Accessories and equipment for transformers. What's worth having on hand?

Anyone who has worked with transformers for more than one season knows this scenario.

The documentation checks out, the parameters are calculated, the handover passed without remarks.

The transformer is in place. It's operating. And for a long time, nothing happens.

Then one day, an alarm sounds, there's a smell of heated oil, or irritating vibrations spread through the entire station. That's when the sentence we all know is uttered:

But everything was brand new! 🤬

The problem is that a transformer is never a solitary device.

It's the center of a small ecosystem. Current, heat, vibrations, moisture, dust, mechanical stresses. They all circulate around it daily. Accessories aren't just aesthetic or catalog add-ons.

They are the tools that allow this ecosystem to remain stable.

This article is a map for thinking about which transformer accessories are worth considering from the start, because later they become the answer to questions that arise under stress, often after the fact.

Reading time: ~10 min

Why transformer accessories determine trouble-free operation

A transformer ages slowly and very consistently.

Insulation loses its properties with temperature.

Oil degrades faster if it's not monitored.

Mechanical vibrations, even minor ones, can over years cause more damage than a single overload.

These are processes you can't see at first glance.

That's why experienced operators say plainly: a transformer without monitoring accessories is a device operating in the dark. And working in the dark always ends in reaction instead of prevention.

In the following chapters, we'll go through the most important groups of accessories.

From electrical components, through temperature measurement and monitoring, to mechanics and cooling.

Each one addresses real problems that genuinely occur.

Insulators and connections, or the first line of electrical peace

It always starts with the connection.

And that's not a coincidence or a figure of speech.

All the electrical systems in the world, regardless of voltage and power, boil down to one question:

how to safely and stably transfer energy from one element to another?

Cable, busbar, transformer termination.

It is precisely at this point that two orders, which by nature don't get along, meet.

The electrical order and the mechanical order.

On one hand, we have voltage, electric field, current, temperature.
On the other, mechanical forces, vibrations, thermal expansion, the weight of conductors, and movements resulting from the operation of the entire system.

The insulator is the element that must reconcile these worlds.
It must provide electrical insulation while simultaneously transferring mechanical loads.
It must maintain the geometry of the connection while preventing discharges.
It must be invisible in daily operation but absolutely reliable for years.

It is precisely at these connection points where problems most often begin, remaining hidden for a long time.
Local overheating due to insufficient contact pressure.
Surface micro-discharges that don't yet trigger protection but already degrade the insulation.
Slight loosening of connections caused by heating and cooling cycles.

The transformer as a whole may appear healthy, while its weakest points are operating at the edge of tolerance.

In the case of medium-voltage cable terminations, the method of securing the conductor is fundamental. A cable is not a static element. It changes its length with temperature, transmits vibrations, and is sometimes subjected to additional installation stresses. If the connection lacks controlled pressure, contact resistance appears.
And where there is resistance, heat appears.

In practice, the question often arises: what insulator to choose for a medium-voltage cable termination?

In such cases, medium-voltage cable terminal insulators are used, which provide a stable connection and controlled conductor pressure. Their task is not just electrical insulation.
They actively stabilize the connection.

They ensure uniform and repeatable conductor pressure, regardless of whether the installation is operating in winter at low temperatures or in summer under full load.
This solution is particularly important in stations where cables are long, heavy, or routed in a way that generates additional mechanical forces.

A well-chosen insulator with a terminal ensures the connection maintains its parameters not just on the day of handover, but also after 5 or 10 years of operation.

In installations based on busbars, the problem looks somewhat different.

A busbar is rigid, massive, and transmits much greater forces.
There is no room for random tolerances here.
Precision in positioning and resistance to vibrations resulting from high current flow and electrodynamic phenomena are what count.

Insulators with busbar clamps serve as precise support and guide points.

They maintain a constant system geometry, prevent busbars from shifting, and protect connections from loosening. Thanks to them, contact parameters remain stable even during prolonged operation under high load. This is especially important in industrial installations where a transformer doesn't operate occasionally, but daily, often close to its design limits.

