Multi-vendor Experiences with IEC 61850 Installation, Testing
Transcription
Multi-vendor Experiences with IEC 61850 Installation, Testing
Multi-vendor Experiences with IEC 61850 Installation, Testing, Configuration, Diagnostics, and Upgrades David Dolezilek Schweitzer Engineering Laboratories, Inc. Copyright © SEL 2008 Practical Uses of IEC 61850 Protocols and Synchrophasors GOOSE in a Centralized Remedial Action Scheme (CRAS) GOOSE versus hard-wire protective trip RTU I/O collection via GOOSE Diagnostics tools for GOOSE “virtual wiring” Recent Global IEC 61850 installations Improving RAS with synchrophasors Remedial Action Schemes OOSESouthern California Edison (SCE) Tested Digital Communications Speed 13.3 13 Strive to mitigate thermal overload and instability throughout transmission territory RAS Round-Trip Detect Decide Trip Performance Criteria: Detect, Calculate, React 50 ms To / From any Location Test starts when Monitor detects Contact Input 1 Central Processor sends decision alarm Monitor chooses action to take Mitigator receives decision alarm Monitor sends monitor alarm Mitigator chooses action to take Central Processor receives monitor alarm Mitigator closes trip output contact Central Processor chooses action to take Monitor detects mitigation trip output as Monitor Contact Input 2 RAS enabled in Central Processor? Scope measures difference between Contact Input 1 and 2 Yes Initial Testing Verified Time Budget Using Three IEDs 740 Km Apart Next: Arming via SEL an Dell Computers Multiple Devices Demonstrated for WECC RAS Committee Within One Hour, Five New Devices Were “Digitally” Wired Typical: GOOSE Trip Tansit 1.50 msec Central Processing Time 2.083 msec Monitor is 60 miles distant. Mitigators are local to CP. Mitigation GOOSE transit, subscription, output - 3 msec or 11 msec Jim Bridger Power Plant Simultaneous, Independent Operation RAS C RAS D DNP Gateway DNP Gateway IEC Logic Controller IEC Logic Controller IEC Logic Controller IEC Logic Controller IEC Logic Controller IEC Logic Controller I/O Modules I/O Modules I/O Modules I/O Modules I/O Modules I/O Modules Input Input Input Input Voting Crosspoints Voting Output Voting Output Three Levels of Voting Jim Bridger Substation RAS Uses Crosspoint Switch f Trigger Inputs Crosspoint Switch Preloaded and Ready to Go CB Opens Output Remediation Contingency Trip G1 N1 N2 X N3 X Trip G2 Trip G3 X X Trip G4 Bypass C1 Bypass C2 X X X N4 N5 t X X X X X Tripping Outputs Designed to Handle Multiple, Closely Timed Events First Event Example1 Example 2 Time (s) t=0s N-Events System State t=5s IN1 IN6 N=1 N=20 S1 S1 IN6 N=6 S2 PacifiCorp / Idaho Power Remedial Action Scheme Eliminates Congestion Fastest control system in the world Stability improvements increase capacity 50%, avoid blackouts Training / Testing / Playback Simulator Test Simulator Plugged Into RAS C Protection-Class Features Deterministic, high-speed, peer-to-peer protocol used between RAS controllers No backplanes to fail No auxiliary power supplies MS Windows® NOT used in RAS controller All controllers embedded Identical logic in all six controllers Florida’s International Drive 1999 Project: Distribution Automation at Transmission Speeds Switching With a Recloser… Recloser + Control Without Communications Manual Switching = 1 hour Switching w/Recloser = 10 seconds …vs. Distribution at Transmission Speed SEL & S&C for International Drive SEL-351S + Communications Smart Switching = 0.1 second Multivendor IEC 61850 CFE Parque Eolico La Venta Existing Generators at Wind Farm Biggest Wind Farm Project in Mexico CFE expects to generate close to 3 GW by 2014 in “La Ventosa” Substation Expansion - New