Grid-Forming BESS: Initialization, GFL/GFM Transitions & Microgrid Engineering

Part A — Grid-Forming BESS Transitions at a Glance

A microgrid can pass every steady-state check — load flow, short-circuit, voltage drop, power factor — and still fail when it matters most: in the first few cycles after the utility disappears or the battery changes control mode. A 13.8 kV grid-forming battery energy storage system (BESS) may look perfectly stable on paper. The real test is what happens when operating conditions change and the critical load is at stake.

Three engineering challenges decide whether a critical microgrid rides through those first cycles:

1. Initialization. Mismatches in voltage magnitude, phase angle or controller states between the network solution and the inverter controls create artificial transients at the start of a simulation — and real transients at the moment of a mode change in the field.
2. Control transitions. Grid-following (GFL) control regulates current and synchronizes with a phase-locked loop (PLL). Grid-forming (GFM) control creates its own voltage and frequency reference. Switching between them is not a software toggle; controller states, references and outputs must be handed over consistently.
3. Seamless transfer. In hospitals, data centers, water utilities and defense installations, a disturbance during islanding can drop process equipment, IT load or life-safety systems. Continuity depends on transfer logic, inverter current limits, protection and the wider power architecture working together.

What Keentel's simulations show

Keentel Engineering modeled a 13.8 kV critical microgrid: a 45 MVA BESS, a 30 MW plus 10 Mvar critical load, and a utility source with 250 MVA of short-circuit capacity. Before islanding, the BESS exports about 11 MW and the utility supplies the remaining 19 MW. The model is a three-phase average-value representation in the dq frame, including network inductance and capacitance dynamics, a droop-based GFM controller and a PLL-based GFL controller.

3. Initialization: eliminating artificial transients

3.1 Why initialization matters

An EMT simulation starts from an initial state of every inductor current, capacitor voltage, machine flux and controller state. If those states are not mutually consistent, the simulation spends its first cycles moving from the inconsistent starting point to a consistent one. That movement looks exactly like a physical transient: current spikes, voltage oscillations, frequency swings and, sometimes, protection or current-limit operation that changes the rest of the run.

Consistent initialization means:

1. a load flow solution at 60 Hz establishes bus voltages, angles and branch flows;
2. every network element is initialized to that phasor solution;
3. every controller is initialized so that its outputs reproduce the load flow injections, its integrators hold the values needed for zero error, and its filters hold their steady-state outputs;
4. the simulation starts with all derivatives near zero.

3.2 Initializing a grid-forming controller

For a GFM inverter connected through coupling impedance R + jX and delivering current I to a bus at voltage V from the load flow, the required internal voltage is:

The controller states are then set as follows:

3.3 Worked example: Keentel's 13.8 kV microgrid



Base quantities on 45 MVA and 13.8 kV:

With these states, the simulation starts in steady state: the inverter current stays at 0.25 pu from t = 0.

3.4 What a mismatch does

If the controller's internal angle is set 10° away from the correct value, the initial current error is approximately the voltage difference across the coupling reactance:

Combined with the 0.25 pu operating current, Keentel's simulation shows a peak of 1.23 pu. The sensitivity is nearly linear:

A real inverter's current limiter would clip these peaks, but clipping changes the controller's behavior and can trigger mode changes or protection that would not occur with correct initialization. A study that reports "current limiting during the first 100 ms" may be reporting nothing more than an initialization error.

3.5 Flat start and other initialization practices

A flat start — every state at zero and the sources ramped from zero — avoids inconsistent initial values by energizing the model gradually. It is robust but slow, and it does not represent the intended operating point until the model settles. In Keentel's flat-start case, the system reached the correct operating point after about 150 ms with a 1.22 pu voltage overshoot on the way. Flat start is acceptable when the simulation runs long enough to settle before any event, and when nothing in the model (such as protection or a current-limit latch) is triggered during settling.