Oil-air bushings are a separate category.

They are responsible for one of the most difficult tasks in the entire transformer.
Safely transitioning voltage from the oil-filled interior to the outside, to the air environment. In this single element, different dielectrics, different tempreatures, and different environmental conditions meet.

An oil-air bushing must be sealed, resistant to aging, contamination, and moisture.

Any weakening of its properties can lead to surface discharges, and in extreme cases, to a loss of the transformer's seal. Silicone versions are increasingly chosen today because silicone handles contamination, rain, UV radiation, and variable weather conditions excellently. Even when the insulator's surface isn't perfectly clean, silicone retains its dielectric properties.

This is precisely why silicone oil-air bushings have become the standard in modern transformer stations. Not because they are trendy, but because they better withstand the real world.
And the real world, as we know, is rarely laboratory-clean ;-)

In environments requiring particular mechanical flexibility, EPDM (Elastimold) insulators are also used. EPDM is, in simple terms, a special type of technical rubber, designed to work where ordinary materials would quickly give up. It's not soft rubber like in a tire nor brittle like plastic. It's an elastomer, i.e., an elastic material that, after deformation, returns to its shape and doesn't lose its properties for years.

You could compare it to a very durable seal that doesn't harden in the frost, doesn't crack in the sun, and doesn't crumble over time. EPDM withstands continuous vibrations, temperature changes from frost to high heat, and the effects of moisture and ozone present in the air.

In practice, this means that components made of EPDM don't 'age nervously'.
They don't crack suddenly, don't lose elasticity, and don't require frequent replacement.
Therefore in compact transformer stations and prefabricated solutions, where everything works close together and is subject to constant micro-movements, EPDM performs significantly better than rigid insulating materials.

Tapered bushings, or safe passage through the housing

A tapered bushing is a component rarely talked about until it starts causing problems.

And it is precisely this component that is responsible for one of the most critical points in a transformer:

the passage of voltage through the housing.

Leaks, micro-cracks, improper installation.

Any of these factors can lead to moisture ingress into the insulation and, consequently, to accelerated transformer aging.

That's why tapered transformer bushings are no place for compromises.

A well-chosen bushing ensures electrical stability, oil tightness, and mechanical strength. In practice, its quality directly translates to the lifespan of the entire device.

In many cases, upgrading the bushing solves problems that were previously attributed to the windings or oil.

Oil and winding temperature, or what really ages a transformer

If there is one parameter that most affects a transformer's lifespan, it's temperature.

A transformer doesn't wear out because it's old.

It wears out because it's too hot.

Sometimes just a little too hot, but for long enough.

In the physics of electrical insulation, there is no mercy or romanticism. There is temperature and time. The rest are consequences.

For decades, it has been known that every increase in winding temperature above the design value dramatically accelerates insulation aging. Every 6 to 8 °C above the nominal operating temperature can halve the insulation's lifespan.

This isn't a textbook curiosity; it's hard operational reality.

For a transformer, this means a reduction in life not by a few percent, but by half.

And most interestingly, this process happens quietly. Without sparks, without noise, without an alarm at startup.

The oil in a transformer cannot be treated solely as an insulating medium.

It is primarily a carrier of information about the device's condition. Its temperature speaks volumes about what's happening inside, even when the windings are still invisible and inaccessible. Therefore, measuring the oil temperature is not an add-on or a premium option. It's an absolute minimum if we want to know how the transformer is really performing.

The simplest and still very effective form of control is transformer oil temperature indicators. Mechanical, without electronics, resistant to environmental conditions. Their huge advantage is immediacy.

A single glance is enough to know whether the device is operating within a safe range or is starting to approach limits that are better not exceeded too often.

When the installation becomes more demanding and loads variable, information alone is no longer enough. This is where temperature controllers, such as the CCT 440, working with PT100 sensors, come into play. This is no longer just measurement. This is temperature management.

