Automatic Generation Control (AGC) First Pilot Project at NTPC Dadri

Transcription

1 Automatic Generation Control (AGC) First Pilot Project at NTPC Dadri 03-August 2017

2 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

3 Commission s orders Central Electricity Regulatory Commission (Ancillary Services Operations) Regulations, th August Implemented from: 12 th April 2016 Report of the Committee on Spinning Reserves 17 th September %20SpinningReseves.pdf Roadmap to operationalise Reserves in the country 13 th October

4 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 1 st April 2017 POSOCO awarded a pilot AGC project on 18 th Jan

5 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

6 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 6

7 Year: 2016 Source: Derived from 7

8 Frequency profile of Continental Europe Narrow range of Hz!! Deterministic frequency deviations root causes and proposals for potential solutions A joint EURELECTRIC ENTSO-E response paper 8

9 Typical frequency profile for Eastern Interconnection, US For 11 th April 2012 Based on 2 second frequency data available from PJM website 9

10 Sample Daily Frequency Profile of India Generally remains within Hz for 70-75% of the time 10

11 Frequency Profile

12 Frequency Profile 12

13 Frequency Variation Index (FVI) over the years 13

14 Frequency Profile 14

15 Frequency Profile Maximum Frequency 15

16 Frequency Profile Average Frequency ~ 50 Hz. 16

17 Frequency Profile Minimum Frequency 17

18 Frequency Profile FVI consistently hovering around 0.03 to

19 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 19

20 Hz Kudankulam 1000 MW tripping event Jan Hz Feb 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 ) Hz Hz Hz

21 Frequency Response Characteristics (FRC) has increased from 6000 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 13 th Feb 2017 in petition 65/MP/2014 Target FRC of MW/Hz suggested along with testing 21

22 CERC Terms and Conditions of Tariff Regulations, 2014 the rate of return of a new project shall be reduced by 1% for such period as may be decided by the Commission, if the generating station or transmission system is found to be declared under commercial operation without commissioning of any of the Restricted Governor Mode Operation (RGMO)/ Free Governor Mode Operation (FGMO), data telemetry, communication system 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 22

23 Secondary control through Automatic Generation Control (AGC) 23

24 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

25 AGC input Data Scheduled interchange Tie line telemetry (MW) Actual unit generation (MW) Frequency (Actual & Desired) Economic Dispatch program (ED) data

26 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.

27 Automatic Generation Control Interfaces Unit Economic Basepoints Unit Economic Participation Factors Economic Dispatch Net Scheduled Interchange Interchange Scheduling External Interfac e External ACE External Unit Data Island Data Estimated Unit & Line MW Automatic Generation Control State Estimato r Setpoint/ Pulse Control Commands Unit Connection Status Unit Control Status Unit Output Unit Limits Unit Ramp Rates ACE Calculation Unit Control Mode Unit Basepoint Unit Ramp Schedules System frequency System Time Error Tie Line Flows 19

28 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

29 Project progress A team from POSOCO, POWERGRID and M/s Siemens visited NTPC Dadri on 6 th May 2016 to explore the ground level requirements with NTPC Execution of AGC pilot project as per technical specifications through limited tender Invited bids on 21 st October 2016 from the four SCADA vendors M/s ALSTOM M/s OSI M/s Siemens M/s ABB Bids opened on 30 th Nov 2016 Letter of Award (LOA) issued to M/s Siemens on 18 th Jan 17 and accepted by Siemens on 25 th Jan 17 CERC Petition filed by POSOCO for payment mechanism on 3 rd April 2017 Hearing by CERC scheduled on 18 th July

30 Technical Specifications 30

31 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 31

32 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. 32

33 Draft Rules for the CLU Algorithm at NTPC Receive Unit Status, Present Schedule and DeltaP signal and number of mills. If Present Schedule is close to 230, 330 or 430 MW, start another extra mill to create Spinning Reserve. Delta P signal be clamped to +/- 50 MW if the value is outside +/- 50 MW. The biasing between units should be user enterable. Start with 0.5, for equal contribution. Difference between two consecutive ICCP refresh values of Delta P shall be clamped to a limit of 1 MW to start with. (i.e., Max(Delta Delta P) = 1 MW) 33

34 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 34

35 1. Factoring AGC signals while evaluating deviations Energy produced due to AGC signals should not be considered as deviation from the schedule Aggregated AGC incremental MW signals over 15 minutes / 5 minutes would be logged in MWh at NLDC. AGC MWh logs forwarded to NRPC secretariat on weekly basis. Deviation in MWh for every time block would be worked out as MWh deviation = (Actual MWh)-(Scheduled MWh)- (AGC MWh) which would be settled as per the existing DSM Regulations 35

36 2. Compensate for the Extra Energy spent/saved The AGC energy account will be available every week For AGC MWh generated during a block, variable charges to Dadri from the NR DSM pool For AGC MWh reduced during a time block Dadri charges to the NR DSM pool 36

