Shared Bus, Hidden Resonance

Co-locating a battery with a solar array on one 480 V bus creates an electrical problem that no single piece of equipment owns — and that neither manufacturer will solve for you. Here is what actually has to be calculated before the transformer is ordered.

A solar array and a battery sharing a common 480 V collection bus is now the default architecture for co-located generation. It is efficient, it saves a transformer, and it works — until the two sets of power electronics start talking to each other through the bus impedance.

The failure mode does not announce itself. There is no bang, no trip on day one. What happens instead is a slow accumulation of symptoms that get attributed to everything else: nuisance inverter faults during light-load mornings, capacitor heating, harmonic alarms that the SCADA system logs and nobody reads, a protection relay that operates for no fault anyone can find. Sites run for months in this condition. Some run for years, quietly losing production and equipment life.



The cause is resonance between the output filters of two independent inverter systems that were never designed to share a bus. And the fix — an isolation transformer or a line reactor — is cheap relative to the consequences, provided it is specified correctly. That last condition is where most of the difficulty lives.

1.  Why a shared bus goes unstable

Every grid-forming or grid-following inverter has an output filter, almost always an LCL arrangement, whose job is to keep switching-frequency ripple out of the network. That filter is a resonant circuit. On its own, connected to a stiff grid, its resonant peak sits at a frequency the inverter’s own control loop is designed to damp, and nothing interesting happens.

Put a second inverter system on the same bus and the picture changes. The two filters are now coupled through the bus impedance, which is small. The combined network has resonant frequencies that neither manufacturer modelled, because neither manufacturer knew what else would be connected. If one of those frequencies happens to land near a harmonic order that either system produces — the 11th, the 13th, somewhere in the low hundreds of hertz to low kilohertz — the network amplifies it rather than damping it.

Amplification of a few per cent of harmonic current into something much larger is what produces the heating, the alarms and the spurious relay operations. The magnitude depends on how sharp the resonant peak is and how much damping the network provides, which is why two apparently identical sites can behave completely differently.



The part that catches people out

Resonance is worst at light load, not full load. Absolute harmonic current from switching ripple is roughly independent of real power output, so a site at 25 % output is injecting nearly the same absolute harmonic current into a network with far less damping from load. Sites that are perfectly stable at midday can misbehave at breakfast.

2.  What the battery manufacturer requires

Tesla addresses this directly in the Megapack 2 XL Design and Installation Manual at §2.9.1, and the requirement is unusually concrete. Excessive resonance is expected — their word — when a Megapack shares a common 480 V AC bus with power electronics meeting both of two conditions:

• The total apparent power rating of the power electronics exceeds 20 % of the Megapack’s apparent power rating.
• The equivalent switching frequency at the AC bus is less than 35 kHz.

Both conditions are met on essentially every co-located solar-plus-storage site built today. A 2-hour Megapack 2 XL has a 2,400 kVA inverter rating, so the 20 % threshold is 480 kVA — less than three utility-scale string inverters. And no utility-scale inverter on the market switches anywhere near 35 kHz; silicon-carbide designs have raised switching frequencies considerably but remain an order of magnitude below that ceiling.

Where both conditions are met, three remedies are permitted: relocate the equipment, install a line reactor of at least 0.022 mH per phase, or install an isolation transformer with impedance between 3 % and 7 %. In both cases the mitigation must carry the continuous current of the connected equipment and must sit in series between the Megapack and the common AC bus.

A location detail worth reading twice

The manual places the mitigation between the battery and the bus. Many designers place it between the solar switchgear and the bus instead, which is often the better engineering choice and interrupts the same resonant loop. It is nonetheless a documented deviation, and it costs nothing to obtain written concurrence from the manufacturer’s applications engineering before the purchase order is placed. Warranty positions have been lost over less.

3.  Reactor or transformer

The reactor is dramatically cheaper. A 0.022 mH three-phase reactor is a fraction of the cost, size and lead time of a 2,500 kVA dry-type transformer, and it satisfies the manufacturer’s stated requirement. On a project where budget is under pressure, it is the obvious answer.



