· NERC Technical Document on Balancing and Frequency Control ... part of a generation management...

THIRD Meeting of the

National Reliability Council for Electricity

1.8.2014

AGENDA

• Inputs from sub-group of NRCE on methodology of calculation of TTC,

ATC and TRM and discussion thereon.

• Proposal of inclusion of private sector participants.

• Decision on Dynamic Line Rating (DLR).

• Decision on Reserves and Automatic Generation Control (AGC).

• Any other matter with the permission of the Chair.

Decisions taken in the Second meeting of the

NRCE

• a) Certification of TTC, ATC and TRM for June 2014 could not be done due to paucity of time and also due to lack of discussion on the methodology for determination of the same. It was decided that the sub-group along with any members of NRCE, if they so desire, would sit in NLDC and interact with them to find out the methodology of determination of TTC, ATC and TRM, sometime between 10th and 15th of June 2014.

• b) The decisions to include private generators as members of the NRCE would be taken when all or most of the NRCE members are present.

Proposal of inclusion of

private sector participants

MOM of the Central Advisory Committee

Meeting of the CERC held on 12.5.2014.

• “7.0 Consensus:

• After discussion, consensus was evolved on the following:

• 6 The issue of Available Transfer Capacity vis-à-vis Total Transfer Capacity needs urgent attention of the Regulators.

• 6 There is a need for enhanced transparency and information dissemination on TTC/ATC.

• 6 The concept of General Network Access (GNA) to be taken up immediately.

• 6 Transmission planning should also take RE capacity addition into consideration.

• 6 Day ahead/intra-day market should be further strengthened. Market design for Ancillary Services should be created at the earliest.

MOM of the Central Advisory Committee

Meeting of the CERC held on 12.5.2014.

• 6Gas based generating stations should be utilized for ancillary services.

• 6 ToD tariff for transmission should be examined. The economic cost of transmission should be captured in policy/regulation making in the context.

• 6 Interaction of CAC and FOR should be facilitated. SERCs should be impressed upon to insist on adequacy of power procurement by discoms so as to fulfill their mandate of universal service/supply obligation.

• 6 Reliability Council constituted in pursuance of CERC Order should co-opt representatives from private sector as well, as Members.

• 6 A small committee may be constituted from amongst the members of CAC to examine issues connected with transmission congestion.

• 6 CAC should meet more often.

Proposal of inclusion of private sector

participants• Letters received from private developers for inclusion in NRCE :

• Jindal Power

• GMR Energy

• Adani Power Ltd.

• It was thought that the Private Power Associations may nominate their representatives, who have knowledge in the field.

• IPPAI has nominated Shri Vikas Saxena, Vice President, Jindal Power. Experience of 34 years in the power sector. Was in NTPC and PGCIL. Expertise in Power system Design and Protection.

• APP has nominated Shri Satyajit Ganguly, Vice President, Sesa Sterlite Ltd. Worked in PGCIL and WRLDC.

Inputs from sub-group of NRCE

on methodology of calculation of

TTC, ATC and TRM

Discussions in the second meeting of the sub-

Group of the NRCE held on 10.6.2014

• How often should calculations of TTC, ATC and TRM be done.

• Presently it is done once or maximum twice, i.e. during peak and off-peak hours to arrive at the TTC, ATC and TRM for the month.

• If there is an outage of generator or line or other system element, then the same is calculated again.

• The power flow on inter-State transmission corridors keeps changing in the absence of Reserves and Automatic Generation Control.

• System Protection Schemes are put to increase the TTC, ATC and TRM.

Decisions taken in the second meeting of the

sub-Group of the NRCE held on 10.6.2014

• (i) Awareness should be brought to all states in the OCC meetings on the need for accurate data at all generation and demand nodes of the power system in the State.

• (ii) System protection schemes have been put in place as contingency measures. All the RPCs would take this up as an agenda item in the OCC meetings to ensure that the relays of these schemes are not bypassed.

• (iii) In order to check the actual power flows vis-a-vis the ATC, it was decided that the power flows in certain critical transmission corridors would be studied, like the S1 – S2 corridor and the corridor between Western and Northern Regions.

Decisions taken in the second meeting of the

sub-Group of the NRCE

• (iv) The matter of issuing guidelines for loadability of lines taking into

consideration the ambient temperature would be put up to the NRCE for decision.

• (v) The matter of having reserves and Automatic Generation Control (AGC) in each state to control the variation of flows on inter-state lines

would be put up to the NRCE for decision.

Power flows in S1 – S2 corridor

• Bangalore –Salem S/C 400 KV line

• Kolar –Hosur D/C 400 KV line

• Hosur-Salem S/C 400 kV line

• Kolar – Sriperumbudur (Chennai) S/C 400 KV line

• Nellore- Sriperumbudur (Chennai) S/C 400 KV line

• Chitoor- Sriperumbudur (Chennai) S/C 400 KV line

• Nellore-Almati S/C 400 KV line

Critical lines in the S1-S2 corridor

• The main constraint are in the first two lines, i.e

(i) Bangalore –Salem S/C 400 KV line and

(ii) Kolar –Hosur D/C 400 KV line

Total Power flow on S1-S2 corridor (15 minute

readings for May 2014)

Power flow on a single circuit of 400 kV D/C Kolar-Hosur line (15 minute readings for May 2014) (critical line in S1-S2)

Dynamic Line Rating

(DLR).