37 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 37

38 Inputs needed for Accounting (Main and Standby) MW Delta P signals every 10 seconds at NTPC Dadri (Main) Delta P = P AGCsetpoint P schedule 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 38

39 Regulation accuracy of the solar plant demonstration exceeded accuracy of conventional resources 100% Regulation Up Accuracy Page 39 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Source: CAISO Steam Turbine Pump Turbine Hydro Combined Cycle Limited Energy Storage Gas Turbine Solar PV (Middle of the Day) Solar PV (Sunset) Solar PV (Sunrise) 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

40 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 MW up/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 Dadri Stage-II on days when full generation is requisitioned or schedule is at technical minimum Take up other pilot projects including wind and solar 40

41 Automatic Generation Control (AGC) Pilot Project Implementation Philosophy

42 Region considered as an Area for secondary control ACE = (Ia - Is) + 10 * Bf * (Fa - 50) NORTHERN REGION NORTH- EASTERN REGION WESTERN REGION SOUTHERN REGION Eastern REGION Ia = Actual net interchange, negative for NR meaning import by NR EASTERN REGION 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 42 both possible

43 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

44 Technical Specifications New

45 Data Flow in AGC Project Back-up NLDC SCADA AGC On/OFF AGC Set point Scaled ACE ICCP NR-IR Schedule NR-IR Actual Frequency AGC System at NLDC AGC Local/Remote Unit Load Set Point Actual Generation Circuit Breaker Status IEC 104 Protocol AGC Set point AGC Local/Remote Unit Load Set Point Actual Generation Circuit Breaker Status AGC console at NTPC Factor AGC RTU at NTPC DeltaP NTPC DCS

46 Control block diagram at NLDC Unit Load Set Point schedule total from unit 5 &6 ACE 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

47 Communication block diagram Setpoint AGC Database in the IMM SCADA Database in the IMM ICCP of NLDC SCADA & IFS before sending towards NTPC RTU IMM : Information Model Management IFS: Independent Front End Server ICCP : Inter Control Centre Protocol RTU: Remote Terminal Unit

48 Sample dashboard

49 AGC set point from NLDC AGC using ACE, ULSP, tuned parameters, limits etc. P Schedule (Back up) P AGC Setpoint (Back up) NLDC PC with provision to enter AGC unit biasing manually, if needed AGC RTU at Plant with algorithm to produce final unit wise set points A1 A2 P AGC Setpoint total (main) Unit DCS Inputs from the two unit DCS: ULSP of the generator for the present time block and breaker status P Schedule (main) B1, B2 Max Load Set point Unit 1 Unit Capability Unit 2 NTPC Min Load Set point Turbine Control Boiler Control NTPC side Block diagram 49

50 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

51 Output limit checks 50 MW utilization of Spinning Reserve Plant Ramp rate (~ 10 MW/min) honoured while giving DeltaP signals 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.

52 NTPC DCS snapshot

53 Sample performance plots 0000hrs of 10 th June 2017 to 0000hrs of 12 th June 2017

54 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

55 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 10 th June to 00 hrs of 12 th June 2017 Delta P data was plotted for comparison 10 th -12 th June 17 were predominantly Regulation Down days Block wise AGC MWh computed

56 Comparison graph

57 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 variable charges plus markup 50ps to Dadri from the NR DSM pool For AGC MWh reduced during a time block Dadri variable charges to the NR DSM pool Incentive of 50ps earned by Dadri during down regulation

58 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

59 AGC Pilot Project at NTPC Dadri Stg-II Report of the Mock Test conducted on 29 th June 2017 Pioneering Experience

60 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

61 AGC ON/OFF tested for 4 minutes from 1847 to 1851 hrs Actual generation following the ULSP schedule before AGC correction AGC in local mode Unit 6 taken into AGC Remote at 1741 hrs Unit 5 taken into AGC Remote at 1814 hrs Total Plant under AGC Dadri Stg-II total Plant actual generation following the AGC Set point Mock Test finished at 1910 hrs

62 AGC Correction +ve = Reg Up AGC Correction -ve = Reg Down ACE +ve = NR Surplus ACE ve = NR Deficit Variation of AGC correction (Delta P) wrt NR Scaled Area Control Error AGC Correction Restricted to +/- 50 MW (Maximum Spinning Reserve utilization from NTPC Dadri Stg-II) AGC ON/OFF tested for 4 minutes from 1847 to 1851 hrs AGC in local mode Unit 6 taken into AGC Remote at 1741 hrs Unit 5 taken into AGC Remote at 1814 hrs Total Plant under AGC Mock Test finished at 1910 hrs

63 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

64 Extra Reading

65 Effect of RGMO Presently Grid Frequency is frequently out of the dead band (+/ 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.

66 Interaction with RGMO Plant taken into AGC Remote at 1814 hrs RGMO switched ON at 1900 hrs Mock test completed at 1910 hrs

67 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)

68

69 AGC way forward Petition no. 79/RC/2017 was filed in this matter by POSOCO with Hon ble Commission. Pettion was admitted on 18 th 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 21 st sept 2017

70 Thank you