Smart Substations in MEA s Distribution System. Pichit Jintagosonwit

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1 Smart Substations in MEA s Distribution System Pichit Jintagosonwit

2 Smart Grid Electrical Infrastructure + Intelligence Infrastructure Uses information technologies to improve how electricity travels from power plants to consumers Allows consumers to interact with the grid Integrates new and improved technologies into the operation of the grid resulting in new services and functions

3 MEA s Smart Grid Objectives Power System Enhance reliability of the existing grid Improve efficiency of MEA power system Services Create opportunities for new services Enable active participation by consumers Energy Saving and Renewable Energy Promote energy saving and integration of renewable energy resources Support new technologies i.e., electric Vehicle-to-Grid (V2G)

4 MEA s Smart Grid Roadmap Stage Laying the Foundations Stage Large Scale Implementation Stage Ultimate Stage Implement Substation Automation based on IEC61850 for existing substations 40 substations 100 substations 100% (approx. 170 substations) Power System Implement Distribution Management System 30% of service area 60% of service area 100% of service area Employ outage monitoring system in HV and MV Initiate self-healing capability in HV and MV for some areas. Extend outage monitoring system to LV Expand self-healing capability in HV and MV to cover the entire service area Implement asset management to reduce operation and maintenance costs

5 Smarter Substation Substation + The Latest Information Technologies Focusing on secondary devices (protective relay, CT/PT) commonly called IEDs (Intelligence Electronic Device). Layer-3 Ethernet switches and TCP/IP (instead of serial comm.) IEC61850 (Trend of application protocol). Substation applications have to utilize real-time information as much as possible. The old smart substation s applications normally use only DI/DO and can not utilize AI which maybe required for very fast decision such as 3-bays BTO.

6 IEC61850 Messaging (1)

7 IEC61850 Messaging (2)

8 3-Bays BTO Function (1) Subtation Termainal Station Bays-BTO Auto Termainal Station 2 L1 L2 Bus A DS1A BCA DS2A BC Bus B DS1B BCB DS2B Do not Close due to Tr.2 may be overload

9 3-Bays BTO Function (2) Subtation Termainal Station Bays-BTO Auto Termainal Station 2 L1 4 L2 Bus A DS1A BCA DS2A BC Bus B DS1B BCB DS2B

10 Smart Substation for Smart Grid Because of TCP/IP, Switch, IEC61850 technologies Supporting future grid applications in scale of baylevel response time (4ms by native GOOSE, super fast for grid level) by using VLAN across WAN. GOOSE/UDP is coming for across network via gateways /firewalls. Making us can share communication infrastructure such as fiber-optic cores. For Example,in the past, we had to use dedicated cores and PLCs for LTF (Line Transfer Function between substations)

11 LTF (1) Inline Substation Open-loop Substation Managed Switch IP Network Managed Switch IED with LTF function IED with LTF function

12 LTF (2) 1 From Terminal Station 1 Inline Substation Auto Open-loop Substation From Terminal Station 2 27 Trip 27 2 Delay of 0.2 Sec L1-A 3 L2-A L1-B L2-B 4 DS1-B DS2-B DS1A-A BCA-A DS2A-A DS-B BC-A DS2B-A BCB-A DS2B-A

13 Consolidation Concept Smart Substation > Substation Automation SCADA HMI CCU#1 CCU#2 Station Gateway TDS Station bus Protective Relay BCU Protection & Control Protection & Control Protection & Control Bay control Bay control Processinterface Processinterface Processinterface

14 Engineeri ng Portable MMI Station Computers CCU#1 CCU#2 HMI Typical System Topology DCC Gatewa y With Firewall (CGW) GPS TDS Station Level Switch Switch Line Bay Trans. Bay BS/BC. Bay Line Bay Trans. Bay Switch Switch Switch Switch Switch LAN B Main 21/21N, 27/59, 79, 50BF 67/67N, 27/59 50BF+ BCU Main 87 50/51, 50/51N, 50BF+B CU 115/69kV 50/51, 50/51N, 50BF+B CU LAN A Main 21/21N, 27/59,7 9,50BF 67/67N, 27/59 50BF+ BCU Main 87 50/51, 50/51N, 50BF+B CU Bay Level 14

15 Substation Automation (SA)

16 Substation Automation (SA) SICAM PAS Station Unit Station-LAN: IEC 61850; Ethernet 100 Mbps Fibre Optic Double Loop with redundancy function 7UT61 (87T) SJ61 (50/51) SJ61 (50BF) SA52 (21/21N) SD61 (87L) SJ61 (50BF) SJ61 (50/51) SJ61 (50BF) kv Switchgear Power Transformer No.1 Line Incoming No.1 Bus Coupler 7UT61 (87T) SJ61 (50/51) SJ61 (50BF) UT61 (87T) SJ61 (50/51) SJ61 (50BF) SA52 (21/21N) SD61 (87L) SJ61 (50BF) kv Switchgear Power Transformer No.2 Power Transformer No.3 Line Incoming No.2