It is also, frequently, the wrong one — not because it fails to solve the resonance problem, but because it solves only the resonance problem. Co-located sites usually have two or three other issues in the same part of the single-line, and the transformer disposes of all of them at once.

One row deserves expansion. A reactor at the manufacturer’s minimum of 0.022 mH presents 8.3 mΩ at 60 Hz, which on a 2,500 kVA, 480 V base is roughly 9 % impedance — larger than a typical transformer’s 5.75 %. The reactor is not a small impedance. But it sits in the battery branch, so it does nothing for fault duty or incident energy at the solar switchgear, which is where people are working.

4.  Three ways the specification goes wrong

Assume the transformer is the chosen route. Three specification errors recur often enough to be worth naming, and all three survive vendor review because the vendor builds what the specification says.

4.1  Nobody says which winding faces the array

A specification that reads "Primary 480 V delta, secondary 480 V wye" is ambiguous in a photovoltaic application, because real power flows from the array toward the utility while transformers are conventionally described from the utility side. A vendor can reasonably build that unit with the delta facing either direction.

The direction is not a detail. Standard transformerless string inverters require a grounded wye source facing the inverters — the system’s neutral must be grounded so that line-to-ground voltage is defined and bounded. Certain variants require the exact opposite, a floating ungrounded source. Get the orientation backwards and either the inverters lose the reference they need, or a variant that must float finds itself grounded.

Write it physically, not by label

State on the purchase order and confirm on the approval drawings: wye winding facing the solar switchgear, neutral brought out and grounded at a single point; delta winding facing the medium-voltage transformer.

Do not rely on the words primary and secondary to carry that meaning, because they do not.

4.2  Sizing on real power divided by power factor

The familiar calculation is S = P ÷ PF. For a 2 MW site at 0.90 power factor that gives 2,222 kVA, rounded up to a 2,500 kVA standard rating. The arithmetic is correct and the answer often happens to be right, but the reasoning does not apply to an inverter block.

String inverters are apparent-power limited. A 200 kVA unit with adjustable power factor delivers 200 kVA total; at 0.90 PF that is 180 kW of real power, not 200 kW plus reactive on top. Ten of them total 2,000 kVA and deliver 1,800 kW at 0.90 PF. There is no operating point at which 2,222 kVA flows.

The correct basis is aggregate inverter apparent power. It matters because the same faulty reasoning applied to a 1.5 MW block gives 1,667 kVA and invites a 1,500 kVA transformer that is exactly at its rating with zero margin — for a continuous-duty source, on cold clear days, with no allowance for future inverter addition.

4.3  Buying more K-factor than physics requires

K-factor is the standard way of rating a transformer for harmonic heating, and it is routinely over-specified. The definition, per UL 1561, sums over all orders including the fundamental, with harmonic current expressed in per unit of rated RMS load current:

  K  =  Σ  ( I h, pu )²  ×  h²

The order-squared weighting looks alarming and drives people toward K-13 or K-20. But the fundamental term dominates the sum, so a fixed quantity of distortion produces far less variation in K than the weighting suggests. Take a modern silicon-carbide inverter with published total current distortion under 3 % at rated load, and place all of that distortion at a single harmonic — the least favourable case that can physically exist:

A conclusion you can reach without measuring anything



Even in the physically unrealisable worst case, the required K-factor is 3.25. Any realistic distribution across the low orders gives between 1.0 and 1.6. K-4 is adequate under every spectral distribution consistent with a published sub-3 % distortion figure, and escalating beyond it buys physical size and cost with no technical basis. This is a bounding argument, and measurement cannot overturn it.

5.  The grounding consequence nobody budgets for

Install a transformer with a grounded wye winding facing the array and you have created a separately derived system under NEC Article 250.30. This is not optional and it is not free. It requires a system bonding jumper at one point only, a grounding electrode conductor sized to Table 250.66 and run to a grounding electrode at the transformer or first disconnecting means, and a supply-side bonding jumper.

