Automatic Generation Control (AGC)

First Pilot Project at NTPC Dadri

03-August 2017

Outline

• Commission’s orders on spinning reserves

• Frequency profile of different systems and India

• Primary Control

• Secondary control through Automatic Generation Control (AGC)– Details of pilot project by POSOCO and NTPC

– Further steps

• Commercial mechanism for plants under AGC

• Further directions required from Hon’ble Commission

2

Commission’s orders

• Central Electricity Regulatory Commission (Ancillary Services Operations) Regulations, 2015

– 13th August 2015

– http://cercind.gov.in/2015/regulation/Noti13.pdf

– Implemented from: 12th April 2016

• Report of the Committee on Spinning Reserves

– 17th September 2015

– http://www.cercind.gov.in/2015/orders/Annexure-%20SpinningReseves.pdf

• Roadmap to operationalise Reserves in the country

– 13th October 2015

– http://cercind.gov.in/2015/orders/SO_11.pdf3

Roadmap to operationalise Reserves in the country- Salient points

• Philosophy recommended to be adopted

– Operation at constant frequency target of 50.0 Hz

– with constant area interchange

• For AGC, power plants and Load Dispatch Centres (LDCs)

– necessary software and communication infrastructure

– Automated control signals from LDC to the generator

• AGC to be operationalized wef 1st April 2017

POSOCO awarded a pilot AGC project on 18th Jan 2017

4

Primary and Secondary Reserves

• Secondary Reserves (centralized approach)

– North : 800 MW

– East : 660 MW

– West : 800 MW

– South : 1000 MW

– North East : 363 MW

– Total : 3623 MW

• Primary Reserves (distributed )

– 4000 MW considering Ultra Mega Power Plant out

5

Tertiary Reserves (decentralized)

• All India level : 5218 MW

– NR : 1658 MW

– WR : 1353 MW

– SR : 1343 MW

– ER : 857 MW

– NER : 65 MW

• Reserves to be maintained at intra state level

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Year: 2016Source: Derived from http://fnetpublic.utk.edu/ 7

Frequency profile of Continental Europe

Narrow range of 49.96-50.04 Hz!!

Deterministic frequency deviations – root causes and proposals for potential solutions --------------------------------------------------------------------------------------------------A joint EURELECTRIC – ENTSO-E response paper

8

Typical frequency profile for Eastern Interconnection, US

For 11th April 2012

Based on 2 second frequency data available from PJM website

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Sample Daily Frequency Profile of India

Generally remains within 49.90-50.05 Hz for 70-75% of the time

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Frequency Profile

Frequency Profile

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Frequency Variation Index (FVI) over the years

13

Frequency Profile

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Frequency Profile

Maximum Frequency

15

Frequency Profile

Average Frequency ~ 50 Hz.

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Minimum Frequency

Frequency Profile

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Frequency Profile

FVI consistently hovering around 0.03 to 0.05

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Frequency as per global standards in India• Load and RE forecasting

– Decentralized at State level

• Unit commitment and Scheduling – Decentralized – Move from 15-minutes to 5-minute scheduling (SAMAST)

• Load following resources– Decentralized

• Fast/slow tertiary response– Centralized through Ancillary Services at ISTS level

• Secondary response– Automatic Generation Control (AGC) at regional level

• Primary control– Decentralized

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49.83

49.88

49.93

49.98

50.03

50.08

1 501 1001 1501 2001 2501 3001 3501 4001

Jan-15 Feb-17

Early frequency recovery in Feb 2017 PMU plot due to improved Primary Response in comparison to Jan 2015 for a similar event(1000 MW Generating Unit Tripping )

49.88 Hz

49.85 Hz

Hz

50.07 Hz

49.91 Hz

Kudankulam 1000 MW tripping event

• Frequency Response Characteristics (FRC) has increased from6000 MW/Hz in early 2015 to over 9000 MW/Hz in Mar 2017

• Quarterly reports submitted to CERC for 39 events since Jan 2015

Commission’s orders have facilitated primary response order dated 13th Feb 2017 in petition 65/MP/2014

Target FRC of 15000 MW/Hz suggested along with testing

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CERC Terms and Conditions of Tariff Regulations, 2014

“ the rate of return of a new project shall be reduced by 1% for such period asmay be decided by the Commission, if the generating station or transmissionsystem is found to be declared under commercial operation withoutcommissioning of any of the Restricted Governor Mode Operation (RGMO)/Free Governor Mode Operation (FGMO), data telemetry, communicationsystem up to load dispatch centre or protection system:

as and when any of the above requirements are found lacking in a generating station based on the report submitted by the respective RLDC, RoE shall be reduced by 1% for the period for which the deficiency continues “

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Secondary control through

Automatic Generation Control (AGC)

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Automatic Generation Control fundamentals

• AGC regulates the power output of electric generators within a prescribed control area in response to change in system frequency, tie line loading, or the relation of these to each other.

