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1 Use of the new revisions of IEEE Standards 421.2 and 421.5 to satisfy international grid code requirements Presented by: Les Hajagos Kestrel Power Engineering - Canada [email protected] 2 Introduction • In North America, we have the NERC Reliability Standards in place. In other regions around the world, local grid codes have similar requirements. • The Excitation System SC will report on our many recent activities related to testing and modeling of excitation systems, associated controllers and limits to support meeting these requirements • See also our companion presentation 16PESGM2680 ‘“The Impact of Grid Codes Upon Generator Excitation System Design and Standards” 3 Presentations Presentation 421.2 Guide for Identification, Testing and Evaluation of Dynamic Performance 421.5 Recommended Practice for Models for Power System Stability Studies Overview of grid codes Practical international experiences 421.5 sample data and model data usability Testing model data usability Power System Stabilizer tuning criteria Excitation limiter models and protection coordination Presenter Organization Rich Schaeffer Basler Electric Les Hajagos Kestrel Power Robert ThorntonBrush Electric Jones José Taborda JT Consulting Quanta Alex Schneider Technology Leo Lima Kestrel Power Bureau of Shawn Patterson Reclamation Les Hajagos Kestrel Power 4 IEEE 421 Series of Standards • 421.1 Standard Definitions • 421.2 Guide for Identification, Testing and Evaluation of Dynamic Performance • 421.3 High-Potential Test Requirements • 421.4 Guide for Preparation of Specifications • 421.5 Recommended Practice for Models for Power System Stability Studies • 421.6 Specification and Design of Field Discharge Equipment 5 NERC Standards (Excitation Related) • MOD-025-2, Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability • MOD-026-1, Verifications of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions • VAR-002-4, Generator Operation for Maintaining Network Voltage Schedules (includes AVR/PSS requirements) 6 NERC Standards (Excitation Related) • PRC-005-2 Protection System Maintenance – may impact new exciters with built in protection • PRC-019-2 Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection • PRC-024-1 Generator Performance During Frequency and Voltage Excursions 7 NERC MOD-026-1 Verifications of Models and Data for Generator Excitation Systems Items to be verified by measurement and reported are: • manufacturer and type of excitation system (e.g. static, brushless, rotating dc, etc.) • model for each excitation system / voltage regulator control system with associated gains, time constants, and limits • static set points for under and over excitation limiters • reactive compensator settings • Measured data showing match between measurement and simulations • model for each power system stabilizer with associated gains, time constants, and limits • Associated generator model 8 Example Grid Code Excitation Response Requirements Each synchronous generation facility that is rated at 10 MVA or larger shall be equipped with an excitation system with • A voltage response time to either ceiling not more than 50ms for a 5% step change from rated voltage under open-circuit conditions and; • A linear response between ceilings • Positive and negative ceilings not less than 200% and -140% of rated field voltage at rated terminal voltage and rated field current • A positive ceiling not less than 170% of rated field voltage at rated terminal voltage and 160% of rated field current 9 421.5 Recommended Practice for Models for Power System Stability Studies • This IEEE standard started in 1968 with papers describing simulation models following the initial creation of NERC and the use of digital simulation programs to study and operate power systems • It includes the necessary simulation models of the excitation system major control functions: AVR, RCC, PSS and the new 2016 revision includes models of OEL, UEL and SCL functions and PF/Var controllers and most importantly linkages of the limiters to the AVR 10 421.5 Excitation System Classifications • Three distinctive types of excitation systems are identified on the basis of excitation power source: • a) Type DC Excitation Systems, which utilize a direct current generator with a commutator • b) Type AC Excitation Systems, which use an alternator and either stationary or rotating rectifiers to produce the direct field current • c) Type ST Excitation Systems, in which excitation power is supplied through transformers or auxiliary generator windings and rectifiers 11 Summary of Changes and Equivalence of Models Model Name Example DC Rotating Exciters Version of IEEE Std. 421.5 2015 2005 1992 DC1C DC1A DC1A Additional options for connecting OEL limits and additional limit VEmin DC2C DC2A DC2A Additional options for connecting OEL limits and additional limit VEmin DC3A DC3A DC3A no changes DC4C DC4B n/a Additional options for connecting OEL and UEL inputs 12 Additional Excitation System Functions • • • • • • • Voltage sensing and load compensation Power system stabilizer