MV switchgear

What it is (precise)

Switchgear is an assembly, not a device, and its members are separated by exactly one question: what each one is allowed to interrupt. A circuit breaker makes and breaks load current and fault current, tested to IEC 62271-100. A switch-disconnector — the load-break switch — breaks load current and never fault current. A disconnector or earthing switch, to IEC 62271-102, does no interrupting at all; it establishes an isolating distance or a deliberate connection to earth after something else has cleared the circuit.

Fuses appear on the AC side too, in switch-fuse combinations to IEC 62271-105 using HRC fuses selected per IEC 60282-1: one catalogued vendor table puts a 31.5 A fuse on a 630 kVA transformer feeder and 63 A on a 2,000 kVA feeder at 35/36 kV. That is a different animal from DC string fusing, which sits behind the battery contactors and is covered in the fuse entry — an AC fuse interrupts at a natural current zero fifty or sixty times a second, and a DC fuse has no such help.

On a battery plant the assembly usually arrives as a ring-main unit, and the catalogued configuration is remarkably consistent between vendors. One MV power station datasheet specifies a 36 kV unit as SD-SD-CB: two cable feeders each with a switch-disconnector and earthing switch, plus one transformer feeder with a vacuum circuit breaker, its protection device, a disconnector and an earthing switch.

The cubicle families are ordered by a function letter that is worth learning before reading any rating table — in one widely used range, l is a feeder, p a fuse-protection cubicle, v a circuit-breaker cubicle, s a busbar switch, m metering, with compact double cubicles (2lp, 2lv) sharing a single gas tank. Read the letter first, then the rating column that belongs to it, because a feeder cubicle and a breaker cubicle in the same lineup do not carry the same numbers.

The physical interfaces matter more than they look. Cable feeders terminate on outer-cone bushings with clamps sized for a stated cable diameter range — 36 to 52 mm on one catalogued unit, three clamps per feeder — and the cable compartment carries its own earthing bar. Ratings, standards and accessibility all attach to the assembly as tested, not to the breaker inside it, which is why substituting a component or omitting an accessory at site is a change to the rating rather than a detail.

How it interrupts, and what it is insulated with

Two media get conflated in the same sentence and they do different jobs. Interruption is what happens between the contacts when they part under current: at medium voltage that is a vacuum interrupter, and the catalogued BESS circuit-breaker cubicles are vacuum units tested to IEC 62271-100. Insulation is what holds the compartment off from earth and phase from phase while nothing is happening, and in a sealed ring-main unit that is a gas.

The two coexist in the same box: the same catalogued unit is described as fully gas-insulated in a hermetically sealed stainless-steel tank and as a vacuum circuit breaker. Ingress ratings follow the split — one datasheet gives the gas vessel IP65 to IEC 60529 while the external enclosure is only IP2X, and an outdoor variant is offered at IP54 with IK10 impact and C5-class corrosion protection.

The insulating gas has been SF6, and the reason it is leaving is not electrical. SF6 is among the most potent greenhouse gases known — thousands of times the warming potential of CO2 per kilogram — with atmospheric persistence on the order of 3,200 years, and a fleet of sealed tanks leaks slowly for decades.

In the European Union, the revised F-gas Regulation phases SF6 out of new switchgear in stages by voltage class, with medium voltage first; California and other jurisdictions run their own schedules, and the installed base is generally allowed to serve out its life under handling and reporting rules. Thresholds and dates are jurisdiction-specific and keep being amended, so a specification should cite the current text for the market the plant is built in rather than a remembered date.

What is actually orderable in 2026 is narrower than the marketing suggests, and the catalogues say so plainly. One MV power station option list carries SF6 as the standard insulation with an SF6-free variant available in a single configuration — the three-feeder 24 kV unit — while every 36, 38, 38.5 and 40.5 kV option in the same list is gas-filled.

Another vendor's smart transformer station specifies Clean Air as its insulating medium outright. For a twenty-year asset the procurement questions are concrete: does the SF6-free version exist at the required voltage class and interrupting duty, what does it do to footprint and lead time, and who carries the end-of-life gas handling and reporting obligation if it does not.

Ratings against the fault study

Three current families appear on the same page and answer different questions, as the current entry sets out. Continuous rating is thermal: 400 or 630 A busbar and feeder ratings are the catalogued norm for BESS ring-main units, and the number moves with ambient — one MV station sheet quotes cable-feeder current as 630 A at 40 °C, 565 A at 50 °C, 530 A at 55 °C and 430 A at 60 °C, and adds that the interior of the station runs about 10 K above outside ambient, against a standard that allows a 24-hour mean of 35 °C.

Short-time withstand is survival, not interruption: Icw of 16, 20 or 25 kA for 1 s (3 s as an option) with the matching peak withstand Ip of 40, 50 or 62.5 kA. Short-circuit breaking capacity belongs only to the breaker cubicle — catalogued at 16, 20 or 25 kA at 36 kV on one vacuum range. Altitude is the third variable and the one most often skipped: indoor use to 2,000 m, or 6,500 ft on the ANSI sheet, before derating begins.

The comparison that actually gates the design is interrupting and withstand rating against the calculated fault current at that bus, for the study's clearing time. Here the BESS result is counterintuitive: the batteries contribute very little to it. An inverter-based resource feeds roughly 1.1 to 1.2 per unit of its own rated current into a fault, so the duty at the MV bus is dominated by the grid source behind the interconnection transformer, and a larger battery plant does not automatically demand a larger kA class.