3.6 Signs of an initialization problem

• Current, power or frequency excursions in the first few cycles with no event applied.
• Results that change when the event time is moved later.
• Current limiters or protection elements operating before any event.
• DC offsets in phase currents that decay with the network X/R time constant.
• Different results from different simulation time steps.

Keentel's practice is to run every model for a settling period with no events, confirm flat traces for all monitored quantities, and only then apply disturbances.

4. Control transitions: more than a software toggle

4.1 Why transitions occur

Many BESS installations operate in GFL mode when grid-connected — for historical reasons, because interconnection requirements were written for current-source behavior, or because the vendor's GFM mode is intended only for islanded operation — and switch to GFM when an island is detected. The transition can be:

4.2 What must be handed over



At the moment of transition, the GFM controller must start from the conditions the GFL controller and the network have created:

In Keentel's transition cases:

The choice of voltage ramp is a design trade-off: a faster ramp restores voltage sooner but draws more current to recharge network capacitance and re-magnetize loads. The best setting depends on the load's tolerance, the inverter's current margin and the presence of motors and transformers that will draw inrush current when voltage recovers.

4.3 Islanding detection delay

During the detection interval, the grid-following inverter cannot support the island. In the Keentel model, voltage falls to about 0.53 to 0.60 pu during that interval:

Islanding detection methods include breaker status from the point of interconnection (direct transfer trip or hardwired status), passive methods (voltage, frequency, rate of change of frequency, phase jump), active methods (impedance measurement, frequency shift) and communication-based schemes. Breaker-status signals are fastest and most reliable when the utility breaker is local; passive and active methods are slower and subject to non-detection zones when load and generation are balanced.



4.4 Critical-load tolerance

The ITIC (CBEMA) curve describes the voltage tolerance of typical information technology equipment:

In Keentel's model, the bus voltage during a 3-cycle detection interval is about 0.53 to 0.6 pu for about 50 ms. That falls outside the ITIC curve: equipment that just meets the curve may drop out. Only the grid-forming-before-islanding case keeps the critical load within the curve. Real data center loads behind UPS systems ride through such events on the UPS, but many process loads, variable frequency drives, control power supplies and contactors do not have that protection, and semiconductor fabrication tools are typically specified to SEMI F47, which allows 50% voltage for only 200 ms.

5. Seamless transfer: architectures that protect the critical load

5.1 Option 1: Grid-forming at all times

The BESS operates as a GFM voltage source while grid-connected, sharing load with the utility according to its droop and dispatch set points, and continues unchanged when the utility is lost. No transfer occurs, so there is no detection delay and no state handover. Keentel's simulation shows a voltage dip of less than one millisecond and a smooth transition to islanded frequency.

5.2 Option 2: GFL while grid-connected, fast bumpless transfer

The BESS operates in GFL mode, and a fast islanding detection signal triggers a bumpless GFM transfer. This can approach seamless performance when detection is fast (breaker status within a cycle) and the handover is carefully engineered, but some voltage disturbance during detection is unavoidable.

5.3 Option 3: Planned islanding only, with UPS or static switch for unplanned events

The microgrid islands intentionally — for example, ahead of forecast storms — with the BESS reducing the point-of-interconnection power flow to near zero before the breaker opens. Unplanned events are handled by UPS systems at the load or by a static transfer switch. This approach is common where the load already has UPS protection.

5.4 Option 4: Static switch at the point of interconnection

A thyristor-based static switch can separate the microgrid from the utility within a quarter to half cycle, much faster than a mechanical breaker. Combined with GFM operation, it minimizes the disturbance seen by critical loads during utility-side faults.

5.5 Selection

6. Inverter current limiting

6.1 Why GFM current limiting is difficult

A voltage source does not control its own current; the network does. During faults, motor starting, transformer energization or large load steps, a GFM inverter would deliver whatever current the network draws. Power semiconductors cannot tolerate overcurrent for more than milliseconds, so GFM inverters must limit current by control action, typically to 1.1 to 1.5 pu of rating. Methods include:

During current limiting, the GFM inverter is no longer an ideal voltage source, and its synchronization mechanism (droop or virtual inertia) may not see the true power imbalance. After the limit releases, the controller must recover synchronism without a second transient. These behaviors are vendor-specific and must be represented with vendor EMT models.