• The AGC program provides closed-loop control that assigns the automatically controlled generation in such a way that the control area load is satisfied while the desired frequency and interchange schedules are maintained.

• The AGC program recognizes both economic and regulation limits and protects against rate- of- change Violations

AGC input Data

• Scheduled interchange

• Tie line telemetry (MW)

• Actual unit generation (MW)

• Frequency (Actual & Desired)

• Economic Dispatch program (ED) data

AGC control Modes

The following AGC control modes are provided

to allow AGC to be operated under various

system operational conditions – Tie Line Bias Control (TLBC)

– Constant Frequency Control (CFC)

– Constant Net Inter-change Control (CNI)

– Tie Line Bias Control Plus Time error correction.

– The control mode is selected by the dispatcher via buttons located

on the operator panel of each console.

Automatic Generation Control Interfaces

• ACE Calculation• Unit Control Mode• Unit Basepoint• Unit Ramp Schedules

Automatic GenerationControl

Interchange Scheduling

• Net Scheduled Interchange

EconomicDispatch

• Unit Economic Basepoints• Unit Economic Participation Factors

• Unit Connection Status• Unit Control Status• Unit Output• Unit Limits

• Unit Ramp Rates

• System frequency• System Time Error

• Tie Line Flows

•Setpoint/ PulseControl Commands

External Interface

• External ACE• External Unit Data

State Estimator

•Island Data•Estimated Unit & Line MW

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Secondary Control through AGC

• Pilot at NTPC Dadri Stg-II (2 x 490 MW)– Dadri Stage II power plant is located near Delhi.

– Easy to visit and monitor the field level implementation process.

– High variable cost of the order of 325 paise/kWh

– Economical to keep Spinning Reserves as little opportunity cost

• Subsequent pilots could be explored in each region– Simhadri-II in Southern Region

– NP Kunta Solar

– Wind project

• Detailed procedure would be submitted by POSOCO

28

Project progress• A team from POSOCO, POWERGRID and M/s Siemens

– visited NTPC Dadri on 6th May 2016– to explore the ground level requirements with NTPC

• Execution of AGC pilot project as per technicalspecifications through limited tender– Invited bids on 21st October 2016 from the four SCADA vendors

• M/s ALSTOM• M/s OSI• M/s Siemens• M/s ABB

• Bids opened on 30th Nov 2016• Letter of Award (LOA) issued to M/s Siemens on 18th Jan’17

and accepted by Siemens on 25th Jan ’17• CERC Petition filed by POSOCO for payment mechanism on

3rd April 2017– Hearing by CERC scheduled on 18th July 2017 29

Technical Specifications

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Area Control Error (ACE) formula

• ACE = A * (Ia - Is) + 10 * Bf * (50 - Fa)A = 0 or 1; 0 -> for adopting ‘only Frequency control

mode’ and 1 -> for adopting ‘Tie Line Bias mode’ (user entry)

Ia= Actual net interchange (negative value for import)

Is= Scheduled net interchange (negative value for import)

Bf = Frequency Bias Coefficient in MW/0.1 Hz (positive value, user entry)

Fa = Actual System Frequency

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ACE and AGC set point • Spikes in ACE data are present for different

reasons. – By design, AGC cannot handle large changes in ACE – Pilot AGC shall clamp ACE exceeding +/- 800 MW to +/-

800 MW

• Method for Scaling of ACE– Scale using a factor of 15 (800/15 = approx 50 MW, the

maximum Spinning Reserve.

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Draft Rules for the CLU Algorithm at NTPC

• Receive Unit Status, Present Schedule and DeltaP signal andnumber of mills.

• If Present Schedule is close to 230, 330 or 430 MW, startanother extra mill to create Spinning Reserve.

• Delta P signal be clamped to +/- 50 MW if the value isoutside +/- 50 MW.

