or Off load tap changers on the generator would also be

used to take care of seasonal variations in the voltage profile.

5.7 CHANGING TRANSFORMER TAP POSITION

The transformer tap positions on different Inter-connecting transformers forming important

elements of Regional Grid shall be changed as per requirements in order to improve the grid

voltage. NRLDC shall coordinate and advise the settings of different tap positions and any

change in their positions shall be carried out only after consultation with NRLDC [IEGC

6.6.5].

5.8 LOAD MANAGEMENT FOR CONTROLLING THE LOW VOLTAGE

All the state constituents shall identify the radial feeders in their areas which have significant

reactive drawals and which can be disconnected (manually or through Under Voltage relay) in

order to improve the voltage conditions in the event of voltage dropping to low levels. Thedetails of all such feeders shall be kept handy in the respective control rooms and standing

instruction would remain with the operating personnel to obtain the requisite relief in the hour

of crisis by disconnecting such feeders.

In case the state constituents do not take the requisite measures and the voltage drops down to

critically low levels (say 380kV and below at 400kV bus), then NRLDC may resort to

regulatory measures by opening of lines including those, feeding radial loads in the areas of

defaulting constituents [IEGC 6.6.3]. While taking such action, NRLDC would duly consider

that the same does not result in affecting ISGS generation.

5.9 HVDC FILTER BANK SWITCHING

During conditions of high voltage in the grid, the switchable filter banks installed at the HVDC

terminal stations shall be switched off wherever feasible in consultation with the operators at

the terminal substations.


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5.10 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 have been exhausted, selected 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 NRLDC in real time and as per the standing instructions

issued from time to time. While taking such action, NRLDC would duly consider that the same

does not result in affecting ISGS generation.

5.11 SUMMARY

The following specific action at Grid Substations / Generating Stations shall be taken in the

event of voltage going high / low.

In the event of high voltage (e.g., 400kV bus voltages going above 410kV), the following

specific steps would be taken by the respective grid substations / generating station at their

own, unless specifically mentioned by NRLDC otherwise;

The bus reactors be switched in

The manually switchable capacitor banks be taken out

The switchable line/ tertiary reactors be taken in Operate synchronous condensers for VAR absorption

Operate hydro generators / gas turbines as synchronous condenser for VAR absorption

wherever possible

Opening of the lightly loaded lines in consultation with NRLDC, keeping in view thesecurity of the balance network.

In the event of low voltage, (e.g. 400kV bus voltages going down below 390kV), the following

specific steps would be taken by the respective grid substations / generating station at their

own, unless specifically mentioned by NRLDC otherwise;

The bus reactors be switched out

The capacitor banks be switched in

The switchable line / tertiary reactors be taken out

Operate synchronous condensers for VAR generation

Operate hydro generators / gas turbines as synchronous condenser for VAR generation,

wherever possible

Closing of lines which were opened to control high voltage, in consultation with NRLDC

5.12 DEFENCE PLAN FOR VOLTAGE CONTROL

The details may be referred in Chapter on Defence Mechanism for Northern Region.

******


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CHAPTER- 6

6.0 CONGESTION MANAGEMENT AND ALLEVIATION

6.1 GENERAL

The system planner generally designs a power system, which complies with the various

transmission security standards and associated criteria mentioned in section 3.5 of the IEGC.

Operating the system securely, within its design and limitations, is a fundamental requirement

if security of power supply is to be maintained. This chapter describes the actions required on

the part of the system operator to keep the network secured at all times against contingencies.

6.2 PERMISSIBLE EQUIPMENT LOADING

As per the CEA Manual on Transmission Planning Criteria, Jan 2013 all the system parameters

line voltages, loadings, frequency shall be within permissible normal limits even under N-1 or

single contingency. The loading limit for a transmission line shall be its thermal loading limit.

The loading limit for an inter-connecting transformer (ICT) shall be its name plate rating.