Over-excitation limiter Under-excitation limiter Stator current limiter Power factor and var control Discontinuous excitation controls 13 Functional Block Diagram for Synchronous Machine Excitation Control System (VSCLsum) or (VSCLoel and VSCLuel) Vpf/VAr VUEL VC VOEL STATOR CURRENT LIMITER P, Q, V, I Q, pf PF/VAr CONTROLLER P, Q, V, I UNDEREXCITATION LIMITER VOLTAGE MEASUREMENT TRANSDUCER VC1 CURRENT COMPENSATOR V, I OVEREXCITATION LIMITER VFE EXCITATION CONTROL ELEMENTS EFD SYNCHRONOUS MACHINE AND POWER SYSTEM EXCITER EFE IFD VREF VS VST DISCONTINUOUS EXCITATION CONTROL POWER SYSTEM STABILIZER VSI 14 Type DC1C DC Commutator Exciter VOEL VUEL VOEL a b b VUEL a VREF VC – VRmax + + S + + VS + + S 1+sTC HV gate 1+sTB – LV gate EFE KA 1+sTA VRmin VSCLsum a a VUELscl VOELscl b b + 1 S sTE – EFDmin VFE S VF EFD + + VX KE SE(EFD) (a) sKF 1+sTF alternate OEL input locations (VOEL) a summation point b take-over footnotes: (a) VX = EFD∙SE(EFD) alternate UEL input locations (VUEL) a summation point b take-over alternate SCL input locations (VSCL) a summation point b take-over 15 Type PSS2C Power System Stabilizer Model VSI1max VSI1 VSTmax sTW1 sTW2 1 1+sTW1 1+sTW2 1+sT6 + S + VSI1min sTW3 u1 1+sTW3 sTW4 VSI2min (1+sT9)M N + S – KS1 1+sT1 1+sT3 1+sT10 1+sT12 1+sT2 1+sT4 1+sT11 1+sT13 VPSS VSTmin KS3 VSI2max VSI2 1+sT8 1+sTW4 u2 block bypass logic (a) y KS2 1+sT7 7 PSS types available Inputs to all excitation types PSS VST output logic (b) 16 Sample Data for PSS2C Stabilizer (for AC6C Model) Description Power system stabilizer gain Power system stabilizer gain Power system stabilizer gain PSS transducer time constant PSS transducer time constant [3] PSS washout time constant PSS washout time constant PSS washout time constant PSS washout time constant PSS ramp tracking filter numerator time constant PSS ramp tracking filter denominator time constant PSS ramp track filter denominator exponent PSS ramp track filter numerator exponent PSS numerator (lead) compensating time constant (1st block) PSS denominator (lag) compensating time constant (1st block) PSS numerator (lead) compensating time constant (2nd block) PSS denominator (lag) compensating time constant (2nd block) PSS numerator (lead) compensating time constant (3rd block) PSS denominator (lag) compensating time constant (3rd block) PSS numerator (lead) compensating time constant (4th block) PSS denominator (lag) compensating time constant (4th block) Maximum PSS output Minimum PSS output Input signal #1 maximum limit Input signal #1 minimum limit Input signal #2 maximum limit Input signal #2 minimum limit Generator MW threshold for PSS activation Generator MW threshold for PSS de-activation Symbol KS1 KS2 KS3 T6 T7 Tw1 Tw2 Tw3 Tw4 T8 T9 M N T1 T2 T3 T4 T10 T11 T12 T13 VSTmax VSTmin VSI1max VSI1min VSI2max VSI2min PPSSon PPSSoff Type A E/A E E A A A A A A A A A A A A A A A A A A A A A A A A A Value 20 [2] 1 0.0 10 10 10 10 [4] 0.30 0.15 2 4 0.16 0.02 0.16 0.02 [5] [5] [6] [6] 0.20 –0.066 2 -2 2 -2 0 0 Units pu pu pu s s s s s s s s s s s s s s s s pu pu pu pu pu pu pu pu 17 OEL activation logic Ibias VOELmax3 + S (a) – Ex: OEL2C Ierr (b) KPoel+ KIoel + s + VOELmax2 sKDoel 1+sTC2oel 1+sTC1oel 1+sTDoel 1+sTB2oel 1+sTB1oel VOELmin3 Iact VOELmax1 VOELmin2 VOEL VOELmin1 TFCL Iinst KACT 1 1 1+sTAoel OEL input 5 types of OEL (d) KSCALE Ipu Summation and takeover styles Z Ilim Tlim VINVmax Tmax W K2[(Ipu/ITFpu)c2−1] IERRinv2 – IERRinv1 K1[(Ipu/ITFpu) −1] ITFpu S (f) c1 1+sTRoel (e) s Iref + Terr OEL ramp rate logic OEL timer logic VINVmin + 1 S s – (c) Tmin KFB footnotes: Inputs to all excitation types (a) OEL activation logic uses user-selected parameters Ten, Toff, ITHoff, Ireset and Iinst. It also uses the signals Terr, Iact and Iref shown in the block diagram. IF {(Terr ≤ 0) or [(Iact > Iref) for longer than Ten]} or (Ten =0) enable OEL à Ibias = 0 IF {(Iref = Iinst) and [(Iref – Iact) > ITHoff} for longer than Toff reset OEL à Ibias = Ireset (b) (c) The OEL transfer function is either just the gain KPoel, or the PID control, or the double lead-lag blocks. The parameters in the model should be set accordingly. OEL timer logic uses user-selected parameters FixedRU, FixedRD and ITFpu. It also uses the signals Ipu and IERRinv2, shown in the block diagram. IF (ITFpu − Ipu) ≥ 0 W = FixedRU + IERRinv2 ELSE W = FixedRD + IERRinv2 ENDIF (d) OEL input is user-selected. Could be generator field current IFD or generator field voltage EFD or exciter field current VFE. (e) Parameter KSCALE should be calculated to convert from the per unit base used for the OEL input signal to a per unit base corresponding to the rated value for the selected OEL input signal. All other parameters in the model are expressed in per unit of rated value. (f) OEL ramp rate logic uses user-selected parameters SW1, KZRU, TFCL, KRU and KRD. It also uses the signals Terr and IERRinv1, shown in the block diagram. The parameter SW1 is a user-selected logic, which will select fixed ramp rates or a ramp rate function of the field current error. IF SW1 = 0 C = KRU D = KRD ELSE C = IERRinv1 D = IERRinv1 ENDIF IF Terr ≥ Kzru*TFCL Z=C ELSEIF Terr ≤ 