Adaptive Protection for Microgrids

Transcription

1 1 Adaptive Protection for Microgrids Nikos Hatziargyriou, Vasilis Kleftakis, Vasileios Papaspiliotopoulos, George Korres Smart RUE: Smart grids Research Unit of the Electrical and Computer Engineering School of the National Technical University of Athens (NTUA) July, 2016 IEEE Power & Energy Society General Meeting 2016 Boston, United States

2 2 Presentation Outline Introduction Protection issues in distribution grids with DG penetration - Microgrids Adaptive Protection Systems Available Equipment in ICCS/NTUA Adaptive HIL implementation Hardware in the Loop experiments Hardware tests utilizing RTDS and SEL relays Evaluation of ICCS Adaptive Protection System

3 Introduction - Grid Operation Modes (3/4) Grid connected Mode 3 CB0, CB1 circuit breakers closed Two fault current sources Utility grid DG units

4 Introduction - Grid Operation Modes (4/4) Islanded Mode 4 CB0, CB1 circuit breakers opened One fault current source DG units: Fault current level depends on type, size and location of DG

5 Protection issues in distribution grids with DG 5

6 6 Protection issues in distribution grids with DG (1/7) Conventional distribution grids are radial and single point feeding networks, based on nondirectional overcurrent relaying for their protection. Each relay includes a group of pre-calculated settings based on short-circuit studies and no complicated issues are dealt with during the initial design. DG penetration in modern distribution networks causes significant increase of fault current level and partial contribution in short-circuit cases, resulting in maloperation of existing overcurrent protective devices (relays, reclosers, fuses). For this reason, the development and application of adaptive protection schemes, with adjustable setting groups, would guarantee safe operation for smart grids with DG and sophisticated topologies.

7 7 Protection issues in distribution grids with DG (2/7) Protection blinding (also called underreach) This phenomenon occurs when a large-scale conventional DG unit is connected to a distribution feeder between the main grid and the fault location. Grid fault contribution is reduced due to the partial contribution from the DG unit, and the feeder relay R1 senses a lower short-circuit current value. As a consequence, the relay cannot be asserted and clear the fault, suffering from blinding. HV GRID BUS MV I f,grid DG < I f,grid no DG BUS 1 BUS 2 R1 I f DG > I f no DG I f,dg DG1 LOAD1 LOAD2

8 8 Protection issues in distribution grids with DG (3/7) Sympathetic tripping In grid-connected operation mode, when a DG unit is connected to a specific feeder and a fault occurs on an adjacent one, the fault current contribution from the DG unit might exceed the pickup current setting of feeder s overcurrent relay, especially when DG capacity is sufficiently large. Therefore, the relay R1 trips sympathetically to relay R2. and the healthy feeder faces an unexpected outage. R1 HV GRID BUS MV DG1 R2 If,DG If,grid

9 9 Protection issues in distribution grids with DG (4/7) Bi-directional current flow In grid-connected and islanded operation mode, due to the presence of DG units, the power and fault current may flow bi-directionally. Impact to protection: Selectivity and coordination problem of traditional nondirectional overcurrent protective devices.

10 10 Protection issues in distribution grids with DG (5/7) Failed reclosing In grid-connected operation mode, the fault current detection capability of recloser is affected by the DG contribution. It concerns another aspect of protection blinding. Impact to protection: Failed reclosing.

11 11 Protection issues in distribution grids with DG (6/7) Insufficient fault current contribution In islanded operation mode, the fault current contribution from inverter-interfaced DG units is limited to about twice the rated current of the inverter. Impact to protection: Ineffective use of overcurrent protection. Insufficient fault current contribution could not reach overcurrent relay s pickup setting.

12 12 Protection issues in distribution grids with DG (7/7) Loss-of-mains protection The islanding phenomenon occurs when one or more non-utility generation sources and a portion of the distribution network still operate, while isolated from the remainder of the main system. The basic operating principles of islanding detection techniques are: The monitoring of main system and DG operating parameters The decision on whether there is an islanding situation or not, based on the parameter variations. MAIN SYSTEM BUS MV ISLANDING DETECTION OPEN CLOSED REMOTE TECHNIQUES LOCAL TECHNIQUES DG1 LOAD1 LOAD2 PASSIVE ACTIVE

13 Adaptive Protection Systems (1/3) 13

14 14 Adaptive Protection Systems (2/3) The use of adjustable protective relay settings that can change in real time (on-line), depending on the network configuration (topology, DG connection) changes, by using signals from local sensors or a central control system. Adaptive protection systems solve the protection issues mentioned in the previous section.