Under N-1-1 conditions some equipment may be loaded upto their emergency limits. To bring

the system parameters back within their normal limits, load re-scheduling of generation may

have to be applied either manually or through automatic system protection schemes (SPS).Such measures shall be applied within one and a half hour (1 ) after the disturbance. The

emergency thermal ratings represent equipment limits that can be tolerated for a relatively

short time which may be one hour or two hour. The maximum permissible thermal line loading

of different types of line configurations, employing various types of conductors are enclosed as

Annex-VI.

Each system operator at SLDC / substations would endeavour to keep the line/ ICT loadings

within operating limits and inform NRLDC 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 line with regulation 6.4.12 of IEGC, NRLDC may direct the SLDC/ISGS/other regionalentities to increase/decrease their drawal/generation in case of contingencies e.g. overloading

of lines/transformers, abnormal voltages, threat to system security. Such directions shall

immediately be acted upon.

NRLDC shall endeavour to exchange power with the neighbouring regions on opportunity

basis in addition to the interregional bilateral agreements already in vogue. The prime

consideration for such exchange would be improvement in the grid parameters as well as

system reliability and economy.

6.3 ASSESSMENT OF TRANSFER CAPABILITY

Assessment of Total Transfer Capability (TTC), Transmission Reliability Margin (TRM) andAvailable Transfer Capability (ATC) for import and export of power within Northern region as

required for reliable system operation and for facilitating non-discriminatory open access in

transmission shall be carried out by NRLDC in coordination with National Load Despatch

Centre and other RLDCs. The Detailed Procedure for Relieving Congestion in Real Time

Operation as approved by the CERC vide order dated 22.04.2013 may be referred for further

details. The assessed TTC, TRM and ATC shall be posted on NRLDC/NLDC website in the

formats as enclosed in Annex-VII.


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6.4 MAJOR CORRIDORS/FLOW GATES IN NORTHERN REGION

List of lines in the major corridors/flow gates in Northern region have been enclosed as Annex-

VIII-a. The advisory issued by National Load Desptach Centre for secure operation of the grid

consequent to commissioning of the high capacity 765 kV corridor in the NEW grid is also

enclosed as Annex-VIII-b.

6.5 MONITORING OF CONGESTION

Real time data for monitoring Congestion shall be displayed on the NRLDC website in the

formats as enclosed in Annex-IX.

6.6 GENERATION RESCHEDULING

NRLDC may revise the interchange schedule as allowed by IEGC regulation 6.4.12, 6.5.5, and

6.5.16. Further details may be seen in the chapter on scheduling.

6.7 CURTAILMENT OF SCHEDULED TRANSACTIONS

The transactions already scheduled may be curtailed by NRLDC in the event of transmissionconstraints; congestion in the grid, or in the interest of grid security. In line with regulations

6.4.12, 6.5.28, 6.5.30 and 6.5.31 of IEGC the transactions shall generally be curtailed in the

following sequence

a. Unscheduled Interchanges

b. Short term bilateral transactions

c. Short term collective transactions

d. Medium term transactions

e. Long-term transactions

Amongst the customers of a particular category, curtailment shall be carried out on pro rata

basis. NRLDC would curtail a transaction at the periphery of the Regional entities. SLDC (s)

shall further incorporate the inter-se curtailment of intra State entities to implement the

curtailment.

6.8 PROCEDURE FOR RELIEVING CONGESTION

Congestion Management shall be as per the detailed procedure for relieving congestion in real

time operationas approved by CERC vide its order dated 22.04.2013. It is important to note

that the congestion charge could be applied both upstream and downstream of the congested

corridor irrespective of the frequency. Whenever actual flow on inter/ intra regional link/

corridor exceeds Available Transfer Capability and security criteria are violated for

continuously two time blocks, the National Load Despatch Centre may issue a warning notice.

In case SLDC observes congestion within the Intra State grid it shall take appropriate action

and 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 various formats may be referred in the

detailed procedure for relieving congestion in real time operation under regulation 4 (2) of the

Central Electricity Regulatory Commission (Measures to relieve congestion in real time

operation) Regulations, 2009. These formats are also enclosed as Annex-X.

