Frequency Containment Reserve (FCR) for BESS: Sizing, Revenue & Degradation
Grid frequency must stay close to its normal value at all times. This holds true whether the source is a coal plant, a wind farm, or a battery. Frequency Containment Reserve (FCR) is the automatic response that holds this balance across all of them.
So when power supply and demand drift apart, FCR assets react within seconds. Battery energy storage systems have become top Frequency Containment Reserve providers. They respond faster than almost any other technology on the grid.
| Quick Answer Frequency Containment Reserve (FCR) is the fastest layer of grid balancing. It restores the power balance within 30 seconds of a frequency drop or spike. Batteries sense frequency locally and respond in milliseconds. Operators earn a steady payment for staying ready, whether the reserve activates or not. |
What Is Frequency Containment Reserve (FCR)?
FCR is the first line of defense against grid frequency swings. European rules define Frequency Containment Reserve as the active power reserve that contains frequency right after an imbalance hits.
FCR is also called primary reserve. In Germany, people call it Primärregelleistung.
But it does not push frequency all the way back to 50 Hz. It only stops the drift. It buys time. Then, slower reserves step in and finish the job.
Primary, Secondary, and Tertiary Control
Grid operators stack three response types on top of each other. First, Frequency Containment Reserve acts, and it acts fastest of the three.
Next comes Frequency Restoration Reserve (FRR). It responds between 30 seconds and 12.5 minutes after an event. Finally, manual reserves close out the recovery over the following minutes.
Frequency Containment Reserve 30-Second Response Window
Frequency Containment Reserve assets must adjust their output based on the size of the frequency deviation. In Continental Europe, full activation kicks in once the deviation hits 200 mHz.
At that point, the asset has 30 seconds to deliver its full contracted capacity. So once activated, it must hold that output for 15 to 30 minutes, depending on the region.
Suppliers measure frequency locally, right at the point of generation or use. Because of this, the response runs on its own. No signal from the grid operator is needed first.
The Deadband
A small deadband sits around normal frequency. In the Continental Europe FCR market, this band runs from 49.99 Hz to 50.01 Hz.
Inside the deadband, no response is required. Outside it, however, providers must deliver the volume they promised.
FCR-N vs. FCR-D: The Nordic Split
Nordic countries split Frequency Containment Reserve into two separate products. FCR-N covers normal, everyday swings within about ±0.1 Hz.
FCR-D, on the other hand, covers bigger disturbances that fall outside that range. This split allows finer control across two very different event types.
So, FCR-N assets cycle often, but only shallowly. FCR-D assets sit idle most of the time. Then they respond hard during rare, larger events.
Battery duty cycles differ sharply between the two products. Because of this, the gap matters for sizing and for degradation planning.
Why Batteries Excel at Frequency Containment Reserve
Batteries hold a clear edge over generators for FCR duty. A power electronics-based asset can shift from zero to full output in milliseconds.
A generator, in contrast, needs several seconds just to change its governor setpoint. That gap matters, since FCR is a symmetric product.
Providers must move power in both directions, up and down, from the same asset. A battery handles this cleanly. It still needs a dedicated state-of-charge controller to stay ready on both sides at once.
So, FCR has become one of the strongest early revenue streams for grid-scale batteries. It often beats secondary and tertiary reserve markets on a per-megawatt basis. That is part of why so many storage developers target it first.
Market Structure and Revenue
Frequency Containment Reserve is sold as a capacity product, not an energy product. Providers get paid a set price per megawatt for the tender period.
That payment applies whether the reserve activates once, many times, or not at all. The common European group, for example, runs daily auctions for the next delivery day.
Since a 2024 reform, blocks can be sold in 30-minute chunks instead of longer windows. This shorter block length gives battery operators more scheduling freedom. So operators can now combine FCR with other revenue streams across the same day.
Prequalification Requirements
A battery cannot bid into FCR without passing prequalification tests first. The grid operator checks response speed, accuracy, and sustained delivery through a formal test sequence.
A passed test typically qualifies a unit for up to five years before retesting. The full process, however, commonly takes three to six months, from application to approval.
So, Sunlith recommends starting this process well ahead of commercial operation, because delays here push back revenue directly.
Battery Wear Under Frequency Containment Reserve Duty Cycles
FCR asks a battery to cycle constantly. The bursts are small and frequent. They track real-time frequency noise.
This pattern differs sharply from the large, planned cycles used in energy trading. Researchers describe this cycling as path-dependent: wear depends on the exact charge and discharge order, not just total energy moved.
Newer wear models built for BESS now account for FCR duty directly. They also cover peak shaving and solar profiles in the same framework.
These models weigh heat, current rate, discharge depth, and charge level together. So they no longer look at each stress factor alone.
Keeping Charge Level Balanced
An FCR asset must stay ready to respond in both directions at all times. A battery pinned near full charge, for instance, cannot absorb more energy.
A battery pinned near empty cannot deliver more power either. Either state risks a penalty from the grid operator.
So a dedicated recharge controller keeps the battery centered in its usable range. This controller balances two costs against each other. Aggressive recentering adds extra cycles of its own, so the trade-off needs care.
FCR vs. aFRR vs. mFRR
| Reserve | Response Time | Duration | Payment Type |
| FCR | Within 30 seconds | 15–30 minutes | Capacity only |
| aFRR | Seconds to minutes | Up to 15 minutes | Capacity and activation |
| mFRR | Up to 15 minutes | Longer sustained periods | Capacity and activation |
Frequency Containment Reserve asks the least of an asset in energy content. But it asks the most in speed and cycling frequency. This mix is why lithium iron phosphate batteries fit the service so well.
Sizing a Battery for Frequency Containment Reserve (FCR)
Sizing starts with headroom, not raw capacity. The system needs enough usable energy for a full-power event across the required duration.
It also needs margin for charge-level recovery between events. Power electronics matter just as much as cell chemistry here. A weak inverter design can bottleneck an otherwise well-sized battery.
The inverter and battery management system must both support fast, frequent switching. Because of this, they need extra thermal design margin, so they can do it without adding excess heat.