0 Z=D ELSE Z=0 ENDIF (fixed ramp rates) (ramp Iref up) (ramp Iref down) 18 2 UEL types inputs to all excitation types summation and takeover styles VURmax VUR – – y1=|KUC∙VT−j∙IT| VUImax – y1 VUC + – IT S VUerr KUL+ – VUImin VF VUF KUF VUImax KUI 1+sTU1 1+sTU3 s 1+sTU2 1+sTU4 VUEL Q (pu) VUImin ra d ius =K UR Vars out (+) normalized limit function specified for VT = 1 pu PT QT VUCmax – VT Center = KUC y2 KUR - KUC – y2=|KUR∙VT| op. point UEL not limiting P (pu) Vars in (−) UEL limiting 19 overexcited range VSCLmax LV gate 1 1+sTIT y = (u) u inputs to all excitation types 1 1 1+sTQSCL + – S – 1+sTINV + – S + S ISCLerr ISCLinv IQmin – S KPoex+ B KIoex s y ISCLlim – IQ A Ioex2 K delayed reactive power logic 2 SCL types IT Ioex1 SW1 (b) 0 S + SW1 VSCLmax (b) B KPuex+ A KIuex s Iuex1 VSCLmin 0 underexcited range footnotes: summation and takeover styles – (c) Iuex2 LV gate VSCLmin (a) The reactive current IQ is defined in this model as the reactive power output of the generator (QT) divided by the magnitude of the terminal voltage (VT). In other words, IQ is positive for over-excited operation. (b) SW1 is a user-selected option. When position A is selected, the SCL response is derived from the reactive current. When position B is selected, the SCL response is derived from reactive power. (c) The delayed reactive power logic uses user-selected parameters SW2, TDSCL and VSCLdb. It also uses the signals ISCLerr and ISCLinv shown in the block diagram, and the generator reactive power output QT: IF [(SW2 = 0) and (ISCLerr > 0 for longer than TDSCL)] or [(SW2 ≠ 0) and (ISCLinv > 0)] THEN IF QT > VSCLdb THEN Ioex2 = ISCLerr Iuex2 = 0 ELSEIF QT < −VSCLdb THEN Ioex2 = 0 Iuex2 = ISCLerr ELSE Ioex2 = 0 Iuex2 = 0 ENDIF ELSE Ioex2 = 0 Iuex2 = 0 ENDIF VSCL 20 2 PF and VAR types PFREFnorm (b) + S PFerr – PFnorm VT IT VPFLMT pf controller logic Verr KPpf + (c) KIpf s VPF (a) −VPFLMT footnotes: (a) The output of the model (VPF) is an incremental variable that should be added to the voltage reference setpoint (VREF) in the excitation system model. (b) The signal PFnorm is the normalized power factor of the machine, while PFREFnorm is the desired (reference) setpoint, using the same normalization as PFnorm. (c) The PF controller logic uses user-selected parameters VITmin, VVTmin, and VVTmax. It also requires the signals PFerr and the magnitudes of the generator terminal voltage (VT) and current (IT). The logic also depends on the status of the excitation limiters, OEL, UEL and/or SCL. Verr = 0 IF OEL and UEL and SCL are inactive IF (IT > VITmin) and (VT > VVTmin) and (VT < VVTmax) Verr = PFerr ENDIF ENDIF 21 Per Unit System • • • • Generator Stator Quantities Generator Field Quantities Exciter Field Quantities Saturation (Generator and Rotating Exciter) 22 Manufacturer Model Cross Reference ST1C Silcomatic (a trademark of Canadian General Electric Co.). Westinghouse Canada Solid State Thyristor Excitation System; Westinghouse Type PS Static Excitation System with Type WTA, WTA-300 and WHS voltage regulators. Static excitation systems by ALSTOM, ASEA, Brown Boveri, GEC-Eliott, Hitachi, Mitsubishi, Rayrolle-Parsons, and Toshiba. General Electric Potential Source Static Excitation System. Basler Model SSE/SSE-N. UNITROL (a registered trademark of Asea Brown Boveri, Inc.); THYRIPOL (a registered trademark of Siemens AG.); Westinghouse WDR and MGR, REIVAX static excitation systems. ST2C General Electric static excitation systems, frequently referred to as the SCT-PPT or SCPT. ST3C General Electric Compound Power Source and Potential Power Source GENERREX excitation systems (GENERREX is a trademark of General Electric Co.) ST4C Basler DECS applied to static excitation, Brush PRISMIC applied to static excitation, General Electric EX2000/2100/2100e bus fed potential source and static compound source and GENERREX-PPS or GENERREX-CPS; Canadian General Electric SILCOmatic 5, Basler/Eaton Cutler-Hammer ECS2100 static excitation system, Andritz Hydro THYNE applied to static excitation, Emerson/Emerson Ovation DGC or REIVAX static excitation systems. ST5C UNITROL D, P, F, and 5000 (trademarks of Asea Brown Boveri); Brush DCP. ST6C THYRIPOL (a trademark of Siemens AG) and Basler/Eaton Cutler-Hammer ECS2100 static excitation systems. ST7C ALSTOM excitation systems Eurorec, Microrec K4.1, ALSPA P320 (ALSPA P320 is a trademark of ALSTOM), ControGen HX. ST8C ST9C ST10C Andritz Hydro THYNE applied to static excitation GE Power Conversion SEMIPOL UNITROL F, 5000, 6080, 6800 (trademarks of Asea Brown Boveri) applied to static excitation 23 Example References and Bibliography • 421 series of standards • IEEE Std. C50.13 Synchronous Generators • IEEE 115 Guide for Test Procedures for Synchronous Machines • IEEE 1110 Guide for Synchronous Generator Modeling Practices • IEEE 09TP250 Tutorial Course on Power System Stabilization via Excitation Control 1 Use of the new revision of IEEE Standard 421.2 to satisfy international grid code requirements Presented by: Rich Schaefer Basler Electric - USA [email protected] 2 421.2 Purpose • Provide a basis for evaluating the closed loop performance of