None of that exists before the transformer is installed, because the array’s ground reference previously came from the medium-voltage transformer’s secondary. Adding the isolation transformer moves the reference, and every downstream assumption about ground-fault detection moves with it.



There is a second-order trap here that catches experienced installers. Standard string inverters commonly ship with the neutral terminal bonded to the ground terminal at the factory. Establish a new single-point bond at the transformer and every inverter’s internal bond becomes an additional reference tied in through the equipment grounding conductor. Manufacturers generally publish a procedure for lifting that internal bond; whether it should be lifted is a per-site determination under NEC 250.30 and 250.6, and it should be settled with the manufacturer in writing rather than decided on a ladder.

6.  The question the inverter manufacturer cannot answer

A recurring exchange on these projects goes roughly as follows. The designer asks the inverter manufacturer whether it is acceptable for the neutral to be established by a separate grounding transformer rather than bonded at the inverter. The manufacturer replies that a grounded wye transformer is required. Both parties believe the question has been answered. It has not.

What the inverter requires is a grounded wye source — a defined, bounded ground reference. A zig-zag or grounded wye-delta grounding transformer provides exactly that. So the answer is yes, in principle, subject to one condition that the inverter manufacturer is in no position to evaluate: the resulting system must be effectively grounded at the inverter terminals.

Per IEEE C62.92.1 that means X0/X1 not greater than 3 and R0/X1 not greater than 1, giving a coefficient of grounding of 80 % or less of nominal line-to-line voltage — equivalently, line-to-ground voltage on the unfaulted phases held within roughly 1.38 per unit of nominal line-to-neutral during a ground fault. A grounding transformer of inadequate rating or excessive zero-sequence impedance will not meet it, and the inverter is then exposed to a temporary overvoltage it was never rated to withstand.

Whether any particular arrangement qualifies is a symmetrical-component calculation on your system. The manufacturer cannot perform it, because the answer depends on impedances they have never seen.

A related point about delta windings

A grounded-wye winding presents low zero-sequence impedance only when it is backed by a delta winding or a delta tertiary. A wye-to-grounded-wye unit without one presents high zero-sequence impedance and will generally fail the X0/X1 criterion.

This is worth checking on the existing medium-voltage transformer: a YNyn0 vector group with no tertiary means the site has no zero-sequence trap anywhere between the inverters and the utility, and triplen harmonics pass straight through. The nameplate will tell you in about ten seconds.

7.  What calculation settles, and what needs a meter

Projects stall when this boundary is unclear, usually because someone has been told that nothing can proceed without a power-quality survey. That is not true, and the distinction is worth being precise about, because the equipment decision does not depend on measurement at all.

Everything governing the purchase order is in the top block. A desktop study settles the equipment decision completely. Measurement is required for the utility submission and for quantifying resonance excitation — genuinely necessary work, but not on the critical path to ordering steel.

If you are recording the data yourself

Get the measurement specification written before anyone deploys an instrument. IEEE 519 compliance is assessed statistically — twelve-cycle windows aggregated to three-second values, two hundred of those aggregated to ten-minute values, evaluated at the 95th and 99th percentile over a continuous seven-day period, orders 2 through 50, with instrumentation to IEC 61000-4-7 and IEC 61000-4-30 Class A.

A seven-day recording made with the wrong instrument class or the wrong aggregation cannot be repaired in analysis. It has to be done again.

8.  Before the purchase order goes out

• Confirm per-site AC capacity against the inverter schedule, not the project name — drawing revisions lag capacity changes more often than not
• State winding orientation physically: which winding faces the array, and where the single grounding point is
• Confirm the inverter variant, standard or floating, because they impose opposite grounding requirements
• Read the existing medium-voltage transformer nameplate for the vector group and check whether a zero-sequence trap exists anywhere
• Verify impedance against the battery manufacturer’s band, including the ±7.5 % manufacturing tolerance permitted by IEEE C57.12.01
• Size the K-rating on a bounding calculation and resist escalation without a supporting number
• Obtain written concurrence from the battery manufacturer if the mitigation sits anywhere other than where the manual puts it
• Budget the separately derived system work — electrode, conductor, bonding, and revised ground-fault detection
• Settle the inverter internal neutral-to-ground bond in writing with the manufacturer
• Check whether the specified efficiency standard actually applies; a 480–480 V unit may qualify as special-purpose, which affects cost, size and lead time
  

9.  Case studies

Note on these cases



The following are anonymised engineering scenarios drawn from co-located solar-plus-storage work. Client names, locations and identifying details have been removed, and figures have been rounded or adjusted where necessary to prevent identification. They are presented to illustrate the engineering, not as a client reference list.