Generators SEL - MX060018 Project Satisfies Newest SICLE Design With IEC-61850 SICLE is Spanish Acronym for “Integrated System For Substation Local Control” CFE Specifies SICLE for integration of high voltage substations, SISCOPROMM for low voltage CFE Decided to Build Small but Meaningful Substation CFE wanted to prove 61850 was real Include as many vendors as possible Add other redundant IEDs in parallel Demonstrate true functionality on the network Prove multi-vendor interoperability Proven. Reliable. Complete. World’s First Multisupplier IEC 61850 System in Service Since 2006 “This is, without any doubt, a great advancement for the integration of control and protection systems, and for integration of the IEC 61850 International standard.” David Lancha, Project Manager, IBERINCO Wind Farm Under Construction La Venta II Substation Protection Requirements 87L 21PP 79 50BF 50BF 50BF 87B 51PHS RD 87T 51PHS 51NHS 51NLS Design #1 Used IEC 61850 Part 5, SEL Methods in IEDs, IEC 61850 in SCADA Gateway 230KV 230KV Line LVD93100 Autotransformer LVD92010 230KV Tie LVD97010 SEL-451-4 SEL-451-4 SEL-451-4 SEL-451 SEL-451 SEL-451 SEL-387E SEL-421 SEL-311L 230KV Bus Diff LVDDB9 Redundant HMI SEL-3351 Redundant SCADA Gateway SEL-3332 SEL-3332 SEL-487B SEL-3351 Information Processor Serves DNP/Conitel as SCADA Gateway and OPC to HMIs CFE Requested IEC 61850 in all IEDs SEL ACSELERATOR Architect – SEL-2411 – Automation Substation Configuration Language Controller SEL-751A – Feeders (SCL) Engineering Software SEL-710 – Motors SEL-3351 Rugged Computer SEL-421 – Distance SEL-451-4 – Bay Control SEL-311L – Current Differential SEL-387E – Transformers SEL-451 – Distribution SEL-487B – Buses Meet CFE Substation Protection Requirements Using IEC 61850 Conventional wiring and IEC 61850 GOOSE Test performance of conventional wiring vs. GOOSE for protection functions Determine if all relays will interoperate and perform as desired IEDs approved by CFE Design #2 Used IEC 61850 Part 8,9 in the IEDs IEC 61850 From SEL for Every Application in Bays 230KV 230KV Line LVD93100 Autotransformer LVD92010 230KV Tie LVD97010 SEL-451-4 SEL-451-4 SEL-451-4 SEL-451 SEL-451 SEL-451 SEL-387E SEL-421 SEL-311L 230KV Bus Diff LVDDB9 Redundant HMI SEL-3351 Redundant SCADA Gateway SEL-3332 SEL-3332 SEL-487B SEL-3351 Next CFE Chose to Demonstrate Multivendor Interoperability System integrates devices from multiple vendors SEL Siemens GE ZIV RuggedCom Team ARTECHE Other vendors invited but did not have IEC 61850 available or not approved by CFE Two Different Engineering Groups Working in Parallel to Integrate IEDs HMI LN reporting and bay level GOOSE IEC 61850 integration being done by Iberdrola SCADA Gateway LN reporting and station level GOOSE IEC 61850 integration being done by SEL New Products for CFE : Bay Control, SCADA Gateway, and IEC 61850 SEL Scope: Panel Design for Parque Eolico “Wind Farm” and Intertie Substation Design #3 Used IEC 61850 Part 8,9 in the IEDs Added IEC 61850 Devices From Other Vendors 230KV 230KV Line LVD93100 Autotransformer LVD92010 GE F650 BC 230KV Tie LVD97010 230KV Bus Diff LVDDB9 Redundant HMI Redundant SCADA Gateway ZIV BC SEL-451-4 ZIV HMI SEL-451 SEL-451 SEL-3332 SEL-451 ZIV CPT SEL-387E SEL-421 ZIV HMI GE T60 GE F60 GE F35 Siemens 7SJ62 Siemens 7SJ61 SEL-311L GE L90 SEL-487B Panels Ready for Installation System Architecture Remote HMI DNP ZIV CPT Conitel ZIV HMI ZIV HMI Router + Firewall SEL-3332 SCADA Gateway GPS SEL-487B 87B SW-1 SW-5 Fiber-Optic Ring RuggedCom SW-2 SW-4 SW-3 SEL-451-4 BC GE F650 BC ZIV 6MCV BC SEL-451 50BF, 25, 27 SEL-451 50BF, 25, 27 SEL-421 21, 67 SEL-387E SEL-279H 79 GE T60 87T SEL-451 50BF, 25, 27 GE