• The biasing between units should be user enterable. Startwith 0.5, for equal contribution.

• Difference between two consecutive ICCP refresh values ofDelta P shall be clamped to a limit of 1 MW to start with.(i.e., Max(Delta Delta P) = 1 MW)

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Proposal for commercial settlement for AGC services offered by NTPC Dadri Stage-II

1. Factoring AGC signals while evaluating Deviations.

2. Compensate for the Extra Energy spent/saved

3. Incentivize for the ‘secondary regulation’ services

• CERC Order needed to facilitate all of the above

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1. Factoring AGC signals while evaluating deviations

• Energy produced due to AGC signals should not beconsidered as deviation from the schedule

• Aggregated AGC incremental MW signals over 15minutes / 5 minutes would be logged in MWh at NLDC.

• AGC MWh logs forwarded to NRPC secretariat on weeklybasis.

• Deviation in MWh for every time block would be workedout as

– MWh deviation = (Actual MWh)-(Scheduled MWh)- (AGC MWh)which would be settled as per the existing DSM Regulations

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2. Compensate for the Extra Energy spent/saved

• The AGC energy account will be available every week

• For AGC MWh generated during a block,

– payment @ variable charges to Dadri from the NR DSM pool

• For AGC MWh reduced during a time block

– Dadri pays @variable charges to the NR DSM pool

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3. Incentivize for the ‘secondary regulation’ services

• For AGC MWh in each time block (+ve or –ve)

– 50 paise/kWh mark up payable to NTPC Dadri from NR DSM pool

• Mark up of 50 paise/kWh similar to Ancillary Services (AS) framework of CERC.

• Periodic checks regarding compliance of plant to AGC signals

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Inputs needed for Accounting(Main and Standby)

• MW Delta P signals every 10 seconds at NTPC Dadri(Main)

Delta P = PAGCsetpoint – Pschedule

Integrated into MWh values for 15 minutes and 5 minutes

• MW Delta P signals sent every 10s from NLDC

(Standby)

– Integrated into MWh values for 15 minutes and 5 minutes

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Regulation accuracy of the solar plant demonstration exceeded accuracy of conventional resources

Page 39

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

SteamTurbine

PumpTurbine

Hydro CombinedCycle

LimitedEnergyStorage

GasTurbine

Solar PV(Middle ofthe Day)

Solar PV(Sunset)

Solar PV(Sunrise)

Regulation Up Accuracy

Blue bars taken from the ISO’s informational submittal to FERC on the performance of resources providing regulation services between January 1, 2015 and March 31, 2016

Source: CAISO

CERC approval is needed on the following• Go ahead for the pilot project for NTPC Dadri Stage-II (2 x 490 MW) to

receive AGC signals from NLDC and regulate to the extent of 50 MWup/down to start with and with provision to go up later.

• Deviation Settlement Mechanism (DSM) for Dadri Stage-II under AGC– Factoring AGC signals while working out deviations from the schedule

• Incentivize NTPC Dadri stg-II for the AGC services– 50 paise/kWh mark up similar to Ancillary Services framework

• Facilitate NRLDC to earmark 50 MW up/down reserves at NTPC DadriStage-II on days when full generation is requisitioned or schedule is attechnical minimum

• Take up other pilot projects including wind and solar

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Automatic Generation Control (AGC)Pilot Project

Implementation Philosophy

EASTERN

REGION

SOUTHERN

REGION

WESTERN

REGION

Eastern

REGION

NORTHERN

REGION

NORTH-

EASTERN

REGION

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Region considered as an Area for secondary control

Ia = Actual net interchange, negative for NR meaning import by NR

Is= Scheduled net interchange, negative for NR meaning import by NR

Bf = Frequency Bias Coefficient in MW/0.1 Hz, positive value

Fa = Actual System Frequency

ACE positive means NR is surplus and NR internal generation has to back down

ACE negative means NR is deficit and NR internal generation has to increase

• Tie line bias mode and Frequency bias only mode both possible

ACE = (Ia - Is) + 10 * Bf * (Fa - 50)