15 15 Adaptive Protection Systems (3/3) Adaptive protection systems are based on pre-calculated information where protection settings are updated periodically by the central controller with regard to the networks operating state. Technical requirements: Use of digital directional overcurrent relays (due to the bi-directional flow of short-circuit currents), Several setting groups must be encapsulated in digital overcurrent relays, Establishment of communication infrastructure and use of industrial communication protocols, e.g. Modbus, IEC 61850, DNP3 (necessity of communication between adjacent relays and individual relays with the central control system). Settings for non-directional or directional overcurrent relays are pre-calculated during off-line fault analysis of a given distribution network with DG, using power engineering software (Neplan, PSS/Viper, PowerFactory, ETAP).

16 Laboratory Infrastructure (1/4) 16 Real Time Digital Simulator (RTDS) RTDS Simulator is designed specifically to simulate electrical power systems & test physical equipment such as control and protection devices. RTDS is based on parallel processing. Each processor is assigned specific computing tasks depending on the network configuration. RSCAD software provides the ability to set up simulations, control, and modify system parameters during a simulation, data acquisition, and result analysis. RSCAD also includes libraries with a multitude of power system, control system and protection & automation component models, which can be used to create simulation cases.

17 Laboratory Infrastructure (2/4) 17 Digital Protective Relaying Panel SEL-311B (distance and reclosing relay) SEL-587 (differential/overcurrent relay) SEL-300G (generator relay) SEL-3354 (embedded automation computing platform) All relays have overcurrent elements with 2-6 setting groups, that will be used for adaptive protection implementation.

18 18 Laboratory Infrastructure (3/4) Protective Panel Hardware Components SEL 311B directional & overcurrent features SEL 300G directional & overcurrent features 67P/Q/G directional overcurrent element 50 51P/Q/G/N overcurrent elements 50 51/P/Q/G overcurrent elements 32 power directional element 79 Auto-reclosing element 2 Setting Groups 6 Setting Groups 6 Digital Inputs (220 V DC) 6 Digital Inputs (48 V DC) 7 Digital Outputs 7 Digital Outputs SEL 587 overcurrent features 2 groups of 50 51P/Q/N overcurrent elements 1 Setting Group 2 Digital Inputs (220 V DC) 4 Digital Outputs

19 Laboratory Infrastructure (4/4) 19 PLC SIMATIC S7 300 SIMATIC S7-300 universal controller is an integrated solution for industrial automation systems and is composed of: Power Supply (PS 307 2A ): V AC 24 V DC Central Processor Unit (CPU 312C) Signal Modules (SM): 10 Digital Inputs 6 Digital Outputs (10D.I. 6D.O.) hybrid card 8 Analog Inputs (8A.I.) card The desired automation schemes are programmed and downloaded to SIMATIC S7-300 by using STEP7 software and its programming languages: Ladder Diagram (LAD) Statement List (STL) Function Block Diagram (FBD)

20 Testbed Integration (1/4) 20 Components & Interfaces An innovative testbed infrastructure for adaptive protective schemes has been developed in the Electric Energy Systems Laboratory (EESL) of ICCS-NTUA. This specific testbed is actually a hardware-in-the-loop (HIL) topology, which consists of a Real Time Digital Simulator, two multifunction digital relays, and also a programmable logic controller (PLC).

21 Testbed Integration (2/4) 21 Operating Philosophy The examined distribution grid is simulated by means of the RTDS, while the digital relays undertake the supervision and protection of particular feeders. The SIMATIC S7-300 programmable logic controller is firstly responsible for the collection of the network circuit breaker statuses, and secondly for the relay transition to the proper setting group. Five setting groups are available and the setting values are pre-calculated according to each possible operational state of the examined distribution network. The RTDS also feeds the relay and the programmable controller with the on/off operation status of the grid components, such as distributed generation units, if any, network feeders and laterals and the main substation. The proposed logic ensures the proper adjustment of protective schemes considering every operational change, and thus can increase the dependability of distribution networks.