F60 50, 51HS GE L90 87L GE F35 50, 51TZ SEL-311L Siemens 7SJ62 50, 51LS Siemens 7SJ61 50, 51N SEL Construction, Factory Acceptance Test (FAT), Training, Commissioning IEC 61850 SCL Replaces Wired Connections With Logical Connections GOOSE Messages for Protection CFE wanted to see performance comparison between wired and GOOSE CFE chose to test breaker failure protection scheme using GOOSE Primary protection trip Breaker failure relay retrip Breaker failure relay trip Breaker failure trip reception by bus differential relay Trip to all breakers in bus Customer Factory Acceptance Test GOOSE Retrip Operation 12.5ms Faster Than Parallel Hardwire at La Venta GOOSE Breaker 21 TRIP A Wired Contact Breaker 21 TRIP A 12.5 ms Difference Between Inputs 86FI Operation: GOOSE 8 ms Faster CFE Project Results Retrip test; GOOSE three-fourths cycle faster Breaker failure scheme; GOOSE half-cycle faster – wiring scheme still has to go through physical lockout (86) relay, which adds 6 to 8 ms Configuration and troubleshooting made simpler with sequential events recorder (SER) and event reports Traffic did not affect performance of SEL devices Project Engineering Revealed Necessary Communication Parameters Time synch method - chose SNTP Sacraficed accuracy to use Ethernet Changed back to IRIG later Number of client associations – chose 6 Two redundant HMIs Remote and local engineering workstations Two redundant SCADA gateways Interlock and Automation Projects Dictated GOOSE Requirements Number of outgoing GOOSE messages eight Number of incoming GOOSE messages - 16 Number of incoming GOOSE bits Bay control – 128 Relay –16, 128 depending on application Parque Eolico La Venta II PP&L Modernized From PLCs to IEDs Eliminate programmable devices Digital transducers PLCs Eliminate other components 24 Vdc supplies Interface relays External fault detectors Streamline, Reduce Complexity With IEC 61850 Design Reduce Hardware Components With IEC 61850 Design Design Computers Substation PLCs & Comm. Processor PLC 3 5 22 24 16 4 1 75 NGS 3 1 0 24 0 2 0 30 Bay PLCs Relays Metering IEDs Ethernet Switches SER Total Display Redundant Data Sources via HMI L2 P disagrees with other IEDs Faulty L2 P manually removed Using IEC 61850 Methods for RTU Replacement and Distributed Automation RTU Vendor Went AWOL No New Units, No Product Support Over 400 pad-mounted switchgear in service 50 to 100 new each year Three switch configurations controlling one to six circuit taps or “ways” Desire to simplify configuration, add engineering access, and improve logic Numerous I/O Configurations Must Fit in Fixed Small Space DNP3 serial over radio to SCADA Master changing to DNP3 / TCP in future RTU Real-Time Values via Internal and External Communications Connections RTU Replacement Network Could Also Connect I/O of Relays and Meters SCADA Master Example system database 192.168.0.20 PAC_MASTER DNP3 Serial Ethernet Switch 32 AC analog inputs 2 DC analog inputs 24 digital inputs 16 digital outputs GOOSE Messages PAC_Slave_A PAC_Slave_B PAC_Slave_C 192.168.0.15 192.168.0.25 192.168.0.30 Data Flow Acts the Same as Distributed RTU I/O Panels But Performs Better SCADA Master Field Inputs GOOSE Inputs DNP3 Response DNP3 Command Contact Output GOOSE Outputs Multi-vendor Configuration Requires Stand-Alone Tool Specifically for 61850 Alternate traditional UCA2 method of proprietary settings makes multivendor systems difficult Configure IED via International Standard Substation Configuration Language, SCL Start with IED capability description, ICD file Create configured IED description, CID file Edit only what you choose No accidental changes Minimize verification testing Load