Also, pairing Frequency Containment Reserve with a second revenue stream, like energy trading, often helps. It can offset the wear from constant small cycling and improve project economics overall.
Frequency Containment Reserve (FCR) Outside Europe
Frequency response services exist well beyond the European FCR framework, even where the acronym differs. In the United States, regional grid operators like PJM and CAISO run their own fast-frequency-regulation markets with comparable speed requirements.
Australia’s FCAS framework and the UK’s Dynamic Containment product both serve the same core purpose. They ask batteries to hold grid frequency steady within seconds. Contract terms and payment structures still vary by market.
A developer targeting FCR revenue in one region should still study the local prequalification rules closely. Response-time thresholds, penalty structures, and settlement periods differ enough between markets. A design built for one grid code rarely transfers directly to another.
FAQ
What is the difference between FCR and frequency response?
FCR is one specific type of frequency response, defined under European grid codes. Other regions use different names and slightly different rules for similar fast-acting services.
How much can a BESS earn from FCR?
Revenue depends on the local capacity price and the size of the contracted block. FCR pays as a capacity product, so income tends to be steadier than pure trading revenue.
Does this service wear batteries faster than energy trading?
FCR causes many small, shallow cycles instead of fewer deep ones. The real impact depends on charge-level management and heat control, not on cycle count alone.
What size BESS is needed for FCR?
Sizing depends on the contracted capacity, the required delivery duration, and the margin needed for charge-level recovery between events.
Further Reading
Partial-SOC Cycling and Recalibration Scheduling for LFP BESS
Frequency regulation, peak shaving, and other grid-services duty cycles keep a BESS cycling between roughly 20% and 80% state of charge. That partial-SOC band protects LFP cells from deep-discharge stress. But it also means the estimator rarely sees a true 0% or 100% anchor point. Recalibration scheduling is the deliberate plan for correcting SOC drift when the operating profile itself won’t do it for you.
| Quick Answer Grid-services BESS rarely touch 0% or 100% SOC, so the anchor points that reset Coulomb-counting drift never occur naturally. Recalibration scheduling forces periodic full-range excursions, or substitutes softer in-band anchors, to correct that drift on a set cadence without giving up cycling revenue. |
Why This Needs a Scheduling Plan, Not Just an Anchor Point
Coulomb counting drift and the anchor-point fix are covered in depth in The 20/80 Rule for Batteries: an open-circuit voltage reading at a true 0% or 100% SOC resets the estimator and prevents error from accumulating.
So, the short version: a grid-services BESS often can’t count on that reset happening naturally. A frequency-regulation asset can spend months inside a 20-80% band, since the estimator has nothing to reset against until something schedules a true excursion. This article picks up from there, building the actual recalibration scheduling logic. See our guide to EKF SOC estimation design for how the underlying estimator works.
Soft Anchors vs. True Anchors
Recalibration scheduling generally comes down to two correction options inside a partial-SOC operating window: a soft anchor, or a true anchor.
A soft anchor uses a local voltage extremum, the highest or lowest point the pack reaches inside its normal band, as a weaker reference signal. It costs no cycling capacity, but it is less reliable than a full anchor, since the flat LFP voltage curve blurs the reading. Voltage-based correction methods can sharpen that signal near the charge end, but our EKF SOC estimation design treats it as one input among several, not a standalone fix.
A true anchor, on the other hand, is a scheduled deep excursion to near 0% or 100% SOC. It fully resets the estimator, but it also costs cycling capacity and, therefore, revenue. So the trade-off is the entire scheduling problem in miniature. How often can a fleet afford to give up a true anchor before drift becomes the bigger cost?
Building a Recalibration Scheduling Cadence
Most fleets land on one of three cadence styles.
| Cadence Type | Trigger | Strength | Trade-off |
|---|---|---|---|
| Drift-triggered | EKF divergence crosses a set threshold | Only recalibrates when actually needed | Requires a mature, well-tuned estimator |
| Fixed-calendar | Every set number of weeks, regardless of drift | Simple, easy to plan around revenue contracts | Can waste capacity if drift is genuinely low |
| Hybrid | Fixed-calendar backstop plus early drift-triggered excursions | Balances predictability with accuracy | More logic to implement and tune |
Drift-Triggered Scheduling
Drift-triggered scheduling waits for the estimator itself to flag a problem, typically when the EKF’s own confidence bounds widen past a threshold. So it is efficient, but it also leans hard on estimator quality.
Fixed-Calendar and Hybrid Recalibration Scheduling
Fixed-calendar scheduling, by contrast, ignores drift signals entirely and recalibrates on a regular, pre-set schedule. It is predictable and easy to coordinate with revenue commitments, though occasionally it recalibrates earlier than the pack strictly needs.
A hybrid approach keeps the fixed-calendar backstop but allows an early trigger if drift crosses a threshold sooner. This is close to the logic behind degradation-aware fleet scheduling, where a control policy weighs the cost of an excursion against the degradation and drift risk of skipping it, rather than treating every fleet asset on an identical fixed clock. It caps the worst case without discarding the efficiency of drift-based triggers.
Whichever cadence a project picks, log every recalibration event alongside its trigger reason. An operations team reviewing dispatch anomalies six months later needs that record to tell a genuine fault from an overdue anchor.
DCIR and SOH Milestones in Recalibration Scheduling
Recalibration scheduling should also not rely on SOC alone. Internal resistance and state of health both drift with age, so both can be tracked independently of the SOC estimator.
Pairing a scheduled true anchor with a DCIR measurement gives two independent readings at once, one for charge state, one for cell condition. Our guide to DCIR-adaptive cutoff design covers how resistance data feeds directly into cutoff-voltage decisions.
This cross-check matters most late in project life. Because cells age, the OCV-SOC relationship itself shifts, so a stale voltage-to-SOC table can mask real drift even right after a true anchor. Tying recalibration scheduling to SOH milestones, not just calendar time, catches that.
A practical rule: refresh the OCV-SOC lookup table on SOH milestones, not a fixed calendar. Early in life, fade is slow, so refreshes are rare. Later, as fade accelerates, they need to happen more often. In other words, the milestone, not the clock, should set the pace.
