A 132 kV power transformer needs an impedance specification that works with the network’s fault limits, voltage requirements, and operating arrangements. Lower impedance increases the current supplied through the transformer during a downstream fault. Higher impedance limits that contribution, but generally increases voltage drop under reactive loading. If transformers will operate in parallel, impedance also affects how much load each unit carries.

There is no universally correct impedance percentage for every 132 kV installation. The useful specification is a value, with an agreed tolerance, that satisfies the intended network configurations. Matching two nameplate percentages is only part of establishing parallel compatibility: voltage ratio, phase displacement, impedance angle, and tap control also matter.

What percentage impedance actually tells you

Transformer short-circuit impedance describes the opposition to current between a specified pair of windings. During its measurement, one winding is short-circuited and a reduced voltage is applied to the other until rated current flows. The required voltage, expressed as a percentage of the relevant rated voltage, gives the percentage impedance.

This is mainly the effect of winding resistance and leakage reactance. It is not the transformer’s no-load excitation impedance, and it does not mean that the stated percentage of input power is lost. Resistance produces load losses; reactance influences voltage drop and fault current without itself consuming real power.

An impedance value is meaningful only when its reference conditions are clear. These include the MVA base, winding pair, tap position, frequency, and reference temperature. For a transformer with multiple cooling ratings, establish which rating defines the impedance base. Comparing percentages quoted on different bases can produce a misleading assessment.

For a three-winding transformer, one percentage cannot describe every fault-current path. The study needs the relevant pairwise impedances and their stated bases. A tertiary winding may also affect zero-sequence behaviour, even when its normal load is small.

Estimating fault current without confusing the voltage sides

For an initial estimate of a balanced three-phase fault directly at the secondary terminals, assume an ideal upstream source, nominal voltage, and negligible connecting impedance. Under those assumptions:

Rated current: I_rated = S / (√3 × V)
Transformer-limited fault current: I_sc ≈ I_rated / z_pu
Per-unit impedance: z_pu = Z% / 100

Here, S is the transformer’s three-phase apparent-power rating and V is the line-to-line voltage on the side where current is being calculated. Use consistent units. The corresponding approximate fault apparent power is S / z_pu.

The voltage-side distinction matters. A transformer connected to a 132 kV network may feed a lower-voltage bus, where the current in amperes is much greater for the same apparent power. Using the 132 kV rated current to assess secondary switchgear duty gives the wrong result.

The inverse relationship provides a useful screening rule: reducing impedance increases the transformer’s fault-current contribution. However, this calculation estimates only the current passing through that transformer under the stated assumptions. It is not a complete prediction of total bus fault current.

For a network calculation, refer the source, transformer, and connecting impedances to a common voltage and power base. Add their resistance and reactance components as complex quantities. Adding impedance magnitudes arithmetically can distort the result when their impedance angles differ.

When converting between power bases at the same voltage base:

z_new = z_old × S_new / S_old

If the voltage base also changes, the conversion must include the voltage-base relationship.

The network conditions that change switchgear duty

A practical fault study includes upstream source strength, transmission lines, cables, other transformers, and connected generation. Motors may contribute during the initial fault period. Inverter-based generation requires an appropriate fault model because its current response depends on controls and current limits.

The strongest credible source condition usually matters for maximum fault duty. Minimum-source conditions matter for protection sensitivity: a relay must still detect and clear the relevant fault when available current is lower. Assessing only maximum current can therefore leave a protection problem unresolved.

Bus configuration can be just as significant as transformer impedance. Closing a bus coupler may connect another source path and raise total fault current. Where parallel transformers share an upstream source impedance, represent that common impedance explicitly. Simply doubling a single-transformer result can overstate or misrepresent the combined contribution.

The switchgear assessment should distinguish symmetrical RMS current, peak making duty, and the current associated with the required interruption time. The network’s X/R ratio affects the asymmetrical component and peak current. Two arrangements with similar symmetrical fault current can impose different mechanical duties.

Earth faults need a separate assessment. Positive-sequence impedance alone cannot describe them. Winding connections, neutral grounding, zero-sequence impedance, and any grounding resistor or reactor determine the available return paths. A delta winding changes zero-sequence current paths without preventing every earth-fault contribution elsewhere in the installation.