File in IED, or Send to Colleague Via email to Add Future IED Subscriptions “Best Practice” Provides Contextual Names – Generic Names Less Useful Generic Specific Best practice provides specific names whenever possible Exceptions include generic logic points, unnamed contact I/O Use Unique Name and Revision Control Ask IED Directly to Verify Present Configuration Solicit identification report from IED IED name reveals file name and revision ConfigVersion reveals default SCL file that configuration was developed with IED GOOSE Reports Are Essential Review receive and transmit configuration Quickly review network settings Analyze GOOSE statistics and diagnostics Immediately pinpoint source of problem Identification (ID) Reports Provide Source / Destination of “Virtual Wiring” Mismatched Configuration Explains Failure ID shows incorrect revision of PAC configuration Once corrected, GOOSE report shows correct revision as part of GOOSE reference name Analyze Contents With Knowledge of Configuration File Failed GOOSE, Other Alarms Displayed and Sent via Email, Voice, Text Message Cigre Multivendor System of 12 Vendor IEDs Support 8 Unique GOOSE Publications, 16 Subscriptions, 24 for Complex Interlocking SEL-451-4 SEL-421 ZIV IRV-A Team Arteche Toshiba GRZ100 Areva P444 Sisco software IED on PC GE D60 Siemens 7SA525 Siemens 6MD669 Siemens BC1703 GE F650 Second Generation Modernization Began in 2006 Complete modernization of 30 substations ranging in voltage level from 13.8 kV to 138 kV Elektro Network Includes IEC 61850, Telnet, FTP, and SEL Protocols Substations: Guarujá 2 – first modernized substation energized June 12 2007 – seven complete 2008 – eight complete Guarujá 2 Guarujá 3 Sao Paulo State, Brazil Fiber Optics Replace Copper KONYA Industrial Park Chooses SEL and IEC 61850 500 large to mid-size electricity-dependent tenants: plastics, machinery, pharmaceuticals Park management responsible for infrastructure: electricity, gas, water, traffic, security One 100 MW transformer and three 33 kV tie lines from National Grid 65 MW maximum demand increasing by 15% every year 8 Switching Stations, 99 Feeders SEL-3401 GPS-Clock 42-Inch LCD Monitors Server 1 Operator Station 1 Operator Station 2 Server 2 Printers Switch 3 Tie Lines (6 Future) Front-End 2 Substation Computing Front-End 1 Substation Computing SEL-2407 GPS-Receiver Clock 6 x SEL-311L Switch Station 1 Station 2 Station 3 Station 4 Station 5 Station 6 Station 7 54 SEL-751A Relays and 38 SEL-311L Relays Station 8 Control Center Manages 165 Distribution Substations 24 km redundant fiber-optic ring Future distribution automation additions Use Modern Communications for Diagnostics – FTP, Telnet, email GEESE Migrate to Africa Stations Include IEC 61850 MMS and GOOSE City Power Pennyville – 19 bays , 2 bus sections, 3 transformers City Power Khanyisa – similar to above with 36 bays City of Cape Town – 2 complete substations Nelson Mandela Bay Municipality Three new substations in 2008 Each based on IEC 61850 City Power Johannesburg Harley Street Substation Control Center IEC 60870-5-101 SEL-1102 SEL SEL-2410 SEL-2410 Switch Fdr 1 Switch Fdr 29 SEL-1102 Gateway, 2 SEL-2410s, 36 Bays With SEL-451 Relays Electricity of Vietnam (EVN) State-owned utility established 1995 Generation, transmission, and distribution for whole country 4 transmission companies 79,800 km of distribution lines Growing Electricity Demand Forecasted growth 17% per annum until 2025 600 500 Terawatt-Hours 400 300 200 Production 100 Sales 0 1995 2000 2005 2010 2015 2020 2025 First Phase – Substation Modernization Began in 1999 First computerized 220 kV substation commissioned in Ho Chi Minh City This