None of this requires exotic hardware. A BMS that already runs Coulomb counting and logs voltage at rest has what it needs. What is usually missing, instead, is the scheduling logic itself: the explicit rule set that decides when a true anchor is worth the lost cycling revenue and when a soft anchor or a calendar tick will do.
Frequently Asked Questions
How Often Should Recalibration Scheduling Run for a Grid-Services BESS?
There’s no universal number. Because fleets differ, most commercial operators set a fixed-calendar backstop, then allow an early trigger if the estimator’s drift crosses a set threshold sooner. The right recalibration scheduling interval depends on Coulomb-counting sensor quality, how tightly the SOC band is held, and how the fleet weighs lost cycling revenue against estimation risk.
Does partial-SOC cycling shorten the interval between full-range cycles, or lengthen it?
It lengthens it, in the sense that a well-run partial-SOC program deliberately avoids full-range cycles to protect cycle life. Because of that, recalibration scheduling reintroduces them only as often as drift correction requires, not as often as the duty cycle would otherwise allow.
Further Reading
EKF SOC Estimation Design for LFP BESS
Designing an LFP BESS Against SOC Drift, Cell Imbalance, and Premature Cutoffs
Battery Management System (BMS) Explained
References
Full citations for the sources linked inline above:
Gismero, A., Schaltz, E., & Stroe, D.-I. (2020). Recursive State of Charge and State of Health Estimation Method for Lithium-Ion Batteries Based on Coulomb Counting and Open Circuit Voltage. Energies, 13(7), 1811.
Abdollahi, A., Li, J., Li, X., Jones, T., & Habeebullah, A. (2022). Voltage-Based State of Charge Correction at Charge-End. arXiv:2201.02282.
Srinivasa, T. R., Deulkar, V., Bhargava, J., Hajiesmaili, M., & Shenoy, P. (2026). Degradation-Aware Frequency Regulation of a Heterogeneous Battery Fleet via Reinforcement Learning. arXiv:2601.22865.
IEC 60909 Explained: AC Short-Circuit Currents for BESS
A short circuit on the grid side of a BESS behaves nothing like one on the DC bus. IEC 60909 is the standard engineers use to calculate that AC-side fault current.
It also sizes the breakers, relays, and busbars on the grid-facing side of the system.
| Quick Answer IEC 60909 is the IEC standard for calculating short-circuit currents in three-phase AC systems. Its current edition, IEC 60909-0:2016, added rules for how inverter-connected sources like BESS and solar contribute to a fault. So this update matters directly for grid-interconnection and protection-coordination studies. |
What Is IEC 60909?
The standard covers short-circuit current calculation in three-phase AC systems, both low-voltage and high-voltage. IEC Technical Committee 73 develops it, and that’s a detail worth knowing.
That’s the same committee behind IEC 61660, the DC-side equivalent for auxiliary systems. So the two standards share a family resemblance, and not by accident.
The current edition, IEC 60909-0:2016, replaced a 2001 first edition. It’s a full technical revision, not just a minor tweak.
First, the method places an equivalent voltage source at the fault location. Engineers then work out the fault current from that source. They add the impedance of every AC component between it and the fault point.
IEC 60909’s Maximum and Minimum Short-Circuit Current
Like IEC 61660, IEC 60909 calls for two separate calculations, not one. First, the maximum short-circuit current sets equipment ratings.
The minimum short-circuit current does something different. It sets fuse and relay ratings, and it also checks whether protection will trip fast enough during a fault.
Each case runs on its own assumptions, since network configuration and available sources both shift the result.
How IEC 60909 Models Fault Current Sources
IEC 60909 walks through nearly every source type on an AC system. That list covers network feeders, transformers, overhead lines and cables, synchronous generators, and asynchronous motors.
Each source then gets its own impedance model and its own share of the total fault current.
A network feeder is modeled first, using the utility’s own maximum and minimum short-circuit power at the connection point.
Then transformers, cables, and lines each add their own resistance and reactance in series. This works outward from that feeder toward the fault.
Traditional generation still dominates most of this picture. First, a synchronous generator can feed many times its rated current into a nearby fault.
That’s because the fault current is limited mainly by the machine’s own internal reactance, not by any active control.
Picture a substation fed by a large synchronous generator on one side and a smaller BESS on the other. A fault right at the busbar draws heavily from the generator, since its current is bounded only by internal reactance.
The BESS contributes too, but through a very different mechanism, covered next.
Asynchronous motors matter here too, since they aren’t purely passive. Large motors briefly feed current back into a nearby fault as they slow down. So the standard includes a separate check for whether that contribution is large enough to count.
Why the 2016 Edition of IEC 60909 Matters for BESS
IEC 60909’s 2016 edition made a genuinely significant change. It added explicit rules for wind power station units and for power station units with full-size converters. Neither type existed in any meaningful way when the 2001 edition published.
A BESS, meanwhile, connects to the grid through exactly this kind of full-size converter: the PCS. So this update is what actually lets engineers model a BESS’s AC-side fault contribution under a current, recognized standard.
Before 2016, engineers had to adapt rules meant for generators instead, which is a poor fit for how a PCS actually behaves.
How a BESS Contributes to an AC Fault
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A synchronous generator’s fault current is set by its impedance, not by any active control loop, while a PCS works on a different principle entirely. It behaves very differently.
Since the PCS is a power-electronic device, its control system actively regulates the fault current it can push out. IEC 60909 treats it as a current-regulated source instead of an impedance-limited one.
So that current stays capped close to the converter’s own rated current. It doesn’t spike the way a generator’s current can, because the control loop won’t let it.
What This Means for Protection Coordination
This distinction then has real consequences for a project. A feeder fed mostly by BESS and solar can produce far less fault current. That’s true even compared with the same feeder fed by traditional generation.
Many protection schemes were designed around large, generator-driven fault currents. So a low-fault-current feeder can be harder to detect and clear quickly. Under-reach becomes a real risk once the fault current gets close to normal load current.
IEC 60909-0:2016 gives engineers a standards-based way to calculate that lower contribution accurately. That’s a real improvement over guessing at it or borrowing a generator-based rule of thumb.
It’s also why relay settings tuned for a generator-heavy feeder often need a fresh look once a BESS joins the mix.