6.2 Worked example: current margin at islanding

In Keentel's microgrid, the BESS supplies 0.25 pu before islanding. At islanding it must instantly supply the whole critical load:

If the BESS were rated 30 MVA instead, the same load would be 1.05 pu — inside the current limit only in steady state, with no margin for transformer inrush, motor reacceleration or load restoration. A practical design rule is to size the GFM capacity so that the largest credible island load, plus the largest single motor-starting or transformer-energization step, remains within the inverter's short-time current capability.

6.3 Motor and transformer inrush

Induction motors draw five to seven times rated current when starting or reaccelerating after a voltage dip. Transformers draw magnetizing inrush of up to eight to twelve times rated current for their first cycles when energized. When an island is formed or voltage recovers after a transition, many motors reaccelerate together and transformers may be re-energized. The GFM inverter's current limit is then the bottleneck. Staged load pickup, soft starters and VFDs on large motors, and pre-insertion or point-on-wave energization for transformers keep inrush within the inverter's capability.

7. Frequency and voltage control in the island



7.1 Droop frequency deviation

With droop control, islanded frequency settles below nominal when the BESS supplies more than its set point:

In Keentel's model, mp = 0.02 pu/pu (2% droop) and the BESS picks up about 0.37 pu of additional power, giving Δf ≈ 0.02 × 0.37 × 60 ≈ 0.44 Hz, consistent with the simulated 59.55 Hz. Secondary control in the microgrid controller then restores frequency to 60 Hz over seconds by adjusting P*.

7.2 Multiple sources

When the island includes several GFM inverters, generators or combined heat and power units, droop settings determine load sharing:

Mismatched droops cause one unit to take most of a load step and reach its current limit first. Generator governors and inverter droops have very different response speeds, so the inverter takes the initial step even if steady-state sharing is balanced. Coordinated settings and EMT verification are essential.

7.3 Voltage regulation

Reactive power droop shares reactive load among sources but allows voltage to fall with reactive demand. In Keentel's model, islanded voltage settles at 0.96 pu. A microgrid controller's secondary voltage control or a voltage set point schedule returns the critical bus to nominal.

7.4 Reconnection

Before reclosing to the utility, the microgrid must synchronize. IEEE 1547-2018 specifies synchronization limits for DER; for aggregate ratings above 1,500 kVA, frequency difference must be within 0.1 Hz, voltage difference within 3% and phase angle difference within 10°. The microgrid controller adjusts frequency and voltage set points to meet these limits, then closes the point-of-interconnection breaker with a synchronism-check relay (ANSI 25) supervising. After reconnection, the BESS either remains GFM or transitions back to GFL, and that transition also requires bumpless handling.

7.5 Worked example: sharing a load step with a generator

An islanded campus has the 45 MVA BESS (2% droop) and a 20 MW gas generator (5% governor droop). A 6 MW chiller plant restarts.

In the first cycles, the BESS takes essentially all 6 MW, because the generator's governor and engine respond over seconds. The steady-state split then settles to about 85/15. If the design intent is for the generator to carry sustained load and the BESS to provide only transient support, the microgrid controller's secondary control must shift the BESS set point back toward zero and raise the generator's set point — and the EMT and dynamic studies must confirm that the handover does not create slow oscillations between the two sources.

7.6 Black start with a grid-forming BESS

A grid-forming BESS can black-start a microgrid without diesel generators. The main technical challenge is energizing transformers and cables within the inverter's current limit.

For example, a 13.8 kV campus with eight 3 MVA transformers totals 24 MVA of transformer capacity. If all were energized at full voltage, inrush of six to ten times rating could approach 150 to 240 MVA — far beyond the 45 MVA BESS's capability of about 54 MVA at 1.2 pu. A soft voltage ramp from zero reduces inrush to a small fraction of rated current, and the island then picks up load in stages. The microgrid controller sequence, breaker timing and the BESS's voltage ramp must be studied in EMT and verified during commissioning.