What does inflate the number is arithmetic error — a transformer impedance dropped into the model on its own nameplate base rather than the study base, the factor the per-unit-system entry works through, propagates straight into breaker duties. Where a switch-fuse cubicle is used instead of a breaker, there is a further coordination check: the combination has a stated take-over current and transfer current — 490 A and 820 A at 36 kV on one catalogued unit — and no plausible fault current may fall in a band where neither device owns the clearing.

Internal arc classification is a fourth rating and a different concept from all three. IAC to IEC 62271-200 is a tested statement about the assembly's behaviour with an arc burning inside it: an accessibility type (A for authorized personnel only), then the faces qualified — F front, L lateral, R rear — then the current and duration, so IAC A FL 20 kA 1 s means front and lateral faces were tested at 20 kA for one second. Catalogued BESS units run from AFL 20 kA 1 s up to AFLR 25 kA 1 s, and one carries an IEEE C37.20.7 internal-arc rating at 25 kA for 1 s alongside the IEC figure.

Two conditions travel with the class and get lost at site. The rating holds only with the tested exhaust path installed — one datasheet's R class is explicitly conditional on the rear chimney being fitted, and outdoor cubicles are specified to vent to a trench or upward — and IAC is not an arc-flash incident-energy figure. In North America the approach boundary and the clothing a technician wears come from an IEEE 1584 study applied under NFPA 70E, calculated for the site, not read off the enclosure label.

The isolation points an O&M procedure depends on

Almost every MV maintenance procedure at a battery plant resolves to one sequence performed on this equipment: open, earth, prove dead, lock. The hardware exists to make that sequence hard to get wrong. A three-position switch-disconnector holds closed, open and earthed in a single mechanism with defined load-breaking capacity, so the switch and the earthing switch cannot both be closed. Mechanical and electrical interlocks enforce the rest, including blocking access to the cable compartment until the circuit is earthed, with keylock and padlock provisions for lockout/tagout.

Proof of absence of voltage comes from a voltage-presence indicating system to IEC 62271-206 and IEC 61243-5, typically capacitive indicators per feeder — some with an HF output that doubles as a partial-discharge measurement point. Auxiliary contacts on the breaker, switch-disconnectors and earthing switches report the achieved state back to SCADA, which is what makes a remote confirmation of an isolation credible.

The BESS-specific caution is that earthing the MV cubicle does not de-energize the plant. Strings remain live behind their own contactors and fusing, at full DC bus voltage, and the DC side has a separate isolation sequence with separate hardware — the battery-string and fuse entries cover it. Two device errors recur alongside that one.

A switch-disconnector may break load current but must never be asked to clear a fault, and a plain disconnector must not be opened under load at all; the single-line diagram article makes the same point about reading the symbols. And the isolation point named in a written procedure has to be the device the drawing actually shows, at the revision the plant was built to, or the procedure isolates something else.

Operating endurance is where a battery plant differs from a distribution feeder, and the classes on the datasheet say so. Catalogued figures run 1000-M1 mechanical for a manual load-break switch, 5000-M2 for the motorised version, electrical class E3, with earthing switches at M0/E2 and vacuum circuit breakers at M2 — 10,000 mechanical operations — and E2-C2; another sheet quotes M1/E1 to IEC 62271-100 for the same functional position.

A BESS does its switching in silicon several times a day, so the breaker's operations budget is spent on protection trips, maintenance isolations, and any configured reclosing or cascaded restart of the MV transformers rather than on dispatch. The C2 suffix earns attention where a feeder energizes long collection cable runs, since it is the class describing restrike performance when breaking capacitive current.

How it shows up in specs, studies and contracts

On the datasheet, six lines decide whether the unit fits. Rated voltage Ur against the system voltage — catalogued BESS ranges list 36, 38, 38.5 and 40.5 kV classes serving 33 and 34.5 kV networks.

Insulation level, and here the standards diverge at similar kV: 70 kV power-frequency withstand and 170 kV lightning impulse phase-to-earth at 36 kV IEC, against 150/165 kV impulse on the 38 kV ANSI sheet, so insulation coordination does not carry across standards by inspection. Continuous current stated at the ambient your enclosure actually reaches. Icw with its duration, matched to the fault study's clearing time.

IAC with its faces and its exhaust condition. And the insulating medium with its jurisdictional consequences. In studies, the chain is short and each link owns one deliverable: the fault study sets the kA, the coordination study sets the curves the relay executes through this breaker, and the arc-flash study sets what a technician wears.

One catalogued BESS ring-main unit parameterizes its relay on ANSI 50/51 and 50N/51N and requires inrush inhibition to be enabled on closing, because the skid's integral MV transformer draws magnetizing inrush that a fast overcurrent element will otherwise read as a fault.

Commissioning and contracts inherit the same list. Routine testing to IEC 62271-1 Clause 8 covers dielectric test on the main circuit, tests on auxiliary and control circuits, main-circuit resistance, tightness, and design and visual checks — tightness being the one that matters most on a sealed gas tank, where the pressure gauge is the only in-service window into the dielectric.

Commercially, the switchgear usually sits inside the balance-of-plant scope an O&M agreement covers rather than the battery scope an LTSA covers, so an availability loss traced to a switchgear trip lands on a different counterparty from a loss traced to the cells; write the interface matrix accordingly.

The pitfalls are a short list and all of them are single-number errors: quoting one continuous rating without its ambient, reading an internal-arc class as though every face were tested, specifying a load-break switch where the study requires an interrupting device, treating IAC as arc-flash PPE guidance, and assuming an SF6-free variant exists at your voltage class because it exists in the brochure.