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Home / Technical Articles / Eight criteria you should consider when choosing the right MV/LV transformer type

MV/LV distribution transformer

Although there are few common-sense rules that every electrical engineer follows when choosing the transformer type, it’s always a good idea to name the most important of them. This technical article will briefly explain the eight most common and essential criteria that will help in selecting the right MV/LV distribution transformer.

Eight criteria you should consider when choosing the right MV/LV transformer type
Eight criteria you should consider when choosing the right MV/LV transformer type

Ok, let’s name these eight criteria, and don’t be surprised we started with the cost. Unfortunately, like almost everything in electrical engineering world – everything starts with the money and the cost.

Table of contents:

  1. Cost
  2. Losses
  3. Reduction of insulation life
  4. Transformer impedance and short circuits
  5. Tappings on windings
  6. Connections
  7. Cable terminations
  8. Parallel operation of transformers

1. Cost

Money always matters. Figure 1 shows a cost comparison of the various transformer types. The SF6 and the cast resin are the most expensive and the mineral oil is the least expensive type. The cast resin type also has higher losses because of its more difficult thermal dissipation problems with thermal conduction being the only means possible for internal heat flow.

Comparison of costs of transformer types
Figure 1 – Comparison of costs of transformer types

In its most general application the cost of the transformer must include capital cost of installation and the cost of total losses amortized over the predicted life of the transformer.

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2. Losses

Table 1 shows an example of a comparison of total losses (including the variable copper and the fixed iron losses) in cast-resin and silicone-insulated transformers at various loadings. At a high load factor (80%) there is essentially no difference in total loss: at 50% loading the silicone oil transformer has lower losses (because of its inherently lower no-load losses).

Load factor is the ratio of average load to full rated load of the transformer.

Table 1 – Comparative losses of cast-resin dry type and silicone-oil transformers

no load
80% LF
50% LF
no load
80% LF
50% LF

Table 2 – Comparison of losses of different transformers types (For 1000 kVA, 11kV/415V)

TypeNo load1/4 load1/2 load3/4 loadFull load
Oil2.8No load2.8No load2.8No load2.8No load2.8
Dry-type, 150°C3.2No load3.2No load3.2No load3.2No load3.2
Epoxy dry-type3.2No load3.2No load3.2No load3.2No load3.2

Table 2 shows similar an example of comparison of losses with the other types of transformers. The liquid insulated units are seen to be generally better than the dry-type units particularly at high load factors.

Use of amorphous core transformers is starting to gain ground for small distribution units and they have much lower core losses than standard silicon-steel core transformers.

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3. Reduction of Insulation Life

During operation, the loading of the transformers is of particular importance as it determines the total losses and these, in turn, determine the operating temperature of, and hence any deterioration of, the transformer insulation.

If the insulation temperature rises to too high a level for its class, then the transformer lifetime may be reduced. The increased temperature causes increased chemical reactions in the insulation and these lead to the deterioration by changing the insulation composition.

As a general rule of thumb the 10° C rule is often used, whereby an increase of continuous operating temperature by 10° C causes a reduction of insulation life time by about 50%.

The loss of life versus temperature of operation details are given in typical loading guides for transformers which are published as Standards in most countries. For example, in Australia they are in the Australian Standards AS 2374.7 (oil-filled transformers) and AS 3953 (Dry-type transformers).

Both of these are replaced by IEC-based standards.

See Table 3 for some typical data that can be used to determine insulation deterioration (or lifetime reduction) if loading details and temperature rises are known.

Table 3 – Rate of deterioration of transformer insulation with change in operating temperature.

a) Increase in hotspot temperatureb) Reduction in hotspot temperature
Variation in hotspot temperature °CRelative rate of deteriorationVariation in hotspot temperature °CRelative rate of deterioration
0 1.0001.00
+ 11.12− 10.89
+ 21.26− 20.79
+ 31.41− 30.71
+ 41.59− 40.63
+ 5 1.78− 50.56
+ 62.00− 60.50
+ 72.24− 70.45
+ 82.52− 80.40
+ 92.83− 90.35
+ 103.17− 100.31
+ 113.56− 110.28
+ 124.00− 120.25
+ 134.49− 130.22
+ 145.04− 140.20
+ 155.66− 150.18
+ 166.35− 160.16
+ 177.13− 170.14
+ 188.00− 180.125
+ 198.98− 190.11
+ 2010.1− 200.10
+ 3032.0− 300.03
+ 40102.0− 400.01

The overall average operating temperature can be determined from a mean load factor K, which is derived from cyclic loading details of the transformers.

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4. Transformer Impedance and Short Circuits

As the transformer impedance will be a major part of the impedance of any short circuit path, the effect of the transformer impedance on prospective fault current in a power system is very substantial and thus accurate transformer impedance data is needed to allow such calculations to be performed to determine protection requirements.

In some cases where accuracy is not paramount, general impedance data such as that shown in Figure 6 can be used for fault current determinations involving transformers. As can be seen, an average value of 5% or .05 per unit for transformer impedance (Z) is a good and often used approximation.