8. Protection coordination across operating modes

8.1 The fault current problem

Grid-connected, a 13.8 kV bus with 250 MVA of short-circuit capacity sees about:

Islanded, the 45 MVA BESS with a 1.2 pu current limit can supply only:

That is less than a quarter of the grid-connected fault current and comparable to the load current of large feeders. Time-overcurrent relays set for grid-connected coordination may never operate in the island, or may operate too slowly.



8.2 Adaptive protection strategies

8.3 Inverter fault response

Inverter fault current depends on control: some inverters inject balanced positive-sequence current only, others inject controlled negative-sequence current, and GFM inverters may produce sub-cycle peaks before current limiting acts. IEEE 2800-2022 now specifies negative-sequence current injection for transmission-connected IBRs, and similar expectations are emerging for distribution and microgrid applications. Protection studies must use vendor-specific EMT models to confirm relay operation for the inverter's actual fault response.

8.4 Grounding

A microgrid that is effectively grounded by the utility source may become ungrounded when islanded if the BESS step-up transformer is delta on the medium-voltage side. Ground faults in the island then produce little ground current and phase-to-ground overvoltage on unfaulted phases. Grounding transformers or wye-grounded transformer connections, with ground fault protection designed for the island, address this issue. NEC requirements for grounding of separately derived and interconnected systems apply.

9. Why EMT simulation matters

Positive-sequence RMS models are valuable for system-level studies of power flow, voltage regulation and frequency response, and modern grid-forming positive-sequence models extend their reach. Their assumptions — balanced fundamental-frequency phasors, simplified controls and network algebraic equations — limit their ability to capture:

• sub-cycle current peaks and current-limit behavior,
• PLL dynamics and loss of synchronism,
• controller state handover at transitions,
• unbalanced faults and negative-sequence behavior,
• transformer inrush and motor reacceleration,
• protection operation based on instantaneous quantities,
• interactions between inverters, filters and network resonances.

EMT simulation captures these directly, provided the network and control models have sufficient fidelity. Steady-state stability is only the beginning; the real test is what happens when operating modes change, control loops interact and current limits are reached.

9.1 Model fidelity requirements

9.2 Average-value versus switching models

Average-value models (AVMs) replace switching devices with controlled voltage sources that reproduce the fundamental-frequency output. They are fast and suitable for most system-level transition studies. Detailed switching models are needed for harmonic studies, switching-frequency resonance and some protection studies. Keentel's results in this article use an average-value representation; project-specific studies use the vendor's validated model.

10. US standards and requirements

Note that NFPA 99 and NFPA 110 impose specific requirements on emergency power for health care, including transfer times for life-safety branches; a BESS microgrid that supports those branches must satisfy them or be supplementary to compliant emergency generation.

11. A practical study and commissioning workflow

1. Define critical loads and their tolerance: ITIC, SEMI F47, UPS ride-through, motor contactor dropout.
2. Select architecture: GFM at all times, GFL with bumpless transfer, planned islanding, static switch.
3. Build the model: vendor EMT models for inverters, detailed transformers, loads, generators, protection and microgrid controller logic.
4. Initialize and verify: load flow initialization, settling period, flat traces before events.
5. Study transitions: planned and unplanned islanding at minimum and maximum load, different import and export conditions, different detection times.
6. Study disturbances in the island: faults, motor starting, transformer energization, load steps, loss of a generator.
7. Study reconnection: synchronization and transfer back.
8. Coordinate protection: settings groups, adaptive schemes, grounding.
9. Commission and test: factory acceptance testing of controls, controller hardware-in-the-loop (CHIL) testing of the microgrid controller with the plant model, site acceptance tests including live islanding where permitted.
10. Validate the model: compare field records with simulations; update models.