*****


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CHAPTER 7

7.0 DEMAND MANAGEMENT

7.1 OVERVIEW

Demand management plays a very important role in system operation. Long-term demand

estimation (five years and beyond) is an important input for generation planning. In the

medium term, say one year, it constitutes an important input for outage planning of generating

units and transmission lines. In the short term, say within one week, it is an important input for

generation scheduling. Variation in demand in real time operation from the estimated values

could either be absorbed by the grid or affect it adversely. Even if the estimates are accurate,

the generation could vary from scheduled values adversely affecting the grid. Demand control

then plays an important role in arresting these adverse effects on the grid.

Demand estimation and control is essentially the responsibility of SLDCs. NRLDC would give

instructions to SLDCs on demand control whenever the same has a bearing on the security of

the regional grid & such instructions would have to be complied forthwith by all SLDCs.

7.2 DEMAND ESTIMATION

(i) The SLDCs would forecast active and reactive demand (MW peak, MW off-peak & energy

in MWh/MVArh) on an annual, quarterly, monthly, weekly and ultimately on daily basis,

which would be used in the day-ahead scheduling. The formats for reporting demand

forecasts are enclosed as Annex-XI. Each SLDC is expected to maintain a historical

database for the purpose and be equipped with the state-of-the-art tools such as Energy

Management System (EMS) for demand forecasting. Ideally, the forecasts should be on

hourly basis (8760, 720 & 168 values respectively in the annual, monthly and weekly

forecasts) rather than mentioning only the peak MW and energy requirements for the

period. It is also desirable to have substation wise demand (Nodal MW / MVAr) forecasts.

(ii) In line with the IEGC regulation 5.3 (c), the SLDC shall plan demand managementmeasures like load shedding, power cuts etc. based on the demand estimate and the

estimated availability from different sources and shall ensure that the same is implemented

by the SEB/distribution licensees.

(iii)The annual, quarterly and monthly demand forecasts would be used in the outage plan

prepared by NRPC Secretariat in consultation with all the constituents. In line with IEGC

regulation 5.3 (f) and 5.3 (h), the demand forecasts by the SLDC shall be provided to

NRLDC and NRPC for operational planning and computation of total transfer capability.

(iv)Attention would also be paid by SLDCs in demand forecasting for special days such as

important festivals and National Holidays having different crests and troughs in the daily

load-curve as compared to normal days.

(v) It is also important that, the reactive power requirements are forecasted right from

substation level by each SLDC. The reactive power planning exercise and programme for

installation of reactive compensation equipments should take care of these requirements

also.


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7.3 DEMAND CONTROL

The need for demand control would arise on account of the following conditions:

Variations in demand from the estimated or forecasted values, which cannot be absorbed

by the grid.

Unforeseen generation / transmission outages resulting in reduced power availability.

Network congestion (voltage levels beyond normal operating limits, violation of TTC,

network element load beyond operating limit etc.)

Heavy reactive power demand causing low voltages.

Commercial reasons.

In the interest of system security due to any other contingency in Northern orneighbouring regions.

Demand management measures shall be taken by SLDCs/SEB/distribution licensee/User/bulk

consumer in line with the regulation 5.4 of IEGC. Further sub-regulation 6 of Regulation 6.4 of

Principal Regulations mandates that

6. The system of each regional entity shall be treated and operated as a notional control area.

The algebraic summation of scheduled drawal from ISGS and from contracts through long

term access, medium-term and shortterm open access arrangements shall provide the drawlschedule of each regional entity, and this shall be determined in advance on day-ahead basis.

The regional entities shall regulate their generation and/or consumers load so as to maintain

their actual drawal from the regional grid close to the above schedule. Deviation, if any, from

the drawl schedule, shall be within the limits specified by the Central Commission in UI

Regulations and it shall not cause system parameters to deteriorate beyond permissible limits

and shall not lead to unacceptable line loading...