Scaling the ACE value• NTPC Dadri stg-II alone cannot compensate the whole

Northern Region ACE

• Interchange scaled using a factor of 15, changeable

– Nearly 15 stations available for AGC in NR

• 50 MW will be the maximum Spinning Reserve utilization

• Beyond 50 MW NR Scaled ACE

– Entire 50 MW spinning Reserve will be utilized from NTPC Dadri stg-II

• Utilization restricted to 50 MW

– Regulation limits in the Spectrum 7 software

Technical Specifications

New

Back-up

NLDC

SCADANR-IR Schedule

NR-IR Actual

Frequency

AGC System at

NLDCAGC RTU

at NTPCICCP

AGC On/OFF

AGC Set point

Scaled ACE

IEC 104 Protocol

AGC Local/Remote

Unit Load Set Point

Actual Generation

Circuit Breaker Status

AGC Set point

NTPC DCS

DeltaPAGC Local/Remote

Unit Load Set Point

Actual Generation

Circuit Breaker Status

AGC console at

NTPC

Factor

Data Flow in AGC Project

Control block diagram at NLDC

ACE

Unit Load Set Point schedule total from unit

5 &6

PI controller and Limiters

Plant Set Point

• Integration time constant = 80s• Small signal Proportional time constant = 0.5s • Large signal Proportional time constant = 0.5s • Regulation Limits = +/- 50 MW• Plant limit = 980 MW• Ramp rate = 10 MW/min for Plant

Communication block diagram

SCADA

Database in the

IMM

ICCP of NLDC

SCADA &

IFS before sending

towards NTPC RTU

AGC Database

in the IMM

Setpoint

IMM : Information Model ManagementIFS: Independent Front End ServerICCP : Inter Control Centre ProtocolRTU: Remote Terminal Unit

Sample dashboard

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Max Load Set

point

Min Load Set

point

Unit Capability

Boiler ControlTurbine Control

B1, B2

A1

A2

Unit DCS

Inputs from the two unit DCS:

ULSP of the generator for the

present time block and

breaker status

AGC set point from NLDC AGC

using ACE, ULSP, tuned

parameters, limits etc.

AGC RTU at Plant with

algorithm to produce

final unit wise set points

PC with provision to

enter AGC unit biasing

manually, if needed

PAGC Setpoint total (main)

PAGC Setpoint (Back up)

P Schedule (Back up)

P Schedule (main)

NLDC

NTPC

Unit 2Unit 1

NTPC side Block diagram

Rules fed in NTPC RTU• AGC correction (Delta P) calculated in RTU as

Delta P = Set point sent by NLDC – ULSP of plant

• Check Delta P limits– If Delta P > 50 MW, Delta P = 50 MW– If Delta P < -50 MW, Delta P = -50 MW

• If one link goes down, switch to another

• Multiply the Delta P by the factor entered by NTPC operator– Divide the Delta P amongst the two units

• Send the AGC correction (Delta P) – To individual NTPC unit DCS– Hardwired

Output limit checks• 50 MW utilization of Spinning Reserve

• Plant Ramp rate (~ 10 MW/min) honoured while giving DeltaPsignals

• Difference between two successive values of Delta P

– Max(Delta (Delta P)) = 1MW

– After tuning of controllers

– Taken care of by the Ramp application at NLDC

• Unit Capabilities checked at Plant end

– Maximum MW limit

– Mill availability and Spinning Reserve in real time as declared on paper

• If (Unit Capability – 50 – ULSP) < 0, then start an extra mill, indication at NTPC.

NTPC DCS snapshot

Sample performance plots0000hrs of 10th June 2017 to 0000hrs of 12th June 2017

Load following performance• Plant ramp rate is comparable to the Scaled ACE ramp rate

during normal situations

– Average standard deviation of 5 minute NR ACE for September and October is around 150 MW.

– Average standard deviation of 10s NR ACE for September and October is around 10 MW.

• With more number of units under AGC load following will improve in future

Account data from NTPC and NLDC

• Exercise done for sanity checking of accounting data

• Data for 15 minutes average – Collected from both NLDC and NTPC Dadri stg-II

• Data was from 00 hrs of 10th June to 00 hrs of 12th June 2017

• Delta P data was plotted for comparison

• 10th -12th June’17 were predominantly ‘Regulation Down’ days

• Block wise AGC MWh computed

Comparison graph

Payment for Energy & Incentive• Variable cost of Dadri Stg-II available

• Block wise data

– For both Up and Down regulation

• Payment for energy

– For AGC MWh generated during a block • Payment @ variable charges plus markup 50ps to Dadri from

the NR DSM pool

– For AGC MWh reduced during a time block• Dadri pays @ variable charges to the NR DSM pool