IEC 60909 vs. Related Standards
IEC 60909 doesn’t work alone on a BESS project. But a few related standards cover adjacent ground.
| Standard | Relationship to IEC 60909 |
|---|---|
| IEC 61660 | The DC-side equivalent, covering short-circuit currents in DC auxiliary systems instead of the AC side. Both standards come from the same technical committee. |
| IEC 62933-5-2 | The BESS safety standard, which addresses electrical safety more broadly rather than fault-current calculation methodology specifically. |
| IEEE 2800-2022 | A newer, US-focused standard for interconnecting inverter-based resources, covering performance requirements alongside fault behavior. |
The IEC 61660 connection is worth calling out directly. A full BESS fault study often needs both — this standard for the grid-facing AC side, and IEC 61660 for the battery-facing DC side.
What This Means for BESS Grid-Interconnection Studies
For a project engineer, IEC 60909-0:2016 is the tool for AC-side protection coordination and utility interconnection studies. First, model the PCS as a current-regulated source, not a synchronous one.
A BESS project often sits on a feeder alongside other inverter-based generation, like solar. So check the combined fault contribution rather than treating each source alone. Utilities reviewing an interconnection application will still expect exactly this kind of AC-side study.
Frequently Asked Questions
Does IEC 60909 apply to battery energy storage systems?
Yes, through its current edition. IEC 60909-0:2016 added specific rules for power station units with full-size converters, covering how a BESS’s PCS contributes to an AC-side fault.
What’s the difference between IEC 60909 and IEC 61660?
This standard calculates short-circuit currents on the AC side of a system. IEC 61660 covers the DC side instead, such as the battery and busbar side of a BESS.
Why does a BESS contribute less fault current than a generator?
A PCS is a current-regulated power-electronic source, not an impedance-limited one. Its control system caps the fault current close to its own rated current, unlike a synchronous generator.
Is IEC 60909-0:2016 the current edition?
Yes. It replaced the 2001 first edition and remains the standard’s current edition as of 2026.
Who uses IEC 60909 on a BESS project?
Protection engineers and utility interconnection teams use it for AC-side fault current, breaker and relay sizing, and protection coordination studies.
Further Reading
For the DC side of a BESS fault study, see our guide to BESS short-circuit protection.
DC and AC bus sizing both fit into the broader spec picture — see Understanding BESS Specifications.
A PCS’s broader grid-fault behavior is covered in Grid-Forming vs. Grid-Following BESS and PCS Overvoltage Protection.
Ride-through behavior during a voltage sag is covered in LVRT and HVRT Ride-Through.
For the broader BESS safety-standard landscape, see IEC 62933-5 Safety Standards.
References
IEC 60909-0:2016, Short-circuit currents in three-phase a.c. systems – Part 0: Calculation of currents. International Electrotechnical Commission.
L. Thurner and M. Braun, “Vectorized Calculation of Short Circuit Currents Considering Distributed Generation — An Open Source Implementation of IEC 60909,” arXiv preprint — describes the standard’s treatment of short-circuit current contribution from distributed generation.
IEC 61660 Explained: Calculating DC Short-Circuit Currents
A short circuit on a DC bus behaves very differently from one on an AC grid. IEC 61660 is the standard engineers use to calculate those DC fault currents in battery storage systems and substations. That way, protection devices get sized right.
| Quick Answer IEC 61660 is a three-part IEC standard for calculating short-circuit currents on DC auxiliary buses. It covers rectifiers, batteries, capacitors, and DC motors. BESS engineers still use it today, even though it predates lithium-ion and was written for lead-acid batteries. |
What Is IEC 61660?
IEC 61660 first appeared in 1997. Its full title is “Short-circuit currents in d.c. auxiliary installations in power plants and substations.” IEC Technical Committee 73 developed it. That same committee owns IEC 60909, the equivalent standard for AC systems.
The standard exists because DC faults don’t behave like AC ones. An AC fault current oscillates and decays in a set way.
A DC fault current rises and falls on its own curve instead. Each source shapes that curve in its own way.
IEC 61660-1 is still listed by the IEC as active and current, even though no revision has replaced it since 1997.
This matters for BESS design. Every battery rack, busbar, and DC disconnect on the storage side of the inverter sits on a DC bus.
So when a fault happens there, protection devices must clear a current whose shape this standard was built to predict.
The Three Parts of IEC 61660
The standard is split into three linked documents. Each one covers a different piece of the fault-current picture.
| Part | Title | What It Covers |
|---|---|---|
| Part 1 | Calculation of short-circuit currents | The core method: peak current, quasi-steady-state current, and how to combine several sources |
| Part 2 | Calculation of effects | Mechanical and thermal stress on rigid conductors and busbars, caused by the current from Part 1 |
| Part 3 | Examples of calculations | A technical report with worked examples, so engineers can check their own math against a known result |
Part 1 does the heavy lifting for most BESS projects. From there, Part 2 turns that current into a mechanical design check, while Part 3 serves as a reference for checking the numbers.
Part 3 wasn’t even finished when Part 1 published in 1997. The original foreword lists it as “in preparation,” and it only appeared a few years later as a technical report.
How IEC 61660-1 Calculates DC Short-Circuit Current
Two values matter most to a protection engineer.
Two Values That Matter: Peak and Quasi-Steady-State Current
The peak short-circuit current, written as ip, is the highest instant current a fault ever reaches. So this value sets the rating for breakers, fuses, and busbars, since they must survive that first spike without failing.
The quasi steady-state current, written as Ik, is the current level one second after the fault starts.
Engineers then use this lower, settled value to set fuse and relay trip points, since it reflects what a slower device actually has to clear.
Between those two points sits the time to peak, tp. It tells engineers how fast the current climbs before it starts to fall.
Maximum and Minimum Short-Circuit Current
The standard actually calls for two separate calculations, not one. For equipment ratings, engineers work from conditions that produce the highest possible fault current: cooler conductor resistance and a fully charged battery.
For fuse and protection settings, they work from conditions that produce the lowest fault current instead: conductor resistance at the system’s maximum operating temperature, and a battery closer to fully discharged. Each case still has its own peak and quasi-steady-state current, so a full study runs through both.