Thus in line with regulation 7 (1) of CERC (Unscheduled Interchange charges and related

matters) (Amendment) Regulations, 2010 it shall be ensured by the beneficiary or buyer that

the UI by the respective control area during a time block shall not exceed 12% of its scheduled

drawal or 150 MW, whichever is lower, when frequency is below 49.8 Hz and 3% on a daily

aggregate basis for all the time blocks when the frequency is below 49.8 Hz.

In line with para 14.4 of the Statement of Objects and Reasons in the matter of the Central

Electricity Regulatory Commission (Unscheduled Interchange charges and related matters)

Regulations, 2009 dated 8th June 2009 the UI mechanism should not be construed as

arrangement to meet capacity/energy requirements of beneficiaries. Beneficiaries must contract

for adequate power. The utilities must ensure long term contract or short term contract

arrangements for meeting their energy requirement. The generators / sellers and the

beneficiaries/ the buyers should use avenues like bilateral trading or the trading platforms of

power exchanges by availing open access for meeting short term, medium term or long term

arrangements or agreements.

NRLDC may give instructions for demand disconnection under normal and/or contingent

conditions. Demand control would have to be exercised under these conditions by the

SLDCs/SEB/distribution licensee/User/bulk consumer, which could be done by either of the

following methods or a combination thereof:

Manual demand disconnection.

Shutting off or reconnecting bulk power consumers having a special tariff structure linked

to number of interruptions in the day.


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PC based system for rotational load shedding with facilities for central programming and

uploading of the disconnection schedule for the day from the SLDC / Sub-LDC to the

substations.

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/ rate of change of frequency relays(df/dt)

Loads to be shed under any System protection Scheme identified at NRPC level.

These loads shall be grouped in such a manner that there is no over lapping between different

groups of load. During the demand control by manual disconnection of loads by staggering in

different groups, the roster changeover from one group to another shall be carried out in a

gradual and scientific manner so as to avoid excursions in the system parameters. Each SLDC

would also identify feeders drawing heavy quantum of reactive power and disconnect the same

under low voltage conditions. The necessary metering arrangements for identifying such

feeders would be provided by the SLDCs.

7.4 PROTOCOL FOR HANDLING SUDDEN REDUCTION IN DEMAND

During the event of sudden load throw off in the system suitable measures to control High

frequency & High Voltage may be taken as elaborated in Section 4.5 and Section 5.10

respectively of this document. Depending on the quantum of demand reduction, it may be

segregated into A, B, C and D as under:

Category-A : Demand reduction = Upto 20 %

Category-B : Demand reduction = Between 20 to 30 %

Category-C : Demand reduction = Between 30 to 40 %

Category-D : Demand reduction = More than 40%

The protocol for handling exceptionally large reduction in demand is enclosed as Annex-XII

*****


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CHAPTER-8

8.0 SCHEDULING AND DESPATCH

8.1 OVERVIEW

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].

The approval for connectivity, long term Access, Medium term Open Access and Short term

Open Access (Bilateral as well as Collective) shall be in line with the appropriate Regulations

and procedures approved by CERC. This chapter illustrates the procedure for scheduling the

approved contracts and the treatment to be accorded for special situations.

8.2 JURISDICTION OF NRLDC

The jurisdiction of NRLDC for scheduling and energy settlement is governed by regulation6.4.2, 6.4.3, 6.4.4 of the IEGC. A list of registered users shall be available on the website of

NRLDC. The list of Entities whose scheduling shall be coordinated by the NRLDC is given as

Annex-XIII (A).

The generation scheduling for the stations under Bhakra Beas Management Board (BBMB)

would be co-ordinated and finalised by BBMB in accordance with the requirements of the

beneficiary states viz. Punjab, Haryana, Rajasthan and Himachal Pradesh and subject to the

irrigation and hydrology constraints. The schedules so finalised for each BBMB station would

be communicated to NRLDC.