excitation control systems • Confirm the adequacy of mathematical models for excitation control systems for use in analytical studies of power systems 3 NERC MOD-026-1 Verifications of Models and Data for Generator Excitation Systems Items to be verified by measurement and reported are: • manufacturer and type of excitation system (e.g. static, brushless, rotating dc, etc.) • model for each excitation system/voltage regulator control system with associated gains, time constants, and limits • static set points for under and over excitation limiters • reactive compensator settings • Measured data showing match between measurement and simulations • • model for each power system stabilizer with associated gains, time constants, and limits Associated generator model 4 421.2 Guide for Identification, Field Testing and Evaluation of Dynamic Performance NERC MOD 026 requires simulation models validated by test results of excitation system controls including: •Automatic voltage regulator- Small Signal Response •Reactive current compensation- Reactive Droop •Excitation Limiter Validation- Specific dynamic performance requirements •Power System Stabilizer Tuning- Frequency Response 5 421.2 Dynamic performance classifications Large signal performance criteria • Ceiling current and voltage • Voltage response time • High initial response Small signal performance • Frequency response characteristics • Stability/Stabilizers Effects of excitation limiters 6 Example Grid Code Excitation Response Requirements Each synchronous generation facility that is rated at 10 MVA or larger shall be equipped with an excitation system with • A voltage response time to either ceiling not more than 50ms for a 2-5% step change from rated voltage under open-circuit conditions and; • A linear response between ceilings • Positive and negative ceilings not less than 200% and 140% of rated field voltage at rated terminal voltage and rated field current • A positive ceiling not less than 150% of rated field voltage at rated terminal voltage. Software Tools for Field Testing to IEEE 421.2 Performance Expectations: 2-5% Voltage Step Change in AVR Mode OverExcitation Limiter Testing Under Excitation Limit Dynamic Step Test 11 Frequency Response Measurement for PSS compensation *figure courtesy KPE Built-in Dynamic System Analyzer to perform Generator Frequency Response with Bode Plot Chart Recorder to monitor the Generator Output Internal Dynamic System Analyzer via software Bode Plot to display immediate system results Questions 1 Use of the new revisions of IEEE Standards 421.2 and 421.5 to satisfy international grid code requirements Overview of Grid Codes Presented by: Robert Thornton-Jones Brush Electric - UK [email protected] 2 Introduction • In North America, we have the NERC Reliability Standards in place. In other regions around the world, local grid codes have similar requirements. • The Excitation System SC will report on our many recent activities related to testing and modeling of excitation systems, associated controllers and limits to support meeting these requirements • See also our companion presentation 16PESGM2680 ‘“The Impact of Grid Codes Upon Generator Excitation System Design and Standards” 3 Presentations Presentation 421.2 Guide for Identification, Testing and Evaluation of Dynamic Performance 421.5 Recommended Practice for Models for Power System Stability Studies Overview of grid codes Practical international experiences 421.5 sample data and model data usability Testing model data usability Power System Stabilizer tuning criteria Excitation limiter models and protection coordination Presenter Organization Rich Schaeffer Basler Electric Les Hajagos Kestrel Power Robert ThorntonBrush Electric Jones José Taborda JT Consulting Quanta Alex Schneider Technology Leo Lima Kestrel Power Bureau of Shawn Patterson Reclamation Les Hajagos Kestrel Power UK GRID CODE : COMPLIANCE PROCESS UK Grid Code Applies to… All Transmission Connected Power Stations • i.e. Connection Points >132kV • Most Generators > 200MW are Transmission Connected Embedded Large Power Stations • According to Registered Capacity – see below Medium power stations where CUSC Contract is with National Grid not DNO (CUSC = Connection and Use of System Code contract) UK Grid Code Does Not Apply to Small Power Stations Classifications of Power Stations by Registered Capacity (RC) England & Wales (NGET Area) Large ≥ 100MW, Medium ≥ 50MW, Small < 50MW South of Scotland (SPT Area) Large ≥ 30MW, Small < 30MW North of Scotland (SHETL Area) Large ≥ 10MW, Small < 10MW UK GRID CODE : COMPLIANCE PROCESS Most National Grid compliant generators are >= 250MW Existing Grid Code may change with ENTSOE arriving – see later • Existing Grid Code invoked if the Power Station is > 100MW • likely to revert to Generator Rating rather than Power Station Rating hence for a 105MW generator on site with 6MW of auxiliaries Grid Code would not apply Guidance Notes for Synchronous Generators • Full Grid Code is nearly 600 pages written by lawyers !! • Guidance Notes explain procedures to follow and Grid Code requirements for generators