• Incentive of 50ps earned by Dadri during down regulation

DSM after AGC

• Deviation in MWh for every time block

• MWh deviation = (Actual MWh) - (Scheduled MWh) - (AGC MWh)

• AGC MWh can be positive or negative

– Block wise data available

• Actual MWh and Scheduled MWh will be always positive

• Would be settled as per the existing DSM Regulations

AGC Pilot Project at NTPC Dadri Stg-II

Report of the Mock Test conducted on 29th June 2017

Pioneering Experience

List of Acronyms used and meaning

• ULSP : Unit Load Set Point of NTPC Dadri Stg-II (Gross Set Point including auxiliary power consumption)

• NR Scaled ACE: ACE of the Northern Region scaled by a value of ~30 (user entry), because entire Northern Region ACE will be too high for Dadri alone.

• Delta P : AGC correction wrt ULSP Schedule (eg. Delta P is 20 MW means Regulation Up signal of 20 MW is given above the ULSP schedule by AGC)

• Dadri Stg-II Plant: has 2 units (unit -5 &6, 2x490 MW)

• AGC Remote: NTPC DCS accepts AGC signal sent by NLDC

• AGC Local: NTPC DCS does not accept AGC signal sent by NLDC

Unit 6 taken into AGC Remote at 1741 hrs

Actual generation following the ULSP schedule before AGC correctionAGC in local mode

Unit 5 taken into AGC Remote at 1814 hrsTotal Plant under AGC

Dadri Stg-II total Plant actual generation following the AGC Set point

Mock Test finished at 1910 hrs

AGC ON/OFF tested for 4 minutes from 1847 to 1851 hrs

Variation of AGC correction (Delta P) wrt NR Scaled Area Control ErrorAGC Correction Restricted to +/- 50 MW (Maximum Spinning Reserve utilization from NTPC Dadri Stg-II)

ACE +ve = NR SurplusACE –ve = NR Deficit

AGC Correction +ve = Reg UpAGC Correction -ve = Reg Down

Unit 6 taken into AGC Remote at 1741 hrs

AGC in local mode Unit 5 taken into AGC Remote at 1814 hrsTotal Plant under AGC

Mock Test finished at 1910 hrs

AGC ON/OFF tested for 4 minutes from 1847 to 1851 hrs

General

• NTPC and POSOCO (NRLDC and NLDC) met at NTPC Dadri before the AGC Mock test

• Presentation made by POSOCO regarding implementation philosophy

• Concerns raised by NTPC regarding frequent change in load set point may be detrimental to the plant

– NTPC reported smooth operation during the test

Extra Reading

Effect of RGMO

• Presently Grid Frequency is frequently out of the dead band (+/- 0.03 Hz)

• RGMO signal is given directly to the Turbine Governor

• AGC signal passes through Coordinated Boiler and Turbine controls and reaches the Turbine Governor

• If Grid Frequency is out of dead band interaction between secondary (AGC) and primary (RGMO) is inevitable (sometimes on the positive side and some times on the negative side)

• If Grid Frequency stabilizes to 50 Hz within dead band, then interaction of RGMO and Secondary Control will be minimized.

Interaction with RGMO

Plant taken into AGC Remote at 1814 hrs

RGMO switched ON at 1900 hrs

Mock test completed at 1910 hrs

Ramp rate of the AGC Set Point

• Ramp rate limit was set at 10 MW/min• Change in Set point will be processed with this

rate by the AGC software• Set Point was sent every 2 seconds to the plant

– Ramp rate honoured while giving signals– Temporary instantaneous deviations in adhering to

the ramp rate by the control mechanism for 5% of the time• Smoothened out by NLDC AGC, NTPC Digital Control

System and the natural boiler/turbine response

• 2 minute average ramp rate of the set point is 100% below the limit given (10 MW/min)

AGC way forward

• Petition no. 79/RC/2017 was filed in this matter by POSOCO with Hon’ble Commission.

• Pettion was admitted on 18th july 2017

• A detailed implementation plan to operationalize the spinning reserves in the country was also submitted to CERC highlighting the issues involved

• CERC directed POSOCO to notify in WEB and to serve petition copies to concerned.

• Next hearing on 21st sept 2017

Thank you