success resulted in digitizing more substations through 2003 Early Substation Modernization Conventional protection and control using DNP3 serial and hardwired connections Problems with incompatibilities between multiple manufacturers’ IEDs Second Phase – Standardization To improve IED compatibility, EVN issued specification for substation automation based on UCA2 Based on this, first large-scale substation automation system (SAS) was implemented 220 kV Thu Duc Substation Upgraded Protection System Architecture 220 kV 66 kV Busbar Phase 1 Phase 3 Phase 2 220 kV 110 kV Phase 1 Phase 3 Phase 2 Third Phase – IEC 61850 IEC 61850 Part 10 approved Oct. 2005 EVN standardized for future projects – new and retrofit All 500 kV backbone substations upgraded by 2010 New System Requirements Dual redundant fiber-optic LAN with no single point of failure IEC 61850 for all substation communication IEC 60870-5-101 for SCADA Standard System Hardware Architecture Host 1 Engineering (Bridge to SCADA) Host 2 HIS Server Router to WAN Fiber-Optic Ethernet 100 Mbps LAN 1 LAN 2 Main NIM Backup NIM Main IED Backup IED GPS Clock Bay Cubicle Main IED Backup IED Main IED Backup IED Bay Devices Option 2 Bay Cubicle Bay Cubicle Bay Devices Bay Devices Option 1 Computerized Control and Monitoring Redundant system servers running on Windows® 2000 or Linux® Local HMI, engineering console, and historian Old Protection Panels Replaced Microprocessor-based relays perform protection, control, and monitoring Outdoor Cubicles Reduce Cabling Existing Copper Cabling Binh Long Substation Copper Cabling Reduced @STATION System Overview HMI1 HMI2 ENG HIS GW LAN / WAN IEC 61850 Meter Relays / BCUs Hardware Connections Primary Equipment Legacy Device Gateway Rugged Computing Platform SCADA Gateway Test Results User Interface Feature Required by EVN Tested Display Response Time <1s <1s Data Entry Response Time <1s <1s Display Update Rate <2s <2s Update Completion Rate <1s <1s Test Results User Interface Feature Alarm/Event Response Time Alarm Acknowledge/ Delete Time Report and Logbook Response Time Display Color Printout Response Time Required by EVN Tested <1s <1s <2s <2s < 0.5 min < 0.5 min < 0.5 min < 0.5 min Test Results Required by EVN Tested <2s <1s – <2s – <1s Failover Time Between Main 1 and Main 2 – 0s GOOSE Exchange Time < 10 ms < 8 ms User Interface Feature Console Inhibit Time for Display Hardcopy Analog Data Collection Rate Status Indication Collection Rate Benefits of IEC 61850 SAS Faster system integration with IED interoperability Reduction of copper cabling and hardwiring GOOSE for peer-to-peer data exchange Outdoor cubicles adjacent to feeder or bay System malfunctions reduced by nearly 50% What is a Synchrophasor? Time Waveform and Phasor Representation v(t) A 0 Reference wt A 2 Absolute Time Synchronization Has Fundamentally Changed the World Satellite GPS RCVR GPS RCVR IRIG-B PMU 1 A IRIG-B Mag/Ang Mag/Ang PMU 2 B Direct State Measurement SYNCHROPHASORS GPS provides common time reference Measure state vector Measure currents, too Synchronously! Every second Every cycle Synchrophasors Provide a “Snapshot” of the Power System P= |V1| |V2|sinФ / X V1∠0 Ф= sin-1(PX / |V1| |V2|) P→ V2 ∠Ф Increase Stable Power Transfer Relays Are Right for Synchrophasors Phasor measurement and control unit (PMCU) ≥ PMU Minimal incremental cost Reduced current and voltage connections High-accuracy measurements High reliability and availability Future control applications Relays are everywhere What Operators Did Not See Aug. 14th 64 Minutes Utilities Are Operating Closer to the Edge Margin Margin 1.0 Operating Point Bifurcation Point 0.5 0.0 PU Nominal Load 1.0 