in a more readable form. http://www.nationalgrid.com/NR/rdonlyres/B4DF2400-96FD-40E5-AF448DB88AADA5DF/56510/GuidanceNotesforSynchronousGeneratorsIssue12September2 012.pdf UK GRID CODE : TECHNICAL REQUIREMENTS Technical Requirements Short Circuit Ratio >= 0.5 This requirement has been relaxed for new large nuclear sets but not for medium & smaller Transient Voltage Control... Stepping from 90% to 100% Ut in 600ms, damped to within 5% in < 3s. BCA Specifies Time to Achieve Uf … Can be 50ms to 300ms BCA Specifies Excitation On Load Positive Ceiling for 10% Ut Drop… Can be up to 4pu, typically 2pu to 3pu Power System Stabilizer Required To be demonstrated with random noise injection (200mHz to 3Hz) http://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8B7B8B9AF2408/57423/0_FULL_GRID_CODE_I5R1.pdf UK Grid Code\GBGridCodeI3R27-appendix6-AVR.pdf UK Grid Code\pp_09_32ShortCircuitRatio.pdf UK Grid Code\relaxation of SCR letter.pdf EUROPEAN GRID CODE : TECHNICAL REQUIREMENTS 5 European Synchronous Power System Areas. Categorization into Type requirements A, B, C or D, for generating units according to size and connection point location. as with Hydro Quebec and BC Hydro…. certain Voltage Ranges proposed to exceed those of the IEEE C50.13 and IEC 60034 standards e.g. Type D generators in the Baltic area, continuous operation at 1.10pu voltage is proposed as a requirement ENTSO-E is likely to revert to Generator Rating rather than the Present UK Power Station Rating RUSSIAN GOST STANDARDS GOST & NIIPT / SO-UPS-OJSC Excitation Systems for Turbogenerators (GOST 21558-2000) Requirements mandatory >60MW 4.7 Voltage excitation forcing ratio and current excitation forcing >= 2. • 4.10 Operating speed of excitation during forcing < 60ms for high speed systems Total de-forcing time < 150ms. • 4.12 Delay of system under forcing: • < 30ms for low speed systems • < 20ms for high speed system Generally aiming for static excitation system AUSTRALIAN NATIONAL ELECTRICITY RULES : COMPLIANCE PROCESS NER has 3 Access Standards : Usually aim for highest “Automatic” “R1” Data Collection – Factory Test & Design Data “R2” Data Derived from On-System Testing See 2008 AEMO “Generating System Model Guidelines” AustrailianGridCode\Generating System Model Guidelines.pdf Require specified format model configuration files R1 Requires Significant Extra Resources and Time for… Test of brushless generator with Test Slip Rings Combined Generator & Excitation Test Full Test of Limiters Full Testing of Switch to Standby Verification of Power System Stabilizer Test AUSTRALIAN NATIONAL ELECTRICITY RULES : TECHNICAL REQUIREMENTS Regulation of voltage to within 0.5% of the set point. Voltage set point to be continuously controllable in the range of at least 95% to 105%. Excitation ceiling voltage must be 1.5 times that required for rated operation. (2.3 times for static systems.) Settling times for a step change of voltage set point must be… less than 2.5 seconds for a 5% voltage step on open circuit. less than 5.0 seconds for a 5% voltage step with the generating unit on load (active and reactive) with AVR limiters not operating less than 7.5 seconds for a 5% voltage step with the generating unit on load (active and reactive) when operating into an AVR limiter from an operating point where a voltage step of 2.5% would just cause the limiter to operate. This applies to each limiter. Ability to increase field voltage from rated to ceiling in less than 500ms. (50ms for static systems.) Power System Stabilizer including the usual features such as output limiter, data recording and test facilities. IRISH GRID CODE : TECHNICAL REQUIREMENTS Wind Turbines to Provide the island with >37% of Demand by 2020 Average On-Line Synchronous Inertia to be Reduced by 25% Hence Much Greater Emphasis on Validation Testing Site-work needs to be planned carefully Leading Var Capability of 0.7 Power Factor at 35% Registered Power Capacity. More Onerous Than Other Grid Codes. Need to be Prepared to Demonstrate. Possible Future Requirement for Higher Inertia Machines to Compensate for Wind Penetration. 1 2016 IEEE/PES General Meeting July 17th-21st, 2016 – Boston, MA Panel Session Use of the New Revisions of IEEE Std. 421.2 and 421.5 to Satisfy International Grid Code Requirements Testing model data usability Excitation Systems PSS Limiters Presented by: Leo Lima Kestrel Power Engineering – USA [email protected] 2 Introduction • North American reliability standards • NERC Std. MOD-026 and MOD-027 –Transmission Planner has 90 calendar days to respond if provided models are usable or not. • Models initialize without error • No spurious behavior during a no-disturbance (flat) simulation • Adequate response (stable response) following a disturbance that is otherwise stable • Usability in these Standards is not related to an assessment of adequacy of the dynamic response of the equipment 3 Full System Model • Update models to the database of the full interconnected system model • NERC Model Validation Procedures – Routine Tests • No-fault test (no-disturbance test) • Ring down test • Regional tests • NERC