NRLDC shall be the Nodal Agency for processing of applications for Short term Open Access

where the drawal point lies within the control area of one of the regional entities of NorthernRegion.

8.3 APPLICATION FOR REGISTRATION AS REGIONAL ENTITY

In compliance to regulation 24 of the Central Electricity Regulatory Commission (fees and

charges of Regional Load Despatch Centre and other related matters) Regulations, 2009 all

users located in the Northern region whose scheduling, metering and energy accounting is to be

coordinated by Northern Regional Load Despatch Centre (NRLDC) shall register themselves

with the NRLDC by filing application in the format prescribed as Annex-XIII (B) to these

Procedures. The application shall be submitted at least three months in prior to the proposed

interconnection date.

8.3.1 DATA TO BE SUBMITTED FOR REGISTRATION

The applicant shall furnish following details along with the application for registration

Grant of connectivity, Long term Access/Medium term Open Access by the CTU/STU

Connection Agreement signed by the applicant with CTU/STU


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Geographical map indicating the point of connection with ISTS/STS

Power Purchase Agreement signed by the applicant with the long term beneficiaries

Address, contact number, email ID of a Nodal officer

When NRLDC is convinced of its jurisdiction over the applicant (in light of various provisions

in IEGC) the applicant shall submit additional technical details as mandated by various

regulations. This may inter alia include the following details:

Proposed schedule for testing and commissioning Switching Diagram of the station at the time of commissioning

Equipment protection scheme envisaged

System recording instruments installed at the station

Data and communication facilities installed at the station

Interface Metering Arrangement along with the CT/PT ratios

% allocation (in case if regional entity generator)

In case of hydro generating stations following additional data shall be submitted

Category of hydro station

10 daily inflows

Expected generation in 90 % dependable year (Design Energy)

Curve /table for reservoir level vis-a-vis energy content

A check list in this regard is also enclosed in Annex-XIII (C)

It shall be the responsibility of the regional entity to comply with all the statutory obligations.

Entities registered with NRLDC shall coordinate with the CTU/STU, NRLDC/SLDC for

ensuring the availability of interface metering as well as data and speech communication with

NRLDC/SLDC control centre. The entity shall submit a testing and commissioning schedule

and cooperate with NRLDC in interconnection with the ISTS. The regional entity shall furnish

any other technical detail requested by NRLDC as and when requested for.

8.4 SCHEDULING OF LONG TERM AND MEDIUM TERM CONTRACTS

In line with Regulation 32 of CERC (Terms and Conditions of Tariff) Regulations 2009-14,

NRLDC shall consider the shares / allocations of each beneficiary in the total capacity of

Central sector generating stations as determined by the Central Government, for the purpose of

scheduling. The shares shall be applied in percentages of installed capacity and shall normally

remain constant during a month. Based on the decision of the Central Government the changes

in allocation shall be communicated by the Member-Secretary, Regional Power Committee in

advance, at least three days prior to beginning of a calendar month, except in case of an

emergency calling for an urgent change in allocations out of unallocated capacity. The total

capacity share of a beneficiary would be sum of its capacity share plus allocation out of the

unallocated portion. In the absence of any specific allocation of unallocated power by the

Central Government, the unallocated power shall be added to the allocated shares in the sameproportion as the allocated shares.

The Regional Entities in Northern region shall keep NRLDC informed about the details of their

long term contracts for the purpose of scheduling. The algebraic summation of scheduled

drawal from ISGS and from contracts through a long term, medium term and short term open

access arrangements shall provide the drawal schedule of each regional entity, and this shall be

determined in advance on day-ahead basis.