11.1 Controller hardware-in-the-loop testing

CHIL testing connects the actual microgrid controller — and sometimes actual inverter control boards — to a real-time simulation of the plant and network. It exposes timing, communication and logic errors that offline simulation cannot, and it allows unplanned islanding and fault cases to be tested safely before energization. IEEE 2030.8 provides a framework for microgrid controller testing that supports this approach.



12. Common misconceptions corrected

13. Key takeaways

1. Initialize every state from a load flow, and verify a quiet settling period before applying events.
2. Grid-following inverters cannot hold an island alone. A grid-forming source is required.
3. Transitions must be bumpless: align angle, voltage, power filters and integrators with measured conditions.
4. Detection time is load time at reduced voltage. Grid-forming before islanding avoids it.
5. Size grid-forming capacity for current, not just power, including inrush and load pickup.
6. Protection must work at a quarter of the fault current, using settings groups and current-independent schemes.
7. Use EMT with vendor models for transitions and protection, and validate with CHIL and field testing.

14. How Keentel Engineering helps

Keentel Engineering designs and studies microgrids, BESS interconnections and critical power systems for data centers, hospitals, water utilities, campuses and industrial facilities, from 480 V to 765 kV.

Why clients choose Keentel Engineering

• Control-aware engineering: we understand inverter controls as well as the network.
• EMT depth: detailed modeling of BESS, transformers, loads and protection.
• Critical facility experience: data center, hospital and water utility power architectures.
• Practical design: from studies to stamped drawings and commissioning support.
• Licensed professional engineering: a Florida-registered firm with offices in Tampa, Austin, Sacramento and Baltimore, supporting projects nationwide.

Planning a microgrid or grid-forming BESS for a critical facility? Talk to Keentel Engineering at (813) 389-7871, contact@keentelengineering.com, or book a 15-minute scoping call at calendly.com/keentel-engineering/15min.

Part C — Case Studies

The following are illustrative scenarios based on conditions typical of US critical microgrids. They show how Keentel Engineering approaches grid-forming BESS initialization and transition problems; site details are generalized and figures are rounded.

Case Study 1 — Hospital campus microgrid: equipment drops during transfer

Situation. A hospital campus with a 13.8 kV loop, a 20 MW BESS, combined heat and power and diesel generators commissions a microgrid. During the first planned islanding test, the transfer itself goes well, but during a later unplanned utility outage, imaging equipment, several air handlers and a sterilization process drop offline, even though the microgrid successfully forms an island.

Analysis. Keentel reviews event records and builds an EMT model with the vendor's inverter model and the microgrid controller's logic. The BESS operates in GFL mode when grid-connected and transfers to GFM after a passive islanding detection with a delay of about 8 cycles. During that interval, bus voltage sits near 0.6 pu, outside ITIC limits and below the dropout voltage of motor contactors. The transfer also resets the GFM power filters, causing a brief frequency excursion.

Engineered solution. Keentel recommends operating the BESS in GFM mode while grid-connected, with the utility's agreement under the site's intentional-island provisions, plus a hardwired breaker-status signal for the microgrid controller. Protection settings groups are revised for both modes. Life-safety branches remain on generator-backed automatic transfer switches compliant with NFPA 99 and NFPA 110.

Outcome. A subsequent unplanned outage passes with no equipment dropout, and the microgrid controller's logs show a voltage dip lasting less than one cycle.

Case Study 2 — AI data center campus: BESS bridging generator start

Situation. An AI data center campus at 34.5 kV with 13.8 kV distribution uses a large BESS to carry the campus during utility events while gas generators start. The design team's RMS study shows comfortable margins, but an EMT review is required by the owner before final design.

Analysis. Keentel's EMT study shows that the BESS's GFM current limit is reached during islanding because chiller motors reaccelerate and several 13.8 kV transformers re-magnetize together after the voltage dip from upstream utility faults. During current limiting, the inverters' synchronization behavior changes, and in some cases a second disturbance follows release of the limit. Island fault current is about one-fifth of grid-connected fault current, and several feeder relays would not operate in the island.