Std. MOD-032 • NERC Std. MOD-033 4 Simplified Tests • • • • • • Open Circuit Step Response Response Ratio Test Online Voltage Reference Step Response PSS model testing Excitation limiter testing Turbine/speed governor testing 5 Open Circuit Step Response – Each generation unit is initially operating at full speed, no load (not synchronized to the grid) – Could be an automatic function of the software, such as PSS/E ESTR/ERUN – Results are comparable to actual equipment commissioning tests – Excellent for checking excitation system (AVR) dynamic response – Also checks some parameters of the synchronous generator model 6 Open Circuit Step Response – Does not test PSS models – Might not be applicable to test excitation limiter models – Might not test the limits (ceilings) of the excitation system 7 Response Ratio Test – Response Ratio (aka Excitation System Nominal Response) is defined in IEEE Std. 421.2 – Provides the value for the rated field voltage and current of the equipment – Might test the excitation system limits (positive ceiling) – Might not be applicable to high-initial response excitation systems, particularly when field current limiters (e.g. OEL) is not represented in the simulation 8 Online Voltage Reference Step – Single machine versus infinite bus (SMIB) model – Comparable to actual field commissioning tests – Related to the local mode of oscillation of the unit – Oscillation frequency in the simulation is related to the generator dispatch and the value of the transfer impedance in the SMIB system – Simulations with and without the PSS model will show the PSS contribution to damping at this oscillation frequency 9 Synthetic System et iG E Re Xe iline Pload +j Qload • • Load as constant impedance F. P. Demello and C. Concordia, "Concepts of Synchronous Machine Stability as Affected by Excitation Control," in IEEE Transactions on Power Apparatus and Systems, vol. PAS-88, no. 4, pp. 316-329, April 1969. doi: 10.1109/TPAS.1969.292452 Load as constant power F. J. De Marco, N. Martins and J. C. R. Ferraz, "An automatic method for power system stabilizers phase compensation design," in IEEE Transactions on Power Systems, vol. 28, no. 2, pp. 997-1007, May 2013. doi: 10.1109/TPWRS.2012.2209208 10 PSS Model Testing • Using the synthetic system, effect of PSS on oscillation damping can be assessed for any frequency of interest • For low frequencies (inter-area modes), most of the generator output is feeding the local load, not being transferred to the infinite bus • Limited overall effectiveness of the PSS, as it is modulating just a small fraction of the total power output of the generator 11 PSS Model Testing 2900 2700 PSS no PSS 2500 Et (kV) 20.1 19.9 19.7 Efg (Vdc) 19.5 speed (pu) • Local mode SMIB no local load XE = 20% P (MW) 3100 200 150 100 50 0 -50 0.0010 0.0005 0 -0.0005 -0.0010 -0.0015 0 2 4 Time (seconds) 6 8 10 12 PSS Model Testing 2880 P (MW) 2800 2760 PSS no PSS 2720 20.2 Et (kV) 20.0 19.8 19.6 Efg (Vdc) 19.4 200 150 100 50 0 -50 0.00075 speed (pu) • Inter-area SMIB local load XE = 200% 2840 0.00025 -0.00025 -0.00075 0 5 Time (seconds) 10 15 13 PSS Model Testing 3300 • No PSS P (MW) 3100 2900 2700 2500 XE=20 pu XE=2.0 pu XE=0.2 pu 2300 0.002 spd dev (pu) 0.001 0 -0.001 -0.002 0 5 10 Time (seconds) 15 20 25 14 Excitation Limiter Testing • How to check these models for usability? – Commissioning field tests often performed at modified settings (lowered limits) – Disturbances resulting in activation of the limiters are not common • Suggestion – Single machine versus “almost” infinite bus system – Replace infinite bus by a conventional synchronous generator with excitation system 15 Excitation Limiter Testing • Suggested Test System – Step in voltage reference, to simulate a change in the grid voltage – Positive step → high system voltage → machine goes under excited until reaching UEL – Negative step → low system voltage → machine goes over excited until reaching OEL – Relationship DQ/DET is inversely proportional to the equivalent impedance XE 16 Turbine/Speed Governor Testing • Isolated (islanded) operation or grid-connected operation? – Very important distinction, particularly for hydro units – PSS/E activities GSTR/GRUN automate the test for isolated system conditions – No automated features to test grid-connected response • Playback of recorded system frequency disturbances 17 Turbine/Speed Governor Testing • Suggested Test System – Single machine versus “almost” infinite bus system – Replace infinite bus by a conventional synchronous generator with excitation system and speed governor – Add a local load at the “almost” infinite bus, to make the equivalent machine a generator and to allow a step change in total system load – Adjust magnitude of the step in the system load and parameters of the equivalent governor as necessary 18 Turbine/Speed Governor Testing et iG E Re Xe Pload +j Qload 60.2 60.15 60.1 60.05 frequency (Hz) 60 59.95 WECC trace 59.9 PSS/E Simulation 59.85 59.8 59.75 59.7 59.65 0 10 20 30 time (seconds) 40 50 60 1 Use of the new revisions of IEEE Standards 421.2 and 421.5 to satisfy international grid code