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8.5 SCHEDULING OF HYDRO STATION:

Scheduling of Hydro station shall be done as per various provisions in IEGC 6.5 and CERC

Tariff regulation. The compensation in the day ahead schedule for the fourth day (Day + 3)

shall be carried out as per IEGC 6.5.13. In case of spillage due to transmission constraints/

Unit tripping the expected energy of that day will be reduced by the quantum of energy lost

due to spillage,

Say,

S4 = E4 + (A1-E1)

E1 will be taken as revised expected energy as explained above

8.6 SCHEDULING OF SHORT TERM CONTRACTS

Processing of applications for Short term Open Access in inter State shall be carried out in line

with the procedures prepared by CTU and approved by CERC in 28th

May 2009. The CERC

Regulations and Procedures are available on the NRLDC website under Open Access link on

the home page. A web based utility has been developed for processing of applications. Only

approved short term open Access applications shall be considered for scheduling.

8.7 TIME LINE FOR INFORMATION EXCHANGE FOR SCHEDULING

The procedure for day-ahead scheduling has been elaborated under regulation 6.5 of the IEGC.

The time line for exchange of information between NRLDC, NLDC, SLDC and various

Regional Entities for the purpose of scheduling is summarised in the table below:

Table 2: Time line for information exchange

S No. Information particulars From To To be sent by

(time in hrs)

1 Station-wise ex-power plant MW

and MWh capabilities foreseen

for the next day i.e 0000 hrs to2400 hrs for 96 blocks of 15

minutes duration each.

ISGS

(Regional

EntityGenerator)

NRLDC 0800

2 MW and MWh entitlements

available to each state during the

following day at 15 minutes

interval

NRLDC SLDC 1000

3 Requisition in each of the ISGS

in which they have long term and

medium bilateral interchanges,

approved short term bilateral

interchanges

SLDC NRLDC 1500

4 Generation schedule finalised for its stations in consultation with its

partner states

BBMB/DELHI

SLDC(For

Bawana

CCGT)

NRLDC 1500

5 Scheduling Request of Collective

Transactions

NLDC NRLDC 1600


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S No. Information particulars From To To be sent by

(time in hrs)

6 Interchange schedule to each of

the regional entity, in MW after

deducting the apportioned

estimated transmission losses

NRLDC Regional

Entity

1800

7 Modifications/ changes to be

made if any in the above schedule

SLDC/ISGS/

Regional

Entity

NRLDC 2200

8 Final generation / drawal

schedule

NRLDC SLDC/

ISGS

2300

8.8 TRANSMISSION LOSSES

The application of transmission losses on the various transactions shall be in line with

approved procedure for Sharing of Inter-State Transmission System losses dated June 2011 in

compliance of CERC (Sharing of Inter-state Transmission Charges & Losses) regulation, 2010.

8.9 PEAKING

The run-of-the-river power station with pondage and storage type power stations shall bescheduled to operate during peak hours to meet system peak demand. The total peak hours

duration for the purpose of peaking shall be taken as 3 hours. The time period for morning and

evening peak may be considered as per the system peak demand. The maximum capacity of the

station declared for the station shall be considered as equal to the installed capacity including

overload capability, if any, minus auxiliary consumption, corrected for the reservoir level

[IEGC 6.5.12].

The Declared Capability of the ISGS (except in case of run-of-the-river with up to three hours

of pondage) during peak hours should not be less than that during other hours [IEGC 6.4.17].

8.10 RAMP RATE

ISGS /Regional Entity generators in Northern Region shall be expected to capable of ramping

rate of up to 200 MW/hour. Hydro electric generating stations may be expected to provide a

higher ramp rate [IEGC 6.5.14].

During fuel shortage scenario ISGS shall also declare the possible ramping up/ramping down

[IEGC 6.4.16].

8.11 CURTAILMENT

In the event of contingencies, transmission constraints, congestion in the network, threat to

system security the transactions already scheduled by NRLDC may be curtailed for ensuring

safety and reliability of the system. This is further discussed in Chapter on CongestionManagement and alleviation.

8.12 REVISION OF SCHEDULES REQUESTED BY REGIONAL ENTITIES

Revision in the day-ahead schedule would be allowed as per the various provisions in the Grid

Code. The time from which the revised scheduled would be effective have been summarised in

the table below.