Four Sources of DC Fault Current
The method models four types of equipment that can feed a DC short circuit:
- Rectifiers in a three-phase AC bridge connection
- Stationary lead-acid batteries
- Smoothing capacitors
- DC motors with independent excitation
Each source has its own current shape. A rectifier’s fault current follows the AC network behind it.
Meanwhile, a battery’s current rises with a time constant set by its own resistance and inductance, and a capacitor discharges fast, then decays.
A motor is different again, since it keeps feeding current for a short time while its stored mechanical energy converts back into electrical energy.
When more than one source can reach the same fault point, a correction factor (the standard calls it sigma) combines their peaks into one worst-case total. This matters because the individual peaks don’t always line up in time.
Picture a substation battery room with a rectifier charger and a battery bank feeding the same DC bus. The rectifier’s current might peak in a few milliseconds, while the battery’s current keeps climbing for longer, since its inductance slows the rise. Because of that timing gap, the correction factor keeps the combined peak from being just a simple sum of two separate maximums.
Why IEC 61660 Still Matters for Lithium-Ion BESS
The standard was written in 1997, years before lithium-ion reached grid-scale storage. That gap still matters for BESS engineers today.
The Lithium-Ion Gap
The battery clause only models stationary lead-acid cells, and it gives no official method for lithium iron phosphate or other lithium-ion chemistries. So a literal reading of the standard doesn’t cover the battery technology in most BESS projects built today.
How Engineers Work Around It Today
In practice, the industry leans on two workarounds.
First, many engineers treat a lithium-ion string’s short-circuit response like a capacitor discharge. Both show a fast spike, then a decay, and the standard already has a capacitor method built in.
Second, most BESS integrators pull short-circuit current data straight from the cell or rack maker’s datasheet. They then feed those figures into the rest of the calculation, alongside the rectifier and capacitor terms.
Commercial short-circuit analysis software built around this method now adds lithium-ion battery models as an extension beyond the base document. Engineers keep the same combination approach while plugging in a chemistry-correct source model.
IEC 61660 vs. Related DC and BESS Standards
This standard doesn’t work alone, since a few other documents reference it or cover nearby ground.
| Standard | Relationship to IEC 61660 |
|---|---|
| IEC 60909 | The AC equivalent. This standard’s own foreword names IEC 60909 as a companion reference for the rectifier’s AC-side contribution. |
| IEC 62485-2 | Covers stationary battery installation safety and cites this method for the short-circuit figures that feed protection and ventilation design. |
| IEC 62933-5-2 | The BESS safety standard covers electrical safety more broadly, including how DC-side fault-current figures feed into protection design. |
| IEC 62619 | Covers cell and battery safety testing rather than system-level fault current, so it complements this standard instead of overlapping it. |
What This Means for BESS DC Bus Protection Design
For a project engineer, the takeaway is simple: first, size DC breakers and busbars to the peak current, ip.
Set fuse and relay trip points from the quasi-steady-state current, Ik. Then combine every source that can feed the same fault point, not just the battery.
Since the method predates lithium-ion, document which battery-current approach the design used. Note whether it was capacitor-equivalent modeling or manufacturer datasheet figures, so the calculation can be reviewed and repeated later.
Also check Part 2 once the current is known. A busbar sized only for steady-state load current can still fail mechanically under a DC fault it was never checked against.
Frequently Asked Questions
Does IEC 61660 apply to lithium-ion BESS?
Not directly, since the battery clause only covers stationary lead-acid batteries. Engineers commonly adapt the capacitor model instead, or use manufacturer-supplied short-circuit data for lithium-ion strings.
What’s the difference between IEC 61660 and IEC 60909?
IEC 60909 calculates short-circuit currents in three-phase AC systems. This standard calculates them on the DC side instead, where fault currents don’t oscillate and decay the same way.
Is there a newer edition of IEC 61660?
The first edition dates to 1997, with corrigenda issued in 1999 and 2000. Even so, no second edition has replaced it as of 2026.
What does Part 2 cover that Part 1 doesn’t?
Part 1 calculates the fault current itself, while Part 2 uses that current to calculate the mechanical and thermal stress it puts on rigid conductors and busbars.
Who uses IEC 61660 in a BESS project?
Protection and electrical engineers use it to size DC breakers, fuses, and busbars during the design phase, well before commissioning.
Further Reading
For more on how DC-side faults are handled in BESS design, see our guide to BESS short-circuit protection.
To see how DC bus sizing fits into overall system specs, read Understanding BESS Specifications.
For how a BMS ties into protection design, see BMS Functional Safety, HARA, and FMEA.
For the broader BESS standards landscape, see IEC 62933 Energy Storage Standards, IEC 62933-5 Safety Standards, and our BESS Certifications Guide.
References
IEC 61660-1:1997, Short-circuit currents in d.c. auxiliary installations in power plants and substations – Part 1: Calculation of short-circuit currents. International Electrotechnical Commission (with Corrigenda 1:1999 and 2:2000).
IEEE Industry Applications Society, “DC Arc Flash: History, Physics, and Modeling for Battery, Capacitor, and PV Systems,” first presented at the IEEE Electrical Safety Workshop (ESW) 2023 — covers DC incident-energy modeling approaches for large battery systems, including lithium-ion, and their relation to standards-based short-circuit current models.
Fault Ride-Through Features: The PCS Hardware and Control Functions Behind LVRT/HVRT Compliance
Fault ride-through features are what actually turn a grid-code curve into real PCS behavior during a fault. A ride-through curve on a datasheet is a target, not a mechanism — the hardware and control functions inside the PCS are what determine whether a unit actually meets that target when a real fault hits the line. This article breaks down what those fault ride-through features are and how they work together, from gate-driver-level protection up through plant-level coordination.
| Quick Answer Fault ride-through features are the hardware and control functions inside a PCS — current limiting, DC-link protection, and DC-side energy absorption — that let it meet a grid-code ride-through curve. A compliant curve on a datasheet doesn’t say which of these features a PCS actually implements. |
Our guide to LVRT and HVRT ride-through covers the grid codes and voltage-against-time curves that compliance is measured against. This article goes one level deeper and walks through the specific hardware and control features inside the PCS that make ride-through possible in the first place. Two PCS units can both carry a compliant ride-through curve on their datasheets. They can still behave very differently under an actual fault, because the curve describes an outcome, not an implementation.