Engineered solution. Keentel recommends additional GFM capacity sized for reacceleration current, staged chiller restart through the building management system, adaptive relay settings groups, and bus differential protection on the main 13.8 kV switchgear. The inverter vendor provides a revised current-limiting setting validated in the EMT model.

Outcome. The revised design keeps inverter current within limits in all studied cases, relays operate correctly in both modes, and the owner proceeds with confidence in the campus's ride-through capability.

Case Study 3 — Water utility microgrid: when the model, not the plant, was unstable

Situation. A water utility's treatment plant microgrid study reports large current oscillations and repeated inverter current limiting immediately after every simulated islanding event, leading the design team to propose an expensive increase in BESS capacity.

Analysis. Keentel reviews the model and finds that the GFM controller was initialized with default angle and power filter states rather than from the load flow, and that the islanding event was applied only 50 ms after the simulation started, before the initialization transient had settled. The apparent instability was an initialization artifact superimposed on the islanding event.

Engineered solution. Keentel re-initializes the model from a consistent load flow, adds a two-second settling period before events, implements the vendor's actual transfer logic with state alignment, and repeats the study across load and import conditions.

Outcome. With consistent initialization, the islanding cases show peak currents well within the inverter's limits. The utility avoids the proposed capacity increase, and the corrected model becomes the basis for the controller hardware-in-the-loop test plan.

Part D — Technical FAQ: Grid-Forming BESS and Microgrid Transitions

References and Further Reading

Links were current at publication (October 2026).



• IEEE Std 1547-2018 and IEEE Std 1547.1-2020, Interconnection and Interoperability of Distributed Energy Resources and Conformance Test Procedures. IEEE.
• IEEE Std 2030.7-2017, Specification of Microgrid Controllers; IEEE Std 2030.8-2018, Testing of Microgrid Controllers; IEEE Std 2030.9-2019, Planning and Design of Microgrids. IEEE.
• IEEE Std 2800-2022, Interconnection and Interoperability of Inverter-Based Resources with Transmission Systems. IEEE.
• NFPA 70, National Electrical Code; NFPA 855, Installation of Stationary Energy Storage Systems; NFPA 99, Health Care Facilities Code; NFPA 110, Emergency and Standby Power Systems. National Fire Protection Association.
• UL 1741, UL 9540 and UL 9540A. UL Standards & Engagement.
• NERC, Grid Forming Technology: Bulk Power System Reliability Considerations, and related NERC guidance on grid-forming functional specifications. North American Electric Reliability Corporation.
• ITI (CBEMA) Curve Application Note. Information Technology Industry Council.
• SEMI F47, Specification for Semiconductor Processing Equipment Voltage Sag Immunity. SEMI.
• R. H. Lasseter et al., "Grid-Forming Inverters: A Critical Asset for the Power Grid," IEEE Journal of Emerging and Selected Topics in Power Electronics, 2020.
• Y. Lin et al., Research Roadmap on Grid-Forming Inverters, NREL Technical Report, 2020.
• UNIFI Consortium, Specifications for Grid-Forming Inverter-Based Resources.
  

Disclaimer

This article is general technical information for educational purposes. It is not engineering advice for any specific project and does not create a professional relationship. Simulation results come from Keentel Engineering's simplified average-value models with illustrative parameters; actual behavior depends on vendor-specific inverter controls, current limits, transformers, loads, protection and microgrid controller logic, and must be verified with validated vendor models, controller testing and field commissioning. Designs must follow current IEEE standards, the NEC, NFPA codes, utility interconnection requirements and project-specific engineering analysis, sealed by a licensed professional engineer where required.

Case studies are illustrative scenarios based on typical project conditions, not records of specific client projects. Figures are rounded and indicative.



IEEE, NERC, NFPA, UL, ITI, SEMI and other names are the property of their respective owners. Keentel Engineering is not affiliated with or endorsed by these organizations or any software or equipment vendor.