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Table 3: Revision of Schedule by regional entity

S No. Particulars of request for

revision in schedule

Time block

from which

the revised

schedule

would be

effective

from

Remarks

1 Revision in Declared Capability

by an ISGS having two part tariff

with capacity charge and energy

charge (except hydro stations)

Sixth Time block in which the

request for revision was

received by NRLDC would be

considered as first


by an ISGS in case of tripping

Fourth Time block in which the



considered as first


by run-of-the river hydro andpondage based hydro generating

stations

Sixth If there is large variation of

expected energy (MWh),revision may be allowed at 6

hourly interval effective from

0000 hrs, 0600 hrs, 1200 hrs,

1800 hrs [IEGC 6.5.18]

4 Revision of Declared Capability

by renewable generators

Sixth Time block in which the notice

was given shall be considered

as first. There may be one

revision for each time slot of 3

hours starting from 00:00 hrs

of particular day subject to

maximum 8 revisions during

the day5 Revision of Short term Open

Access (Bilateral) injection

schedule by Seller under forced

outage of generator of capacity

100 MW and above.

Fourth Time block in which the forced

outage is declared shall be

considered as first.

6 Revision in Requisition by a

Regional Entity in ISGS having

two part tariff

Sixth Time block in which the



considered as first

Note:

a) In the cases (1), (2), (3), (4) and (5) above, there need not be any fresh requisition from

the beneficiaries and NRLDC would assume that the MW requirement of the SEB

from the grid would be the same as given in the day-ahead schedule. The station wise

requisition from each ISGS would be re-worked by NRLDC in line with the procedure

described in 6.5.3 above.

b) To discourage frivolous revisions, NRLDC may, at its sole discretion, refuse to accept

schedule/capability changes of less than two (2) percent of the previous

schedule/capability.


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c) The schedule of the thermal generating stations indicating fuel shortage which

intimating the Declared Capability to NRLDC (except gas based ISGS) shall not be

revised except in case of forced outage of generating unit.

8.13 REVISION IN SCHEDULE INITIATED BY NRLDC

NRLDC may initiate revision in schedule under various provisions of IEGC.

Table 4: Revision in Schedule by NRLDC

Note: Generation and drawal schedules issued/revised by the NRLDC shall become effective

from designated time irrespective of communication success. [IEGC 6.5.24]

8.14 MODERATION OF SCHEDULE BY NRLDC

The IEGC allows RLDC to moderate the interchange schedule of the Regional Entities under

certain conditions. These are summarised below:

S No. Particulars of revision in

schedule by NRLDC

Revised

Schedule would

be effective from

Remarks

1 Bottleneck in evacuation of

power of ISGS due to

constraint, outage, failure or

limitation in the

transmission system,

associated switchyard and

substations owned by the

CTU or any other inter-state

transmission licensee

Fourth Time block in which the

bottleneck in evacuation of

power has taken place to be the

first one. The schedule in the

first, second and third block

shall be deemed to be equal to

actual generation.

2 Transmission constraint Fourth Time block in which the revised

schedule was issued by NRLDC

3 In the interest of better

system operation

Fourth Time block in which the revised

schedule was issued by NRLDC

4 Grid Disturbance Scheduled generation of all the

ISGS and Scheduled drawal of

all beneficiaries shall be deemed

to have been revised to be equal

to their actual generation/drawal

for all time blocks affected by

grid disturbance


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Table 5: Moderation of Schedule by NRLDC

8.15 STANDING INSTRUCTIONS BY SLDC TO NRLDC

Regulation 6.5.6 of the IEGC allows SLDC to give standing instruction to NRLDC such that

NRLDC itself may decide the best drawal schedule. However in the spirit of de-centralised

scheduling market mechanism, it is expected that such SLDC should convey to NRLDC atleast the following information on 15-minute time block basis:

Total MW required from the grid at its periphery

MW schedule for bilateral exchanges

Based on the above information, NRLDC would work out the requisitions from each ISGS

considering the merit order of energy charges in respect of ISGS stations after translating the

above MW values to ex-power plant (considering an estimated level of transmission losses).