Two Layers of Fault Ride-Through Response
A PCS handles a fault in two layers. The layers operate on very different timescales. Both layers have to work correctly, or fault ride-through features never get the chance to activate.
- Hardware-level protection reacts in microseconds to low milliseconds. Its only job is to keep the semiconductors from destroying themselves. It has no concept of a grid code.
- Control-level ride-through reacts over tens to hundreds of milliseconds. This layer decides whether the PCS stays connected, injects reactive current, and follows the shape of the required curve.
If the hardware layer trips protectively, the control layer never gets the chance to ride through anything. Whichever layer is more conservative sets the PCS’s real fault ride-through capability — not the control algorithm alone.
Hardware-Level Fault Ride-Through Features
The fastest protection in a PCS sits at the gate-driver level. It senses the collector-emitter voltage of each IGBT to detect desaturation, a condition that signals an output short or a failing device. Engineers tune desaturation-sensing circuits deliberately to avoid nuisance tripping during normal switching transients. The circuits still have to catch a genuine fault fast enough to protect the device.
DC-Link Overvoltage Protection Features
Fault ride-through duty puts stress on the DC side, not just the AC side. During a grid voltage swell, or when active power suddenly can’t be exported at the pre-fault rate, energy backs up into the DC-link capacitor. Left unmanaged, this drives DC-link voltage past the semiconductors’ safe operating limit. The standard hardware answer is a brake chopper: a switch and resistor in series across the DC bus. The chopper circuit compares DC-link voltage against a threshold and switches accordingly, so it dumps excess energy as heat only when the bus voltage would otherwise exceed its saturation limit. Well-designed implementations fire the chopper only when needed. That way, the system wastes no energy during a swell the DC side can absorb on its own.
The wider category of hardware fault ride-through features for DC-link protection includes DC chopper resistors, dynamic braking resistors, and, in some designs, superconducting or bridge-type fault current limiters. These originated in wind turbine converters. The underlying function — dumping fault-driven excess energy somewhere the semiconductors can tolerate — applies directly to PCS design for solar and BESS.
Chopper sizing matters beyond a single event. A resistor sized to survive one fault safely can still overheat if the plant experiences repeated faults in close succession. Repeated faults are common on weak or fault-prone feeders. Duty-cycle rating, not just peak wattage, is the number to check when specifying the chopper.
Control-Level Fault Ride-Through Features
Once the hardware layer confirms the fault is survivable, the control layer decides how the PCS behaves for the rest of the ride-through window. This matters most for grid-forming PCS designs. Utility-scale BESS increasingly uses grid-forming designs because they set their own voltage reference rather than tracking the grid through a phase-locked loop. Three main control-level fault ride-through features keep grid-forming output current within hardware limits during a fault:
- Current saturation: the controller switches into a current-controlled mode and fixes the current reference at the PCS’s maximum rated output for the duration of the fault.
- Virtual impedance: the controller inserts an artificial impedance into its internal voltage-reference calculation. This lowers the commanded voltage in proportion to output current and limits current without a hard mode switch.
- Priority-based saturation: a blended approach that combines current saturation and virtual impedance. It captures the current-limiting reliability of the first method with the smoother, more predictable transient response of the second.
These three approaches trade off differently. Engineers can tune virtual-impedance methods to output more reactive power during the fault than a plain current-limiting approach, which improves voltage support at the point of connection. That only works if they tune the virtual impedance gain correctly. A gain value that’s too small fails to limit current under a severe sag. A gain that’s too large can trigger instability. Published tuning work generally lands on a gain factor between roughly 5 and 10 to balance decoupling and damping.
Timing the virtual impedance is its own design problem. Too little virtual impedance risks depleting the DC bus; too much can cause a grid-forming unit to lose synchronism with other units on the same plant. That risk becomes real once a plant has more than one grid-forming PCS responding to the same event independently.
Fault Ride-Through Features for Unbalanced (Asymmetrical) Faults
Most faults on a distribution or sub-transmission feeder are unbalanced — single-line-to-ground or line-to-line — not the symmetrical three-phase dip used in headline grid-code curves. Unbalanced faults introduce negative-sequence voltage and current components. A control loop built only for positive-sequence quantities can’t regulate these components correctly. Some grid-forming control architectures address this by working directly in the stationary reference frame rather than the conventional rotating (synchronous) frame. This design choice simplifies separating and limiting positive- and negative-sequence fault current independently. Engineers make this control-architecture decision well before a fault occurs — a plant controller can’t add it after the fact.
Fault Ride-Through Features That Differ Between BESS and Solar-Only PCS
A solar PCS has one energy source: whatever the array produces at that instant. It can curtail that output but not absorb energy. A BESS PCS has a battery on the DC side that can actively source or sink energy. That difference changes what fault ride-through features can actually do in practice.
- During a voltage swell (HVRT), a BESS can charge from the surplus DC-side energy instead of dumping it through a brake chopper — but only if the BMS accepts a fast charge-current step, not just a steady-state charge-power limit.
- State of charge and cell temperature set the real headroom. Near full SOC or at temperature extremes, the BMS derates charge current. That derating shrinks how much of a voltage swell the battery can absorb and pushes the PCS back toward reactive-current absorption or a supplemental dump resistor.
- This means the PCS-BMS communication interface needs a fast current-limit path for ride-through events. That path has to run faster than the slower power-limit updates the system uses during normal charge/discharge scheduling.
None of this shows up on a PCS current-vs-time datasheet curve, because the curve is a converter-side spec. Whether the battery can actually support that curve under real SOC and temperature conditions is a system-level integration question, not a spec-sheet question.
Converter Topology and Fault Ride-Through Behavior
Topology choice shapes how fault current is distributed and controlled inside the converter itself.
- Two-level converters concentrate fault current stress on fewer semiconductor devices per phase leg. This simplifies control but raises per-device stress during a fault.