Dynamic line rating

(Reference: U.S. Department of Energy site)

• Dynamic line rating enable system operator to determine capacity and

apply line ratings in real time, based on actual operating conditions.

• In many power systems, static ratings are adjusted to account for

significant differences in maximum ambient temperature. Line ratings

may be adjusted daily, hourly, or even more frequently to reflect the

maximum ambient temperature predicted during a particular period of

time. The method of periodically adjusting a line’s rating based on

ambient air temperature is called ambient- adjusted rating.

Dynamic line rating

(Reference: U.S. Department of Energy site)

• For example, in New York, transmission lines receive a summer seasonal

line rating assuming an ambient temperature of 35 degrees Celsius. If the

maximum ambient temperature predicted for the next 24 hours is only 25

degrees Celsius, the ambient- adjusted rating can be increased by

approximately 10% for the next 24 hours.

Ambient adjusted rating

(along with other parameters )

Day and Night temperature at Hosur (Tamil

Nadu State)

Reserves and Automatic Generation

Control (AGC).

NERC Technical Document

NERC Technical Document on Balancing

and Frequency Control

• Primary Control

• Primary Control is more commonly known as Frequency Response. Frequency Response occurs within the first few seconds following a change in system frequency (disturbance) to stabilize the Interconnection. Frequency Response is provided by:

• 1. Governor Action. Governors on generators are similar to cruise control on your car. They sense a change in speed and adjust the energy input into the generators’prime mover.

• 2. Load shedding.



• Secondary Control

• Secondary Control typically includes the balancing services deployed in the

“minutes” time frame.

• Secondary Control also includes initial reserve deployment for disturbances.

• In short, Secondary Control maintains the minute-to-minute balance throughout the

day and is used to restore frequency to its scheduled value, usually 60 Hz, following

a disturbance. Secondary Control is provided by both Spinning and Non-Spinning

Reserves.



• The most common means of exercising secondary control is throughAutomatic Generation Control (AGC).

• SCADA gathers information about an electric system, in particular system frequency, generator outputs, and actual interchange between the system and adjacent systems.

• Using system frequency and net actual interchange, plus knowledge of net scheduled interchange, it is possible to determine the system’s energy balance with its interconnection in near-real-time.

• Most SCADA systems poll sequentially for electric system data, with a typical periodicity of four seconds.



• AGC computes a Balancing Area’s Area Control Error (ACE) from

interchange and frequency data.

• ACE tells whether a system is in balance or needs to make adjustments to

generation.

• AGC software, while observing ACE, automatically determines the

most economical output for generating resources while observing

energy balance and frequency control, usually by sending setpoints to

generators.

Deviation Settlement Accounts of SR for 14/7/14 to 20/7/14

AGC Software

AGC Software capabilities

• Automatic Generation Control (AGC) calculates the required parameters or changes to optimize the operation of generation units. The automatic generation control software uses real-time data such as frequency, actual generation, tie-line load flows, and plant units’controller status to provide generation changes. Automatic generation control system also calculates the parameters required for load frequency control and provides the required data on demand to maintain system

frequency and power interchanges with neighboring systems at scheduled

values.


• Minimize Area Control Error (ACE)

• Maintain frequency at the scheduled value

• Operate system with adequate security & economy

• Maintain net power interchanges

• Maintain economical power allocation

• Share MW and MVAR proportionally amongst various generation units

• Multiple pre-configured automatic generator control modes


• Automatic generation control software is fully integrated with Economic

Dispatch and Interchange Scheduling, automatically ensuring that generation adjustments are scheduled in the most economical fashion. As

part of a generation management system, automatic generation control software also provides guidelines for optimal electrical system

operation to meet power requirements, steam requirements, and

minimize fuel cost per generator. This process significantly minimizes the

complexities of the decision process.

Thank You

ANNEXURE-I

ATTENDANCE SHEET

3rd

MEETING OF NATIONAL RELIABILITY COUNCIL FOR ELECTRICITY ON 01.08.2014

1

S.NO Name & Designation

(Sh/Smt)

Organization Contact No. e-Mail ID

1. P.K. Pahwa, Member (GO&D) CEA 9818243524 [email protected]

2. Ajay Talegaonkar, S.E. (O) NRPC 9910728144 [email protected]

3. K.V.S. Baba GM, NLDC,

POSOCO

8527607575 [email protected]

4. Satyanarayan.S WRPC 922339938 [email protected]

5. P.S. Mhaske, MS NRPC 9968667741 [email protected]

6. O.K. Yempal, Director (operations) MSETCL 9920174232 [email protected]

7. S.G.Kelkar, ED (Operations) MSETCL 9819363329 [email protected]

[email protected]

8. S.R.Bhat, MS SRPC 9845451121 [email protected]

9. Anil, EE SRPC 9449006041 [email protected]

10. D.K.Bauri, EE ERPC 9883617236 [email protected]

[email protected]

ANNEXURE-I

ATTENDANCE SHEET

3rd

MEETING OF NATIONAL RELIABILITY COUNCIL FOR ELECTRICITY ON 01.08.2014

2

11. Pankaj Batra, CE (IC), RA CEA 9350981062 [email protected]

12. D.K. Meena, Deputy Director, RA CEA 9968031130 [email protected]

13. Pankaj Verma, AD, RAQ CEA 8010125457 [email protected]

· NERC Technical Document on Balancing and Frequency Control ... part of a generation management...

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