requirements Power System Stabilizer Tuning Criteria Shawn Patterson Bureau of Reclamation – USA [email protected] 2 Power System Stabilizers (PSS) • Required in some areas for decades (WECC, Ontario/Quebec-NPCC) • NERC Regional Standard – Western Electricity Coordinating Council (WECC) • Dual input is normal standard requirement (WECC, Brazil, Most Canadian Provinces) 3 PSS • Application of PSS appears as an element in the 421 series of IEEE standards: • 421.5 includes standard models of PSS equipment used by manufacturers • 421.2 includes information on dynamic performance testing of excitation systems that incorporate PSS 4 Power System Stabilizer Models IEEE Standard 421.5 PSS2C is the latest version of the dual input stabilizer VSI1max VSI1 VSTmax sTW1 sTW2 1 1+sTW1 1+sTW2 1+sT6 + S + VSI1min sTW3 u1 1+sTW3 sTW4 1 VSI2min (1+sT9)M N + S – KS1 1+sT1 1+sT3 1+sT10 1+sT12 1+sT2 1+sT4 1+sT11 1+sT13 VPSS VSTmin KS3 VSI2max VSI2 1+sT8 1+sTW4 u2 block bypass logic (a) y KS2 1+sT7 PSS VST output logic (b) 5 Power System Stabilizer Models IEEE Standard 421.5 PSS4C is the latest version of the multi-band variant VVLmax KVL1 KVL2 DwL-I KL1 KL2 KI1 KI2 DwH KH1 KH2 KVL11+sTVL1 1+sTVL3 1+sTVL5 1+sTVL2 1+sTVL4 1+sTVL6 KVL17+sTVL7 1+sTVL9 1+sTVL11 1+sTVL8 1+sTVL10 1+sTVL12 KL11+sTL1 1+sTL3 1+sTL5 1+sTL2 1+sTL4 1+sTL6 KL17+sTL7 1+sTL9 1+sTL11 1+sTL8 1+sTL10 1+sTL12 KI11+sTI1 1+sTI3 1+sTI5 1+sTI2 1+sTI4 1+sTI6 KI17+sTI7 1+sTI9 1+sTI11 1+sTI8 1+sTI10 1+sTI12 KH11+sTH1 1+sTH3 1+sTH5 1+sTH2 1+sTH4 1+sTH6 KH17+sTH7 1+sTH9 1+sTH11 1+sTH8 1+sTH10 1+sTH12 + S KVL VVL – VVLmin VLmax + S KL VL – S VLmin VImax + S KI VI – VImin S S VST VSTmin VHmax + VSTmax KH VH – VHmin 6 IEEE Standard 421.2 • Details both large and small signal performance analysis, requirements, and characteristics of excitation systems – PSS performance rests upon performance of the automatic voltage regulator (AVR) • References the IEEE tutorial document for a comprehensive treatment of PSS theory, application, testing, and performance 7 IEEE PSS Tutorial • Originally developed and published in 1981 • Updated version first presented by the Excitation Systems Subcommittee in 2007 IEEE Tutorial Course in Power System Stabilization via Excitation Control, Excitation Systems Subcommittee, Energy Development and Power Generation Committee, Power & Energy Society, publication 09TP250, first presented at the 2007 IEEE PES General Meeting, Tampa, FL (http://resourcecenter.ieee-pes.org/pes/product/tutorials/PES09TP250) 8 421.2 • Basic requirements for tuning AVRs, with and without PSS – Small signal, time domain performance indices (step response rise time, overshoot, regulation, damping ratio) • Performance measurements required to determine PSS effectiveness – Frequency domain methods and measurements 9 421.2 AVR response Transient Stability vs. Small Signal Stability 10 421.2 Testing Basics 11 421.2 (PSS Tutorial) Tuning and Performance Tuning requirement Note: This also doubles as MOD-026 compliance documentation 12 PSS Elements Signal conditioning And mixing Gain Compensation Limiter VSI1max VSI1 VSTmax sTW1 sTW2 1 1+sTW1 1+sTW2 1+sT6 + S + VSI1min sTW3 u1 sTW4 1 + S – KS1 1+sT1 1+sT3 1+sT10 1+sT12 1+sT2 1+sT4 1+sT11 1+sT13 VPSS PSS VST output logic (b) VSTmin 1+sTW3 VSI2min (1+sT9)M N KS3 VSI2max VSI2 1+sT8 1+sTW4 u2 block bypass logic (a) y KS2 1+sT7 All elements covered comprehensively in the IEEE PSS tutorial 13 PSS Requirements* (*as specified in some regions) Compensation (e.g., within 30 degrees) Washout (maximum time) VSI1max VSI1 VSTmax sTW1 sTW2 1 1+sTW1 1+sTW2 1+sT6 + S + VSI1min sTW3 u1 sTW4 1 + S – KS1 1+sT1 1+sT3 1+sT10 1+sT12 1+sT2 1+sT4 1+sT11 1+sT13 VPSS PSS VST output logic (b) VSTmin 1+sTW3 VSI2min (1+sT9)M N KS3 VSI2max VSI2 1+sT8 1+sTW4 u2 block bypass logic (a) y KS2 1+sT7 Gain Limiter (minimum (minimum requirement) requirement, e.g., 5 percent) 14 Adequate? • AVR and PSS application are some of the most difficult topics for reliability organizations, grid codes, compliance offices • The combination of the 421 standard series (including the referenced PSS tutorial) provides more than enough information for the purposes of reliability standards 15 More • If anything, these documents should be referenced and consulted more – Voltage regulation requirements are usually very simplistic – PSS requirements are lesser known, but are tending to become more technical – Grid codes are just starting to get a handle on performance requirements/standards, so these documents will be essential 1 Excitation Limiter Models and Protection Coordination Presented by: Les Hajagos Kestrel Power Engineering – Canada [email protected] 2 Introduction • In North America, we have the NERC Reliability Standards in place. In other regions around the world, local grid codes have similar requirements. • The Excitation System SC will report on our many recent activities related to testing and modeling of excitation systems, associated controllers and limits to support meeting these requirements • See also our companion presentation 16PESGM2680 ‘“The Impact of Grid Codes Upon Generator Excitation System Design