- Multilevel topologies (such as neutral-point-clamped or modular multilevel designs) spread that stress across more devices. They allow finer control of output voltage during unbalanced current injection, at the cost of more complex coordinated current-limiting logic across levels.
Plant-level topology matters too. Whether the site uses a string architecture or a small number of centralized PCS units changes how individual-unit current limits sum to the plant’s response at the point of interconnection. See our String vs. Centralized BESS PCS comparison for how that choice plays out beyond fault ride-through behavior.
Plant Controller Coordination for Fault Ride-Through Features
A single PCS unit’s current-limiting response is only half the picture. On a multi-inverter plant, the plant controller must aggregate every unit’s local response into a combined output at the point of interconnection (POI). That combined output has to match the required curve. Individual units sometimes apply current limiting independently, with slightly different thresholds or timing. When that happens, the combined POI response can differ meaningfully from what any single unit’s test report shows. Communication latency between the plant controller and individual PCS units becomes a real design constraint here. Ride-through windows can run as short as tens of milliseconds — too short for a slow polling cycle to matter.
Specifying Fault Ride-Through Features When Selecting a PCS
Treat fault ride-through features as a checklist to verify individually, not a single line item to take on faith.
- Ask which current-limiting algorithm the PCS implements — current saturation, virtual impedance, or a priority-based blend — and how the manufacturer tuned the gain or setpoint, not just whether it claims a compliant curve.
- Ask whether the manufacturer validated the DC chopper or dump resistor for repeated, closely spaced faults, not a single worst-case event.
- Confirm the BMS charge-current step response time. Check whether it’s fast enough to support the PCS’s intended DC-side energy-absorption strategy during HVRT.
- Confirm whether the unit is grid-following or grid-forming, and how its behavior changes during any momentary-cessation window.
- Request fault-current test evidence at the plant-controller level, aggregating multiple units, not only single-unit type-test results.
Key Fault Ride-Through Features at a Glance
| Feature | Why It Matters |
|---|---|
| Gate-driver desaturation detection | Fastest layer of protection; determines whether the control layer ever gets to ride through the fault |
| DC chopper / dump resistor | Keeps DC-link voltage within limits during a swell; duty-cycle rating matters more than peak wattage |
| Current saturation vs. virtual impedance vs. priority-based | Different trade-offs between reliability, reactive support, and transient smoothness |
| Positive/negative-sequence current control | Required for the unbalanced faults that dominate real-world fault statistics |
| BESS DC-side energy absorption | Lets a BESS actively soak up swell energy instead of only dissipating it — subject to SOC and thermal derating |
| Plant controller aggregation | Individual-unit compliance doesn’t guarantee POI-level compliance on a multi-inverter plant |
Frequently Asked Questions About Fault Ride-Through Features
What’s the difference between hardware-level and control-level fault ride-through features?
Hardware-level features, such as IGBT desaturation detection, react in microseconds to protect the semiconductors. They have no awareness of grid-code requirements. Control-level ride-through features operate over tens to hundreds of milliseconds. This layer actually follows the required voltage-against-time curve. Hardware protection takes priority whenever the two layers conflict.
Why does a BESS have an advantage over a solar-only plant during HVRT?
A BESS can actively charge its battery to absorb surplus DC-side energy during a voltage swell. A solar-only PCS can’t do this — it has no equivalent energy sink beyond curtailing the array.
What is virtual impedance current limiting?
It’s a control technique where the inverter’s controller inserts an artificial impedance term into its internal voltage-reference calculation. This lowers the commanded output voltage in proportion to current and limits fault current without switching the converter into a different control mode.
Do all grid-forming inverters use the same fault ride-through features?
No. Implementations vary in whether they use current saturation, virtual impedance, or a priority-based combination. They also vary in whether they regulate unbalanced fault current in the stationary or synchronous reference frame. These are architecture-level decisions, not settings a plant operator can change after the PCS is built.
Why does DC chopper sizing matter beyond a single fault event?
A brake chopper resistor sized for a single worst-case fault can still overheat if the plant experiences repeated faults in a short period. Repeated faults are common on weaker feeders. Duty-cycle rating, not just peak wattage, determines whether the chopper survives real-world fault patterns.
Further Reading
LVRT and HVRT: Voltage Ride-Through for BESS and Solar
MCS Certification Explained: The Complete Guide to the UK’s Microgeneration Certification Scheme
MCS certification is the UK’s benchmark for quality in small-scale renewable energy. Since 2007, it has set the standards for solar panels, battery storage, and heat pumps. A product or installer must meet those standards to earn the MCS mark. For homeowners, that mark is often the difference between a government grant and no grant at all.
| Quick Answer MCS certification is the UK’s quality mark for small-scale renewable energy. It covers solar PV, battery storage, heat pumps, solar thermal, biomass, and wind. MCS certifies both the products and the installers who fit them. Most UK government incentives, including the Smart Export Guarantee and Boiler Upgrade Scheme, require it. |
What Is MCS Certification?
MCS stands for Microgeneration Certification Scheme. It is a UKAS-accredited quality scheme. It covers small-scale, low-carbon energy technologies in UK homes and small businesses.
The scheme works on two levels at once. First, it certifies products, while also certifying the businesses that install them. A solar panel, battery, or heat pump must pass independent testing first. Only then can it carry the MCS mark. Second, it certifies installers. The business that fits the system must also meet set technical and consumer-protection standards.
Both halves matter together. A certified product fitted by an uncertified installer will not earn an MCS certificate. Nor will a certified installer using an uncertified product.
The scheme is owned by the MCS Charitable Foundation, a registered charity. It is run day to day by The MCS Service Company Ltd. Independent certification bodies carry out the actual assessments. These bodies hold UKAS accreditation to ISO 17065.
A Brief History of the Scheme
MCS launched in 2007, backed by the UK government. At the time, the microgeneration market was growing fast but had little oversight. The scheme brought a common set of rules to that market.
Early adoption came from the Feed-in Tariff and Renewable Heat Incentive. Both required MCS-certified equipment and installers to qualify for payments.
