Source - Energiforsk 2023-957 Felbortkoppling i Mikronät (2023)

Energiforsk Report 2023:957 — Felbortkoppling i mikronät: Vägledning för utformning och inställning av felbortkopplingssystem i mikronät
(Fault clearing in microgrids: Guidance for design and settings of fault clearing systems in microgrids)
Authors: Arvid Björemark, Florin Stelea, Lars Messing, Johan Stelin (DNV Sweden AB)
Project lead: Johan Stelin (DNV Sweden AB)
Published: October 2023
Programme: Elnätens hållbara teknikutveckling och digitalisering (Energiforsk)
File: raw/PDF extractions/2023-957-felbortkoppling-i-mikrona-t/

Document metadata

• Type: Energiforsk industry guidance report
• Reference group: Arne Berlin (Vattenfall Eldistribution), Joel Clementson (E.ON Energidistribution), Öresundskraft, Jämtkraft Elnät, Skellefteå Kraft, Hitachi Energy Sweden, Jönköping Energi
• Programme board: Kristina Nilsson/Ellevio (chair), Vattenfall, Svk, Göteborg Energi, Jämtkraft, Elinorr, Öresundskraft, Skellefteå Kraft, Umeå Energi, Mälarenergi, Jönköping Energi, Nacka Energi, and ~15 more DSOs
• Funded by: 30+ Swedish DSOs and utilities including all major operators
• Scope: Protection system design for grid-connected microgrids that can operate in island mode (önätsdrift); AC microgrids only; excludes purely islanded networks and DC microgrids; excludes power/voltage balance (assumed to be handled separately)
• Primary source for Arholma section: Interview dated 2023-02-27 with Arne Berlin, Firas Daraiseh, and Yiming Wu (Vattenfall R&D) — conducted when Arholma FAT was complete but commissioning had not yet taken place

Summary

The report addresses a fundamental engineering challenge: protection systems designed for fault currents from synchronous generators do not work reliably when generation is inverter-based — as in any microgrid relying on solar, wind, or battery storage. The fundamental issue is that inverter-based DERs produce 1–1.5 p.u. fault current versus 4–7 p.u. from synchronous generators.

The report: (1) maps Swedish/EU regulatory requirements applicable to microgrids and identifies gaps; (2) characterizes fault current from each generation type; (3) documents protection system designs from three real microgrids (Simris/E.ON, Arholma/Vattenfall, Hailuoto/Finland); (4) evaluates all viable MV and LV protection solutions with pros/cons; and (5) proposes an innovative centralized protection architecture for future microgrids with few circuit breakers.

The intended audience is DSOs planning or operating microgrids in Sweden. The report is explicitly practice-oriented — each protection solution includes setting principles and applicability assessment for island mode.

Fault current from different source types

Key consequence: Phase overcurrent protection is typically unsuitable for inverter-dominated island operation. Directional, differential, and distance-based protection are preferred.

Missing sequence current: Inverter-based generators produce minimal negative sequence current at asymmetric faults unless the inverter control explicitly implements it. This breaks protection algorithms that use negative sequence to identify faulted phases. Germany mandates negative sequence injection (VDE-AR-N 4110/4120); Sweden does not.

Regulatory requirements applicable to microgrids

Swedish law and Elsäkerhetsverket

Ellagen 3 kap 1 § requires DSOs to ensure the grid is safe, reliable and efficient. Elsäkerhetsverket ELSÄK-FS 2022:1 specifies protection requirements including touching voltage (beröringsspänning) limits and fault clearing times. Elsäkerhetsverket makes no distinction between microgrid and conventional grid operation — the same requirements apply in both modes.

Network codes (RFG / EU 2016/631, EIFS 2018:2)

The requirements applicable to generators in microgrids depend on their installed power (type A–D classification). Key gaps identified:

ACER’s 2022 policy paper on RFG revision recommends harmonized type A requirements and investigation of BESS requirements — these recommendations have not yet been implemented.

Practical consequence: In a Swedish microgrid composed entirely of type A PV + BESS, the DSO cannot rely on any RFG-mandated protection behavior from the generation side. Every protection design must address the worst case of no negative sequence current and current-limited fault injection.

Case studies — protection system designs

E.ON Simris (LES pilot, Skåne)

Protection philosophy: All island generation is concentrated at one switchgear point (the BESS switchgear). This design choice fundamentally simplifies protection.

• Primary MV protection (island): Directional overcurrent protection on outgoing feeders from the main switchgear
• Backup: Second directional overcurrent protection at the BESS feeder
• LV faults (solar, wind): Protected by dedicated directional overcurrent on their feeder; BESS feeder as backup
• Ground faults: Zero-sequence voltage protection (nollpunktsspänningsskydd); sensitivity updated in island mode from 3 kΩ → 5 kΩ; non-selective — any MV ground fault in island mode blackouts the entire island
• BESS inverter oversizing: The BESS inverter was deliberately oversized to deliver 2× rated current for 2 seconds to ensure conventional overcurrent protection can detect fault currents. This is a design decision driven by protection requirements, not energy capacity needs.