1.3 1.5 1.7 Long Island: Monitor Angles Between Transmission Distribution Buses to Detect & Prevent Voltage Collapse Vr V S 0 ZL = R + jX S=P+ jQ Smax 1 sin(θ) Vs 2 cos( θ)2 X 2 Apply Remote Synchronizing 230 kV Bus SEL-421 115 kV Bus 13.8 kV Bus SEL-421 Improved View: Synchroscope and Freq Plot make it easier for operators “The MRI of Power Systems” NERC press release on Florida outage Feb. 26, 2008: Synchrophasors are “Like the MRI of bulk power systems” SCE Uses C37.118 From Relays and PMU SCADA Master DNP3 Information Processor IEEE C37.118 Harris 5000/6000, IEC 60870-103, Modbus, SEL Fast Message, Telegyr 8979, Conitel 2020, CoDeSys, OPC, … Distributed Generation Creates Islanding Problems Transmission Network SEL-3378 DG Synchrophasors Detect and Correct Islanding Problems Defensive Strategies Working Group New York State Reliability Council NYSRC asked SEL to propose solutions Mitigate impact of major disturbances on the New York electric system Blackout mitigation and prevention Separate into “islands” using transmission system fault protection relays SEL Synchrophasor Total Potential Worldwide! Europe / Asia 4,115 units Canada North America 142,085 units Asia Pacific 45,793 units South America 15,903 units Africa / Middle East 5,085 units Real-World Example – Line Repair Error Detection Synchrophasors Make CFE’s Grid Smarter Relay-to-Relay Synchrophasors for Generator Shedding Load Shedding Based on Angle 400 kV Synchrophasors 400 kV Trip Generator 900 MW National System Chicoasen Sabino Angostura Tapachula City 400 kV 115 kV Network Southern Region Load Detect and Control Adaptive Islanding Transmission Network SEL-451 Relay / PMU SEL-3378 SVP Distribution Network Unintentional Islanding SEL-451 Relay / PMU Over Angle Protection Holds System Together Link 1 Area 1 Heavy Load Link 2 SEL-421 Synchrophasors Area 2 SEL-421 Trip Generation Area 3 Light Load (Chicoasen – Angostura) > 5° Trip Generation Today: Most Processing Is at the Master Master Finds topology Purges bad data Estimates state Asynchronous Scan RTU RTU ~5 seconds per scan . . . can have partial information from two or more physical systems – due to faults, switching, swinging, tap changes. One Utility’s View of Several Data Streams Bus Voltage Instantaneous Phase Angles Line MVA Frequency PMU ID Trended Phase Angles Local Calculation of Line Temperature Improves Power Transfer Reliability + + Line Temperature = f (Ambient Temp, Current, Line Orientation, Season) IEEE Synchrophasors Compatible With IEC 61850 Networks Possible Future GOOSE or 9-2 Extension IEEE C37.118, Telnet, tunneled serial Verify CT wiring, phase rotation, settings Determining the State of a Power System V2 V1 V3 V4 I231 I12 I34 I232 I12 V1 I V 231 Y 2 State Vector I232 V3 I V 34 4 Traditional RAS Clearing Time Budget Relay Relay Detects Fault -1 Cycle I/O Module Computer Relay Trips/ Asserts Contact Output 0 Cycle I/O Module RAS Controller Issues Gen Breaker Trip 1 Cycle Relay Relay Receives Trip Command and Trips Gen Breaker 2 Cycles Breaker Breaker Trip Time 3 Cycles Total RAS Clearing Time 6 Cycles SVP RAS Clearing Time ¾ Cycle Faster Improving RAS with Synchrophasors Direct state measurement is now practical because of the widespread availability of Synchrophasors The SVP performs local direct state measurement and control Wide area RAS schemes are improved because synchrophasors reduce the amount of information communicated to the master station What Does a Future “Worst-Case Scenario” Look Like? Detect potential unstable operating conditions Control islanding Detect system oscillation before criticality Minimize problems automatically Synchrophasors Empower the Future