Although those two schemes have since closed, the certification framework has grown alongside the newer incentives that replaced them. Battery storage joined the scheme in 2020, with its own dedicated installation standard. That change reflects how central storage has become to UK home energy.
Through 2026 and into 2027, MCS is rolling out its biggest change since launch. This is a redeveloped installer scheme, covered later in this guide.
What Technologies Does MCS Certification Cover?
MCS certification spans seven core technology groups. Together, they cover most of the low-carbon systems a UK household is likely to install.
- Solar PV — rooftop and ground-mounted panels that generate power
- Battery storage — electrical energy storage systems (EESS) that store solar or grid power for later use
- Air and ground source heat pumps — low-carbon heating and hot water
- Solar thermal — panels that heat water directly from sunlight
- Biomass — wood-fuelled boilers and stoves
- Wind turbines — small-scale wind power for homes and small firms
- Micro-hydro — small water-driven electricity generation
How MCS Certification Works
Every technology under the scheme follows two linked sets of rules. One is a product standard. The other is an installation standard. Together, they explain why both the equipment and the company fitting it need to carry the mark.
Product Standards
Product standards set out performance and safety tests for a given technology. MCS 005, for example, covers solar PV modules. On top of that, every manufacturer must also meet MCS 010, a shared factory quality-control standard that applies across all product types. Consequently, a manufacturer submits its product for independent testing first. Only then does it appear on the MCS certified products list.
Installation Standards
Installation standards are published as MCS Installation Standards (MIS) documents. They define how an installer must design, size, and commission a system on site. They cover everything from electrical safety to customer handover paperwork.
An installer’s work is checked in several ways. Certification bodies run technical checks, sample audits, and site visits. Most of this happens on a rolling annual cycle.
MCS Certification for Battery Storage
Battery storage sits inside the same certification framework as solar and heat pumps. It has its own installation standard, though: MIS 3012. First piloted in 2020, and updated since, it covers residential and small commercial systems up to 50kW.
MIS 3012 sorts battery installations into four classes. MCS calls these Electrical Energy Storage System (EESS) classes. The class depends on how the battery, inverter, and safety devices are packaged. It also depends on how many manufacturers supplied them. This classification decides which compatibility checks an installer must run before commissioning.
For a broader look at how storage certification standards work outside the UK residential market, see our guide to BESS certifications.
MIS 3012 also adds UK-specific requirements on top of general battery safety practice. These cover DC isolation, fire and ventilation guidance, and mandatory customer documentation at handover.
Why MCS Certification Matters for Homeowners and Installers
MCS certification is not a legal requirement. You can install a solar panel, battery, or heat pump without it. In practice, though, it is very hard to access UK government incentives without the certificate.
Smart Export Guarantee
The Smart Export Guarantee pays households for electricity they export to the grid. To qualify, an MCS certified installer must install the system. The products used must also be MCS certified. A smart meter that records exports is required too.
Boiler Upgrade Scheme
The Boiler Upgrade Scheme is run by Ofgem on behalf of DESNZ. It offers grants of up to £7,500 towards an air or ground source heat pump. Biomass boilers can get up to £5,000. Both the installer and the heat pump must carry MCS certification for the grant to pay out.
Other Incentives and Protections
The certificate also underpins eligibility for ECO4 and the Home Energy Scotland Grant and Loan, sitting alongside 0% VAT benefits on qualifying installations. Beyond the money, certified installers owe customers real protections. These include a written quote, a minimum workmanship warranty, and free access to dispute resolution if something goes wrong.
The Redeveloped MCS Installer Scheme
MCS is in the middle of its biggest overhaul since launch. Consultation began in 2022 and 2023. The redeveloped installer scheme then started rolling out to installers in early 2026. MCS has set a target completion date of 31 March 2027.
The new scheme shifts focus. It moves away from paperwork-heavy quality management systems. Instead, it looks at the quality of the finished installation on site. Three named business roles now sit at the centre of every certified installer. A Licensee holds ultimate responsibility for meeting scheme requirements. The Main Contact handles day-to-day contact with MCS and the certification body. A Technical Supervisor then signs off that each job meets the relevant installation standard.
Track record now shapes how often an installer gets checked. Installers with a strong, consistent record face fewer site assessments. Those with more issues get checked more often. Every installer must also buy an MCS-approved financial protection product for each customer. This gives homeowners a safety net if an installer cannot fix a problem itself.
How to Check MCS Certification
Checking a company’s MCS certification takes under a minute, and it is free. Search the public installer database on the MCS website. Or look up a specific job on the MCS Installations Database, at certificate.microgenerationcertification.org.
Before signing a contract, confirm three things. First, check the installer’s certification is current. Second, check the exact product model sits on the MCS certified products list. Third, check the installer’s certification covers the technology you are buying. An installer certified for solar PV is not automatically certified for battery storage. Each technology sits under its own installation standard.
Key Takeaways
- MCS certification is the UK’s main quality mark for solar PV, battery storage, heat pumps, solar thermal, biomass, and wind.
- It certifies products and installers separately. A valid MCS certificate needs both.
- It is not a legal requirement, but it is required for the Smart Export Guarantee, Boiler Upgrade Scheme, and ECO4..
- Battery storage has its own installation standard, MIS 3012, covering systems up to 50kW.
- A redeveloped installer scheme is rolling out through 2026 and 2027, with new business roles and mandatory financial protection.
Frequently Asked Questions
Is MCS certification a legal requirement?
No. You can install a solar panel, battery, or heat pump without it. You will not, though, qualify for the Smart Export Guarantee, the Boiler Upgrade Scheme, or related regional grants.
How long does certification last?
It is ongoing, not a one-off event. Certification bodies run regular audits, usually once a year. An installer can lose certification for failing to meet the standard.
Does MCS cover standalone battery storage?
Yes. MIS 3012 covers battery storage added to an existing solar system. It also covers battery-only installations with no solar panels at all.
What happens with a non-MCS installer?
The work may still be safe and good. It will not, though, generate an MCS certificate. Without that certificate, the property cannot access MCS-linked grants or export payments, even later.
Learn More From MCS
For the full list of current standards, certified installers, and certified products, see the official MCS website, which maintains the live installer and product databases referenced throughout this guide.