17 SA Physical Allocation 2 Station Computers 2 Man Machine Interface Servers 2 Operator Man Machine Interface (HMI) Engineering Work Station and Fault Evaluation System Communication Gateway (CGW) Time and Date Server (TDS) Station LAN Ethernet Switches Main and Backup Protection Relay (87L, 21, 87B, 87T, 67, 50/51, ) Backup Protection (Breaker Failure Protection : 50BF) Bay Control Unit (BCU) Process Level Conventional Type CT/VT Conventional Hardwire Connection

18 Process Level: Hard Wiring

19 SA Functions (1) HMI and Related Station Level Operator or Control Functions Monitoring and Measurement Protection (Main and Backup) Line : 87L,21,67, 50BF, Busbar : 87B (Low impedance) Transformer : 87, 50/51, 50/51N, 50BF Feeder : 50/51, 50/51N, 50BF

20 SA Functions (2) Automatic Functions High Speed Automatic Transfer Scheme Voltage Selection Automatic Load Shedding Automatic Load Restoration Interlocking Breaker Failure Protection Rate-of-Change Calculations and Alarming for Selected Analog Input Variables Heartbeat Function Maintenance of TRIP Counters for Breakers Breaker Operating Time Checks

21 SA Functions (3) Local/Remote Control and Monitor Voltage and Var Control Trend Records Events, Alarm and Disturbance Records Fault Location

22 Implementation of SA Chidlom Terminal Station Substation Automation Systems Base on IEC Energized on May 09,

23 Indoor Type Substation Chidlom Terminal Station Building 23

24 Primary Equipment : 230kV GIS 24

25 Transformer : 300 MVA 25

28 Mimic Board and HMI 28

29 Station Computers Station Computers 2 Station Computers 2 Man Machine Interface Servers 2 Operator Man Machine Interface (MMI) Engineering Work Station Communication Gateway (CGW) Time and Date Server (TDS) Station LAN Ethernet Switches 29

30 Bay Level : Relay & BCU Panel 30

31 IEC61850 Experiences SCADA HMI CCU#1 Our protective relay handles automatic, control, interlocking, metering and protection functions, but actually any protective relay has its limitation and also differ from other vendors. e.g. logic-gate capacity, processing time and functionalities giving us several difficulties and deviations from our technical specification. Protection & Control Protection & Control CCU#2 Protection & Control Station Gateway TDS The main point is that we have to require specific protective Station relays bus for sparing due to it is almost impossible for replacing by othervendor in no time. Protection & Control Protection & Control Processinterface Processinterface Processinterface

32 IEC61850 Experiences To maintain SA as easy as possible easily changing a relay with the minimal time. easily procuring a relay as spare from multi-vendors. needing the minimal number of maintenance guys and knowledge for maintaining. Purposed Solutions allocating the fewest functions to each device as much as possible. purchasing size of a relay as small as possible. More bigger more difference of capabilities among vendors such as a number of reports, a number of logic gates, a number of CSWI, number of physical I/O. Consequently, in the case of the full capacity implementation of a relay, It may not be able to put all same functions of the relay to other relay of other vendor resulting in maintenance difficulties. Preparing function compatible list (FCL) including configuration files for purchasing any spare relays

33 Function Compatible List (1) Station Level A B C A B C A B C A B C Bay Level

34 Function Compatible List (2) Station Level A B Main Function Main Function Main Function C A B C A B C A B C Sub Function Sub Function Sub Function Bay Level

35 Number of Physical I/Os Misunderstanding, proposed protective relays from a contractor may have not enough physical I/Os to support protection schemes with high reliability resulting in changing new protective relays and causing a project delay. During issue of the technical specification, MEA has found that one of the most important points is to specify minimal number of physical I/O of any protective relay to support the required functionality making bidders have the clearest view of what protective relays be proposed to MEA. Figure 2 shows two solutions that can do same functions, but they have different reliability level from serial and parallel arrangements. Main Protection Main Protection Back-up Protection Equipment Status by GOOSE Back-up Protection Equipment Status by Hardwiring Equipment Status by Hardwiring

36 Sim Box During the installation process of the SA devices in an existing substation, all the automatic, control and metering functions have to be tested to assure correct functioning when put in services. Due to shutdown time may be not long enough or difficult to fully perform all equipment tests causing project delay. Consequently, MEA has to use plant simulation boxes acting as substation equipments for testing all functions shown as Figure 4. Therefore the needed shutdown time of such substation is as short as the required time for checking equipment connections whether are correct Switchgear still is on service New Control Cable Plant Simulation Box

37 Benefits (1) Standardization Natural Resources Reduction with Modern Networking Technology Cost Reduction More Vender Competition More Intelligence Functions One Time Investment Commissioning and Maintenance Time Saving 37

38 Benefits (2) Open System Architecture Spare Parts Availability Future Extension Convenience Information support for system planning and system analysis Fully Automated Substation System Stability and Reliability for MEA Network Services Smart Substation to Support MEA future Smart Grid Project 38

39 Thank you for your attention.