This is without prejudice to the procedure given for short term open access transactions.

8.16 RESERVOIR FILING/DEPLETION FOR STORAGE TYPE HYDRO POWER

STATIONS

The strategy for reservoir filling and depletion in respect of ISGS hydro would be reviewed in

the monthly OCC meetings of NRPC, when the outage plan is reviewed. Based on the strategy

evolved, the ISGS hydro stations would declare their MWh capability accordingly in the daily

scheduling.

As far as possible the request for silt flushing may be sent to NRLDC at least a week in

advance so that its scheduling may be coordinated. In any case, an operation code shall be

obtained prior to the commencement of silt flushing operation. The protocol for coordinated

generation reduction and silt flushing at Karcham Wangtoo HPS and Nathpa Jhakri HPS is

enclosed as Annex-XIV (A). Likewise the protocol for Chamera-I and Chamera-II & Malana-

1&II is enclosed as Annex- XIV (B) & XIV (C) respectively.

8.17 IMPLEMENTED SCHEDULE ISSUED BY NRLDC

On completion of the operating day i.e. after 2400 hrs, the final schedule as implemented shall

be issued by NRLDC after incorporating all before the fact changes during the day of

operation. Various steps involved in the scheduling and the final schedule issued by NRLDC

shall be open to all the constituents for any checking/verification for a period of 5 days. In

S No. Particulars of moderation

carried out by NRLDC

Rational for moderation/ condition under

which moderation to be carried out

1 Generation schedule of run-of-

river hydro power station with

pondage and storage type hydro

power stations

For optimized utilization of available hydro

energy to meet system peak demand

2 Interchange schedule of Regional

Entities

Transmission constraints foreseen while

finalising the interchange schedule or in the

event of bottleneck in evacuation of power

necessitating reduction in generation

3 Requisition from different states For making schedule operationally

reasonable particularly in terms of ramping

up / ramping down rates and ratio between

minimum and maximum generation levels


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case any mistake/omission is detected, NRLDC shall forthwith make a complete check and

rectify the same [IEGC 6.5.33].

8.18 MEDIA FOR EXCHANGE OF INFORMATION

Considering the large volume of information needed to be exchanged in a time bound manner,

the transfer of information between NRLDC and other constituents i.e. states and ISGS a web

based scheduling program has been developed at NRLDC for Day Ahead and Current Day

Scheduling. This program enables data entry at ISGS and constituent locations through web

based user interface. The program also enables the users to view and download the injection

and drawal schedules and other customised reports such as un-requisitioned surplus in ISGS,

comparison of revised interchange schedule in comparison to the original interchange

schedule.

The web based scheduling program may be accessed from the NRLDC website. Separate

LOGIN / PASSWORD have been provided to the concerned utilities. Login name as allotted

by NRLDC will remain same. However password may be changed by concerned utility. Any

suggestion / feedback on the new software for further improvement may please be sent through

e-mail ([email protected]).

The Regional entities shall upload the information to NRLDC site in regard to scheduling atthe designated time and download the interchange schedules from NRLDC site at the

designated times.

The conventional voice / fax arrangement would act as back-up in case of failure of PC -to- PC

communication link through INTERNET.

In case NRLDC wants to revise the schedule due to transmission constraints or otherwise, then

the required intimation will be flashed by NRLDC to the constituents telephonically/fax/coded

message and accordingly the constituents can download the revised schedule from NRLDC

website.

*****


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CHAPTER -9

9.0 SETTLEMENT SYSTEM

9.1 OVERVIEW

The settlement system involves metering, data collection and processing, energy accounting

and raising of bills by the different constituents. This chapter indicates the roles and

responsibilities of the different constituents in making the settlement system operative.

9.2 SETTLEMENT PERIOD

For the purpose of scheduling a

operating procedures of nr_2013-14.pdf

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