Case 1 — The transformer that would have been built backwards

Situation. 

A cooperative was developing four co-located solar-plus-storage sites and had reached the point of quoting isolation transformers to satisfy the battery manufacturer’s resonance requirement. A specification had been drafted internally and circulated to vendors: 1,500 kVA, dry type, 480 V delta primary, 480 V wye secondary, K-4, electrostatic shield, 5.75 % impedance, NEMA 3R. The intent was to install between the solar array switchgear and the existing medium-voltage transformer.

The specification was, on its face, competent. Impedance sat within the manufacturer’s band. The K-rating was reasonable. The shield was correctly called for. Nothing in it would have caused a vendor to raise a query.

What the review found. 

Three issues, in ascending order of consequence.

The capacity was wrong for three of the four sites. At 480 V, 1,500 kVA is 1,804 A. A 2 MW inverter block draws 2,406 A continuously. The figure appeared to have been derived from the smallest site, where it was an exact match with zero margin, and then applied uniformly. Two of the four sites would have received a transformer overloaded by a third from the day of energisation.

The medium-voltage transformer nameplate — obtained as a photograph during the review — showed vector group YNyn0 with no delta tertiary. The site therefore had no zero-sequence trap anywhere between the inverters and the utility. This confirmed the designer’s instinct that a delta was required, but for a reason nobody had articulated, and it made the winding arrangement more consequential than anyone had realised.

Most seriously, the specification never stated which winding faced the array. Under the intended installation the inverters would draw their grounded-wye reference from the new transformer rather than from the medium-voltage unit. A vendor building delta-toward-the-array — a perfectly reasonable reading of "primary" — would have delivered four transformers that left the inverter side ungrounded. The inverters in question required a grounded wye source. The error would not have surfaced until commissioning.

Resolution. 

The specification was reissued with the winding arrangement stated in physical terms rather than by primary and secondary labels, capacity revised to 2,500 kVA at the larger sites, and a note added on the separately derived system obligations the new grounded wye would create. A rating conflict between the project’s stated capacity and the inverter schedule on the issued single-line was raised as a hold point before any order was placed.

Outcome

Four transformers correctly configured at first order. The winding-orientation error alone would have been discovered at commissioning across four sites, with replacement lead times measured in months against a construction programme with no float.

Case 2 — The reactor that solved the wrong problem

Situation. 

An operating site had been built with a line reactor as the resonance mitigation, selected on cost during value engineering and installed in the battery branch exactly as the manufacturer’s manual specified. The reactor was correctly sized and correctly located, and the resonance it was installed to address did not occur.

The site nonetheless generated persistent problems. Ground-fault indications appeared on the inverters during grid disturbances with no fault found on investigation. Harmonic alarms logged at the revenue meter. The utility raised a query about neutral current on the medium-voltage feeder.

What the analysis found. 

The reactor had been asked to do a job it does not do. It provided series impedance and detuned the resonant interaction, which was its purpose. It provided no galvanic isolation, no zero-sequence trap and no independent ground reference — and the site needed all three for reasons unconnected to resonance.

The medium-voltage transformer was a grounded-wye to grounded-wye unit without a tertiary. Triplen harmonics and zero-sequence unbalance passed directly between the 480 V collection system and the medium-voltage network in both directions. The inverters’ ground reference came through that same transformer, so every zero-sequence disturbance on the utility system arrived at the inverter terminals essentially unattenuated. The nuisance ground-fault indications correlated with utility-side events, which is why no fault was ever found on site.