22 Hardware-In-the-Loop Tests Testbed Integration (3/4) 22 The HIL tests are conducted utilizing RTDS simulator as well as SEL-311B, and SEL-587 digital relays. SEL relays are fed with analog signals (voltages, currents) via their low-level interface.

23 Testbed Integration (4/4) 23 CONTROL UNIT REAL TIME DIGITAL SIMULATOR DIGITAL PROTECTIVE RELAYS

24 t op (s) Hardware in the Loop experiments (1/6) 24 The distribution system under examination is a simplified configuration of the Rhodes HV/MV Substation Gennadi and its outgoing feeders R-22 and R-26, which are protected by R3 and R7 protection relays, respectively. DG connection at Bus 1.1, symmetrical fault at Bus 1.2. R3 operating time increases from 0.55 s to 2.23 s => Protection blinding BUS 1.1 BUS 1.2 R3 L1 (5km) R4 R5 L2 (4km) R6 R EXTERNAL GRID BUS HV R1 TRA1 BUS MV R2 DG1 L5 (1km) BUS 2.1 BUS 2.2 R7 L3 (5km) R8 R9 L4 (4km) R10 R R3 (51P) CTR=800/5 IEC C2 (VI) A=13.5, B=1, C=0 Ipu = 3.38 A, TD = 0.12 X: Y: X: 2120 Y: DG I f (A)

25 Current (ka) Hardware in the Loop experiments (2/6) 25 3-phase fault at Bus 1.2 Total short-circuit current = 3,43 ka Short-circuit current through SEL-311B (main grid contribution) = 0,932 ka (primary) Time for fault clearance = 2,28 s RTDS oscillography IA Time (sec)

26 Hardware in the Loop experiments (3/6) 26 SEL-311B oscillography

27 t op (s) Hardware in the Loop experiments (4/6) 27 DG connection at Bus 1.1, symmetrical fault at Bus 2.1. R3 operates faster (0.38 s) than R7 (0.43 s) due to the DG contribution => Sympathetic tripping & outage of a healthy feeder BUS 1.1 BUS 1.2 R3 L1 (5km) R4 R5 L2 (4km) R6 R EXTERNAL GRID BUS HV R1 TRA1 BUS MV R2 DG1 L5 (1km) BUS 2.1 BUS 2.2 R7 L3 (5km) R8 R9 L4 (4km) R10 R12 DG R7 (51P) CTR=800/1 IEC C1 (SI) A=0.14, B=0.02, C=0 Ipu = 0.45 A, TD = 0.15 R3 (51P) CTR=800/5 IEC C2 (VI) A=13.5, B=1, C=0 Ipu = 2.06 A, TD = 0.10 X: 1510 Y: X: 3950 Y: I f (A)

28 Current (ka) 3-phase fault at Bus 2.1 Short-circuit current through SEL-311B (Feeder 1) = 1,51 ka (primary) Operating time = 400 ms Short-circuit current through SEL-587 (Feeder 2) = 3,95 ka (primary) Operating time = 551 ms RTDS oscillography (SEL-311B) Hardware in the Loop experiments (5/6) IA Time (sec)

29 Hardware in the Loop experiments (6/6) 29 SEL-311B oscillography

30 Evaluation of ICCS Adaptive Protection System (1/2) STAGE 1 30 The evaluation procedure is composed of three stages, as illustrated. INACTIVE ADAPTIVE LOGIC GRID MODE VARIATION SHORT-CIRCUIT SECONDARY TESTS In the first stage, the adaptive logic is inactive, and the prospect of protection blinding and sympathetic tripping incidents is confirmed, depending on the grid operating mode and the initial protection settings. Subsequently, the whole adaptive protection logic is put into effect, and the proper adjustment of relay setting groups to grid mode variations is validated. OUTCOME: OCCURRENCE OF PROTECTION BLINDING & SYMPATHETIC TRIPPING STAGE 2 ACTIVE ADAPTIVE LOGIC GRID MODE VARIATION OUTCOME: PROPER SETTING GROUP CHANGE Finally, in the third stage, the same short-circuit secondary tests as in the first stage are re-conducted, demonstrating that adaptive protection can address the arising DG impacts on distribution protection. STAGE 3 ACTIVE ADAPTIVE LOGIC GRID MODE VARIATION SHORT-CIRCUIT SECONDARY TESTS OUTCOME: ELIMINATION OF DG IMPACTS ON PROTECTION