and Standards” 3 Presentations Presentation 421.2 Guide for Identification, Testing and Evaluation of Dynamic Performance 421.5 Recommended Practice for Models for Power System Stability Studies Overview of grid codes Practical international experiences 421.5 sample data and model data usability Testing model data usability Power System Stabilizer tuning criteria Excitation limiter models and protection coordination Presenter Organization Rich Schaeffer Basler Electric Les Hajagos Kestrel Power Robert ThorntonBrush Electric Jones José Taborda JT Consulting Quanta Alex Schneider Technology Leo Lima Kestrel Power Bureau of Shawn Patterson Reclamation Les Hajagos Kestrel Power 4 Excitation Limiters and Protection: Excitation limiters must coordinate with equipment capabilities (generator, exciter, transformers…) and with internal and external protections and ride-through requirements Excitation, power equipment and relaying are typically different departments in a utility – must coordinate and communicate! 5 IEEE 421 Series of Standards • 421.1 Standard Definitions • 421.2 Guide for Identification, Testing and Evaluation of Dynamic Performance • 421.3 High-Potential Test Requirements • 421.4 Guide for Preparation of Specifications • 421.5 Recommended Practice for Models for Power System Stability Studies • 421.6 Specification and Design of Field Discharge Equipment 6 NERC Standards (Excitation Related) • PRC-005-2 Protection System Maintenance – may impact new exciters with built in protection • PRC-019-2 Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection • PRC-024-1 Generator Performance During Frequency and Voltage Excursions 7 NERC PRC-019-2 Verification that generator voltage regulator controls and limit functions are coordinated with the generator’s capabilities and protective relays Study results with plots or data that could be plotted for the following: • Generator capability curve, including specification of nominal voltage, ambient air or cooling temperature, or hydrogen pressure. • Steady state over-excitation limiter and under-excitation limiter characteristics • MW limit of the prime mover. • Any other limit that could restrict the megawatt or megavar capability. • Loss of excitation / field protective relay characteristics. • Volts-per-hertz protection vs volts-per-hertz limiters • Time vs. field current or time vs. stator current 8 NERC PRC-019-2 Verification that generator voltage regulator controls and limit functions are coordinated with the generator’s capabilities and protective relays 1.1. Assuming the normal automatic voltage regulator control loop and steady-state system operating conditions, verify the following coordination items for each applicable Facility: 1.1.1. The in-service limiters are set to operate before the Protection System of the applicable Facility in order to avoid disconnecting the generator unnecessarily. 1.1.2. The applicable in-service Protection System devices are set to operate to isolate or de-energize equipment in order to limit the extent of damage when operating conditions exceed equipment capabilities or stability limits. 9 Excitation Limiters • • • • Over-Excitation Limiters (OEL) Under-Excitation Limiters (UEL) Over-Voltage (O/V) and V/Hz Stator Current Limiter (SCL) 10 Reactive Capability Coordination 50 Example: NERC PRC-019 Coordination OEL Rated Field SCL Stator Limit UEL PQ Monitor Trip Minimum Field 40 Zone 2 40 Zone 1 Rated PF 0.9 0.95 PF 40 30 20 Reactive Power (MVAr) Grid Codes may impose coordination of limiters, protection and capability and may also impose minimum reactive capability requirements. 10 0 -10 -20 Some types of limiters may be prohibited or may be mandatory (e.g. SCL) -30 -40 *example plot courtesy Kestrel Power Engineering. -50 Active Power (MW) 0 10 20 30 40 50 11 HV Grid Unit Breaker Main Transformer 24T Overview of Protective Devices PT Relays 40 Controls Limiters CT 21 59 32 24 Service Transformer Exciter ~ M Generator 51V 50 5IE M Auxiliary Loads M 12 Field Thermal Coordination Example: Provide shorttime capabilities specified in IEEE/ANSI 50.13 and continuous capability determined by either field current, armature current, or core-end heating. More restrictive limiting functions, such as steady state stability limiters, shall not be enabled without ISO approval. *example plot courtesy Kestrel Power Engineering. 13 V/Hz Coordination Example Coordination may include the excitation limiter, relays, the generator and other equipment, here the GST. Often equipment damage curves are not available and we instead refer to applicable protection standards *example plot courtesy KPE 14 Example UEL Curve For A Cylindrical Rotor Generator Reactive Power (pu) 0 LOE directional -0.2 UEL LOE -0.4 -0.6 0 0.2 0.4 0.6 0.8 Active Power (pu) 1.0 1.2 15 Example UEL Dynamic Response -0.2 Reactive Power (pu) UEL LOE -0.4 -0.6 -0.8 NO UEL 0 2 4 6 Time (seconds) 8 10 16 Example UEL Dynamic Response Generator Apparent Impedance X (pu) 0 -0.2 0 (start) 0.42 LOE directional -0.4 1.67 3.05 impedance -0.6 UEL LOE -0.8 -1.0 0.5 0.7 0.9 1.1 1.3 Generator Apparent Impedance R (pu) 1.5