The utility’s neutral current query had the same root. With no delta anywhere in the path, triplen currents from the collection system had nowhere to circulate and appeared on the medium-voltage neutral.

Resolution. 

A delta to grounded-wye isolation transformer was added in the solar branch, sized to the inverter block. The delta provided the zero-sequence trap the system had never had, the grounded wye gave the array a reference under the owner’s control rather than the utility’s, and the added series impedance reduced fault duty at the solar switchgear as a secondary benefit. The reactor was left in place; it was doing no harm and removing it would have required revisiting the manufacturer’s design review.

Outcome



Nuisance ground-fault indications ceased. The utility’s neutral current query closed. The cost of retrofitting a transformer into an energised site — outage, revised drawings, re-submission to the utility — substantially exceeded what the transformer would have cost at the original order, which is the general lesson of the case.

Case 3 — A specification that described the wrong machine

Situation. 

A three-page engineering design report and technical specification was circulated for review before being issued to transformer vendors. It was well presented, carried a calculation section, cited standards, and read as competent technical work. It was titled as a specification for an isolation and harmonic mitigating transformer.

What the review found. 

The threshold problem was that the document specified a 12.47 kV delta to 480Y/277 V liquid-filled pad-mount transformer with a 65 °C temperature rise and copper windings. That is a medium-voltage distribution transformer. The equipment actually under procurement was a 480 V to 480 V dry-type unit — a different class of machine on every defining parameter. A 65 °C rise is a liquid-filled parameter; dry-type units are specified at 80, 115 or 150 °C. Issued as written, vendors would have quoted a replacement for the transformer already installed on site.

More consequentially, the specified transformer would not have satisfied the battery manufacturer’s requirement under any reading. The medium-voltage transformer sits upstream of the common bus, outside the resonant loop between the two inverter systems. Placing a delta there does nothing to the impedance between them.

The calculation section contained errors that would not have survived utility review. A claimed K-factor range of 3.2 to 3.8 did not follow from the document’s own assumptions — 5 % distortion across the 5th, 7th, 11th and 13th orders yields approximately 1.1, and reaching 3.2 within those orders would require roughly 11 % at the 13th harmonic alone. The K-factor formula was written with harmonic current referenced to the fundamental rather than to rated RMS current, and omitted the fundamental term. A short-circuit figure on the primary side was labelled as available fault current when it was through-fault current referred to the primary. And a passage attributing the K-rating to prevention of "core saturation and thermal runaway" contradicted the document’s own correct statement of the eddy-current mechanism two paragraphs earlier — core saturation is a volts-per-hertz phenomenon, unrelated to harmonic load current.

Several conclusions were nonetheless correct. The 2,500 kVA rating, the K-4 selection, the delta winding for triplen trapping and the electrostatic shield were all the right answers. The derivations simply did not establish them.

Resolution. 

A severity-ranked review memorandum was issued identifying three critical findings, ten significant and four minor, with the correct value stated against each. The correct conclusions were carried forward into a reissued specification. The document was withdrawn before it reached vendors.

Outcome



The reissued specification produced comparable quotations for the correct equipment. The broader lesson concerned document provenance: the report had the characteristics of generated technical content — clean structure, confident tone, specific-looking figures that did not survive arithmetic checking. Any calculation entering a procurement or a utility submission should be independently verified regardless of how authoritative the source document appears.

10.  Where this usually lands

The isolation transformer question looks like a procurement item and behaves like a systems-engineering problem. The transformer itself is straightforward; what makes these projects difficult is that the decision sits at the intersection of three parties’ scopes and belongs cleanly to none of them. The battery manufacturer specifies a mitigation without knowing the array. The inverter manufacturer specifies a grounding requirement without knowing the system impedances. The utility imposes conditions at the interconnection without visibility of either.



The work that closes it is unglamorous and mostly arithmetic: aggregate the inverter ratings honestly, read the nameplate, run the symmetrical components, write the winding arrangement down in words that cannot be misread. None of it requires waiting for a measurement campaign, and all of it is cheaper than discovering the answer at commissioning.

11.  Frequently asked questions