31 Evaluation of ICCS Adaptive Protection System (2/2) Relay log file showing Setting Group transition in the proposed adaptive scheme Signal to activate Setting Group 2 Signal to deactivate Setting Group 1 Setting Group 2 activated Setting Group 1 deactivated Successful transition from SG1 to SG2 31 The determination of feeder relay setting groups (SGs) in the proposed adaptive protection system is formulated as a NLP optimization problem. For each possible configuration, distribution feeders are considered to be protected by directional overcurrent relays (DOCRs) with the associated SG enabled. The objective function aims at minimizing the aggregate operating time of both primary and backup DOCRs installed at the distribution network, subject to technical constraints imposed by DSO.

32 32 Thank you for your attention contact:

33 1 Protection design for microgrids Jean Wild

34 2 What is a microgrid? A local, interconnected energy system within physical boundaries (Department of Energy, USA) Incorporates loads & decentralized energy resources, including storage Multi-energy distribution or electricity-only management Grid-connected or off-grid mode A single entity with its own independent control in both modes Power range from several kw to several MW

35 Public / multiple users Single / private owner 3 Different applications, customers geographies and market dynamics Off-grid facility-led Grid-connected facility Off-grid Industrial sites (mining), remote hotels, Islands, rural zones, Campus, smart buildings, Eco districts, smart communities, Grid-tied Off-grid community-led Grid-connected community

36 4 Microgrid functional architecture a Energy network infrastructure that includes DER b Sensors, meters, and protection c Controls at the DER level d Controls at the microgrid level e SCADA to interface with microgrid operators f Cloud-based services such as tariff management, demand charge optimization, demand response, self consumption, CO 2 reduction, etc Microgrid functional architecture

37 5 Electrical engineering Microgrid technical & economic sizing Local flexible loads sizing, power supplies, including renewable sources and storage according to the microgrid power requirements. Load flow and voltage plan analysis Checks: voltage plan, equipment overload Recommend: transformer tap settings, reactive power compensation Example of load curves and decentralized energy production curves for a sunny islands

38 6 Electrical engineering Short circuit studies & discrimination study Thermal and dynamic current withstand Protection functions Protection and discrimination Dynamic stability Start-up and reacceleration of motors Stability of rotating machines and the network Fast automatic load shedding and source transfer mechanisms Switching on transformers and capacitors

39 Specific constraints for the protection strategy Association of local distributed generation, as well as the capability to island from the main grid, brings new constraints and new challenges for the protection system design Microgrids are characterized by different operating modes determined by the real-time production of distributed generation and the microgrid configuration: grid-connected or islanded Microgrid operating modes : on grid or off grid

40 8 Constraints for the protection strategy 1. The low short-circuit capacity: PV panels or wind turbines are usually coupled via inverters. Magnitude of the short-circuit current is limited nominal current. the short-circuit capacity is lower than from rotating machines. Traditional overcurrent protection philosophies may be compromised and other protection strategies should be defined. 2. The bi directional energy flow. 3. Micro grid operating conditions change the network topology also changes. the earthing system has to be set up in islanded Protection relays as to cope with connected and off grid mode.

41 9 Low short circuit capacity constraint The short-circuit current is low when there is no rotating machine nor grid Conventional protection systems based on simple over-current relays don t match Communication-based protection systems are possible but seems too complex (e.g. differential relays, ) More simple protection principle have to be set up combining current and voltage measurement

42 10 Bi directional energy flows In case of phase short circuit, the short circuit current is provided by several sources In the figure beside, relay 2 has to trip before relay 1 and 3 in order to avoid a black out for the load Bidirectional relays, with selective tripping according to fault current direction have to be set up.

43 11 Operating condition change Due to short circuit power difference, same protective relays have to cope with several protection schemes Earthing system in connected mode is often provided by the main grid. Therefore, once disconnected, the earthing system has to be internally reproduced within the microgrid For instance, A zig-zag transformer can be implemented within microgrid It is not just controls - modification of switching, grounding, and protection is needed. Modeling is generally needed.

44 12 Specificities related to power quality Power quality measurements have to be monitored, analyzed and kept in the normative range in particular: Harmonics Frequency variations Transients Voltage sags and swells Power quality measurements are key to assure microgrid control, reliability, and standard compliance

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