Higher impedance has a voltage-performance cost

Increasing transformer impedance may help keep downstream fault duty within equipment limits, but it affects load-flow performance. For a simplified lagging-power-factor load, the approximate voltage drop in per unit is:

ΔV ≈ I_pu × (r_pu cos φ + x_pu sin φ)

This shows why the resistance/reactance split matters. Reactive loading makes leakage reactance particularly influential. At leading power factor, the reactive term changes sign, so operating conditions can produce a voltage rise rather than a drop.

An on-load tap changer can compensate for steady operating voltage changes within its available range. It cannot eliminate impedance or guarantee acceptable voltage during disturbances. A design that controls fault current but exhausts its tap range under normal loading may be unsuitable for the intended network.

For a renewable-energy connection, evaluate import and export conditions, reactive-power requirements, and collector-system voltage limits together. The impedance decision must serve both the short-circuit study and the load-flow study.

Parallel operation: equal percentages do not guarantee equal loading

Parallel transformers must produce compatible voltages at the common bus. Relevant conditions include voltage ratio, polarity, phase sequence, phase displacement, and tap settings. Incompatible phase relationships can cause severe current when the connection is closed.

Matching vector groups is a straightforward starting point, but the actual phase relationships at the terminals govern compatibility. Transformer connections should be assessed as part of the complete bus arrangement.

Once voltage compatibility is established, load sharing depends on the impedance of each complete branch. This includes transformer impedance and the impedance of cables or bus connections between each transformer and the common bus.

With equal no-load secondary voltages, branch currents divide inversely with their complex impedances. If the impedance angles are sufficiently similar, the approximate apparent-power sharing relationship is:

S_load,1 / S_load,2 ≈ (S_rated,1 / z_pu,1) / (S_rated,2 / z_pu,2)

In this expression, each impedance is quoted on its own transformer rating. Equal percentage impedances therefore support loading approximately in proportion to the respective MVA ratings, subject to the other assumptions.

If one transformer has lower percentage impedance, it takes a greater share of load relative to its rating. It can reach its thermal limit while spare capacity remains in the other unit. Adding the two nameplate ratings does not automatically establish the usable capacity of the parallel bank.

Different X/R ratios further complicate sharing. Units with similar impedance magnitudes may divide active and reactive power differently. Compare resistance and reactance, or impedance magnitude and angle, when evaluating compatibility.

Tap mismatch creates current before useful load is supplied

A difference between transformer secondary voltage phasors drives circulating current through the loop formed by their impedances. In simplified form:

I_circulating ≈ ΔE / (Z₁ + Z₂)

The voltage difference and impedances must be referred to the same side. Circulating current consumes current capacity and increases losses even when external load is small. It combines with each unit’s load current, potentially reducing available capacity.

Identical tap-position numbers do not necessarily mean identical ratios. Transformers may have different tap steps, ranges, or winding arrangements. Compare the actual voltage ratios at intended operating positions.

Independent voltage controllers can also produce undesirable tap movements during parallel operation. The control scheme needs coordinated behaviour, such as a suitable master-follower or circulating-current control arrangement. Its design should address bus-coupler status, transformer availability, and the transition between separate and parallel operation.

Where photovoltaic transformers fit in a 132 kV connection

A photovoltaic plant may have several transformer stages: inverter voltage is raised to a collector voltage, and a separate main transformer connects that collector system to the 132 kV network. Their impedances belong in the same network model, but the units perform different duties.

Jinshida Electric’s Step-Up Transformer for Photovoltaic Power Stations is specified at 500–5000 kVA, with high-voltage options of 10, 20, or 35 kV. These ratings place it at the inverter-to-collector stage; they do not establish suitability as the main 132 kV transformer.

For this arrangement, assess faults at each relevant bus. Collector-transformer impedances affect local fault paths and voltage performance, while the main transformer influences exchange with the transmission network. Parallel-operation requirements apply wherever transformer secondary circuits are actually connected together. Sharing a collector network does not mean every inverter transformer forms a conventional parallel bank.

Turn the network study into a procurement specification

A procurement specification should give the manufacturer enough information to design against the intended operating duty. Requesting a preferred impedance percentage without its basis, tolerance, or network constraints leaves important decisions undefined.

IEC 60076 provides the relevant transformer framework, but a general reference to the series does not define every project requirement. The contract should identify applicable requirements, testing, acceptance criteria, and documentation. Impedance measurement and short-circuit withstand assessment serve different purposes: a satisfactory impedance result does not by itself demonstrate withstand