Usually, the leakage inductance component is the major contribution to the impedance, particularly for high voltage transformers with their larger winding structure spacings.

For precise fault calculations the impedance must be known accurately from data given on the nameplate and the resistance and leakage inductance components must be known. The nameplate will generally give only total Z.

(a) Typical impedance and corresponding typical fault levels for various ratings (b) Effect of impedance on fault levels of 11kV/415V transformers
Figure 6 – (a) Typical impedance and corresponding typical fault levels for various ratings (b) Effect of impedance on fault levels of 11kV/415V transformers

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5. Tappings on windings

Distribution transformers used in buildings do not normally have on-load tap changing (OLTC) facilities to adjust voltage level. However they do have permanent taps which can be altered to allow about a ±10% variation in voltage output level, usually in about 1% steps.

The taps must be manually changed while the transformer is de-energised and isolated. The tapping points are normally on the high voltage windings only.

Figure 7 shows a large distribution transformer with on-load tap-changer. The tapchanger is at left of the three windings.

12.5 MVA cast resin transformer with on load tap changer
Figure 7 – 12.5 MVA cast resin transformer with on load tap changer (photo credit: SEA Trasformatori)

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6. Connections

In general, building distribution transformers are star-connected on the low voltage side to eliminate circulating triplen harmonics (3rd, 9th, 15th etc.) in a delta-connected three-phase winding. The high voltage side is almost always delta connected.

There are many possible variations of winding connections of transformers. These variations can affect the magnitude of the voltages but more particularly they change the phase shift between the primary and secondary windings.

There are about 20 different connections possible if the use of zigzag earths on transformers with delta windings is included, but the most common winding connections for standard distribution transformers are:

  • DY11
  • DY1
  • DY5
  • DY7

DY11 is the most commonly used connection for distribution transformers: it gives a 30° phase shift between primary and secondary.

See Fig. 8 for the corresponding vector diagrams and an explanation of phase shift symbols and phase shift values.

Different connections of windings in transformers and associated vector diagrams
Figure 8 – Different connections of windings in transformers and associated vector diagrams

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7. Cable terminations

Cable terminations to distribution transformers are generally achieved by means of a cable box on the transformer at the high voltage and low voltage sides for both types of transformer with paper insulated cable.

Figure 9 shows examples of medium voltage (11 kV) cable terminations. Note the use of skirts in some cases to increase creepage path lengths for cases where the termination is exposed to air and possible contaminants.

Example of medium voltage cable terminations
Figure 9 – Example of medium voltage cable terminations

The LV cable box is usually air insulated, but the high voltage cable box is compound-filled with petroleum grease or some similar viscous insulant.

Good sealing of the cable box is necessary to keep the moisture out. The modern preference for use of XLPE cable makes terminations in the cable box a little simpler in that moulded heat-shrink terminations are able to be used: these can be relatively easily applied for both high and low voltages.

Distribution transformer: MV cables connection box
Figure 10 – Distribution transformer: MV cables connection box

Paper insulated joints and terminations at high voltage are much more difficult to produce and require considerable expertise to achieve good results (that is, a joint without insulation problems).

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8. Parallel Operation of transformers

When transformers are used in parallel it is necessary to ensure that they satisfy the following requirements:

  1. Have the same voltage ratios
  2. The same tapping points in use (that is the same voltage)
  3. Have the same vector diagram (same phase shift between primary and secondary)
  4. The same impedance angle (this is preferable but not imperative).

If these conditions are not designed for, problems will occur. For example:

  1. There will be unequal loading of the transformers if the impedance angles vary. This can lead to overloading of one transformer and a lighter loading of the other. The same principles that apply to the sharing of load in parallel-connected feeders also apply to transformers.
  2. If the voltage ratio or the tapping points are not the same there will be circulating currents set up in the two transformers which will lead to possible overheating of the transformers and possible change in operation points on the magnetization curves.
  3. If the vector diagrams are different then the line and phase voltages will be intermixed and insulation stress will be stressed.
Single line diagram 3 - Substation with two transformers which operate in parallel on the same busbar
Figure 11 – Single line diagram of a substation with two transformers which operate in parallel on the same busbar

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Sources: Lecture in Industrial and Commercial Power Systems 

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More Information

Edvard Csanyi

Electrical engineer, programmer and founder of EEP. Highly specialized for design of LV/MV switchgears and LV high power busbar trunking (<6300A) in power substations, commercial buildings and industry facilities. Professional in AutoCAD programming.


  1. Davide Sensi
    Feb 15, 2022

    I’d say that the cost comparison is dated in the 90s since actual cost for oil filled transformers and cast resin transformers is practically equal

  2. Engr Moshood Akangbe Afolabi
    Oct 22, 2020

    What is the difference between vector groups Dyn1 and Dyn11 in terms of the transformer utilization?

  3. Radhakrishnan
    Apr 26, 2020

    Highly interested

  4. Audi Alfred
    Jan 30, 2020


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