Main limitation: Ground fault selectivity is not achieved in island mode — any MV ground fault causes total island shutdown. Distributed solar PV fault current contribution was considered negligible and not included in the protection design.

Vattenfall Arholma

Status at time of report: Information from interview on 2023-02-27 with Arne Berlin, Firas Daraiseh, and Yiming Wu (Vattenfall R&D). FAT had been completed at the supplier’s facility, but the equipment had not yet been delivered to Arholma. The system was commissioned in August 2023 per operational sources.

Protection requirements: Vattenfall’s criterion — “protection must not be worse in island mode than in grid-connected mode” — applies to both detection capability and expected disturbance frequency.

MV protection:

• Zero-sequence voltage protection with 3 kΩ sensitivity for MV ground faults; non-selective (any MV ground fault → island blackout)
• Relay settings updated automatically on island mode entry (requires communication)
• Multiple communication technologies being evaluated: 4G (mobile), IEC 61850, fiber optic

LV protection:

• Standard fuses where adequate fault current available
• Di/dt protection (ROCOC — rate-of-change-of-current) on battery terminals: detects high-resistance LV ground faults during island mode by measuring current rate-of-change at the battery connection point; verified through FAT tests using various scenarios
• Economic constraint: some LV substations not modernized → those LV faults are detected and cleared via MV-side protection (cascaded clearing, not selective)

APRS (Adaptive Power Restoration System): Vattenfall has procured APRS for Arholma — advanced logic for automated network reconfiguration after fault isolation. After a fault is cleared and the faulted segment is isolated (via remotely operated disconnectors in de-energized state), APRS identifies safe reconfiguration options by performing load flow analysis, checks for overload or voltage deviation risk, and either executes reconfiguration automatically or provides decision support for operators. This is a separate system from the fault detection/clearing relay protection — it acts after the primary fault clearing step.

Main challenges identified: System balance (frequency/voltage control in island mode) was assessed as the larger challenge. No technical obstacles for fault detection/clearing were found, but economic constraints led to some MV-only LV fault clearing as noted above. Larger equipment vendors were reluctant to participate in the pilot due to perceived project risk.

Hailuoto, Finland (comparator)

Hailuoto island (1,000 permanent residents + ~600 summer cottages); 21 km 20 kV radial; generation: 0.5 MW direct-connected induction wind generator + 1.5 MW diesel generator. ABB pilot project.

Key approach: Adaptive protection with multiple setting groups — when island mode is entered, a central controller signals all protection relays via IEC 61850 to switch to a pre-configured island mode parameter set. This resolves the switching of neutral voltage protection timing, overcurrent thresholds, etc., without replacing hardware.

Advantage over Simris/Arholma approach: Having a synchronous diesel generator means Hailuoto has substantial fault current in island mode — conventional overcurrent protection is viable with adapted settings. The Simris/Arholma situation (pure inverter-based island) is more constrained.

MV protection solutions evaluated

Ground fault solutions for MV networks

Note on Arholma and Simris: Both use non-selective ground fault clearing (zero-sequence voltage protection) in island mode. For small islands with few customers, this is acceptable — any ground fault triggers investigation and repair before reconnection.

LV fault considerations

In grid-connected mode, LV fault currents are determined primarily by transformer reactance. In island mode, the available fault current may drop below safety and protection thresholds. Analysis must be done case by case.

The report recommends:

1. LV faults should be detected and cleared on the LV side where possible
2. Where adequate fault current cannot be guaranteed in island mode, specify a minimum BESS state-of-charge at island entry (BESS contributes short-circuit power via its inverter up to ~1–1.5 p.u.)
3. Verify all fuse clearing times at minimum available fault current in island mode
4. Complementary undervoltage protection can assist clearing

Communication requirements for protection

Wired communication (fiber optic or PLC) is preferred for protection functions due to timing requirements. Wireless (4G/5G, Wi-Fi, Zigbee) is acceptable for non-time-critical functions (apparatus control, monitoring, non-urgent switching). IEC 61850 is the recommended protocol for protection communication between substations and central units.

Conclusions and recommended next steps

1. No single protection solution is universally best — topology, generation type, number of circuit breakers, and economic constraints all determine the appropriate solution for each microgrid.
2. Same protection requirements should apply in island mode as grid-connected mode, but ground fault selectivity requirements may be relaxed case by case.
3. Regulatory harmonization needed: Type A generator requirements should include fault ride-through and fast fault current injection; BESS should have corresponding requirements; negative sequence injection should be investigated for Swedish mandate (as Germany has done).
4. Communication is non-negotiable for island protection: relay settings must update on island mode entry, and wired links are required for time-critical functions.
5. Follow-on study recommended: Case studies applying different protection solutions to Arholma and Simris theoretically or practically (with signal-only relays, not connected to trip circuits).

Relevance to existing wiki pages