Automatic cooling activation, alarm signals, the possibility of integration with a superior system. The transformer stops being mute and starts actively communicating its state.

PT100 sensors for transformers have become standard for a reason.

They are stable, precise, and predictable.

They can be used for both oil temperature measurement and direct winding measurement.

It is precisely they that provide the data which allows for a reaction earlier, before elevated temperature turns into a real operational problem.

DGPT2 Monitoring and RIS Systems - or when a transformer starts to speak

A transformer communicates with its surroundings constantly.

It never operates in silence. It is always signaling something.

It changes oil temperature, reacts with increased pressure inside the tank, generates gases resulting from insulation aging or local overloads.

These phenomena occur regardless of whether anyone is observing them.

The problem is that without appropriate sensors, these signals remain unnoticed.

For the transformer, this is its natural language. For a person without monitoring, it's just background noise.

And it is precisely in this space between phenomenon and information where failures occur, later labeled as 'sudden'.

The DGPT2 system is a classic protective and measuring device used in oil-immersed transformers.

It monitors three basic parameters: Gas, Pressure, and Temperature.

The presence of gas signals processes occurring in the oil and insulation.

A rise in pressure informs about dynamic changes inside the tank.

Temperature allows for assessing the transformer's thermal load.

DGPT2 operates locally and provides clear alarm signals or triggers protective actions.

The RIS system, on the other hand, is a strictly monitoring solution focused on observing trends and analyzing the transformer's condition over time.

It collects data, archives it, and enables interpretation without the need to shut down the device.

Thanks to this, an operator can see not only that a parameter was exceeded, but also how it happened. Whether the temperature rose gradually or suddenly. Whether pressure changes are one-off or repetitive.

Not long ago, both DGPT2 and RIS systems were mainly associated with large transmission stations. Today, they are increasingly used in medium-sized industrial installations and renewable energy farms.

The reason is simple and very pragmatic.

Installation downtime costs more than a monitoring system.

Thanks to such solutions, the operator doesn't learn about a problem at the moment of failure or protective device operation.
They learn earlier, when they still have time to make a decision.
They can schedule maintenance, adjust the load, or check cooling conditions.

The transformer ceases to be a black box and starts being a device that speaks before it starts screaming.

Vibrations and mechanics, the signs of a transformer's life

A transformer vibrates.

Always.

Even a brand new one, fresh after handover, that still smells of paint.

This is not a factory defect or a sign of problems.
The magnetic field, electrodynamic forces, and the core's operation cause the device to live by its own, very subtle rhythm. This isn't visible in catalog data, but it's audible and tangible in the real world.

The trouble begins when these natural vibrations don't stay where they should.

Instead of dissipating within the transformer's structure, they travel further.

To the foundation, to the station housing, to building walls, and sometimes even to neighboring equipment. Then a faint humming appears, followed by irritating noise, and after years, minor cracks, loosened bolts, and components that have... simply shifted apart.

Vibration damping pads for transformers are one of those accessories that rarely impress at the project stage but earn huge points during operation.

They act like shock absorbers. They isolate vibrations from the rest of the structure, reduce noise, and ensure the foundation doesn't have to participate in every impulse of the transformer's work.

It's a simple, somewhat underappreciated, and very effective solution.

In many facilities, it's precisely the lack of vibroacoustic separation that turns out, after years, to be the cause of mechanical problems described with one word: wear and tear.

And the truth is often more prosaic. The transformer was simply gently reminding everyone of its existence the whole time, and no one gave it pads so it could do so more quietly.

Ventilation and cooling, or when nameplate power meets summer

Every transformer has its proud rated power listed in the documentation.

The numbers match, the calculations too. The problem is that these values are very often derived under conditions with only moderate connection to reality. A friendly ambient temperature. Proper ventilation. No heatwaves, no dust, no enclosed station standing in full sun.

And then summer comes.

Concrete heats up like a frying pan. The air in the station stands still.

The transformer does exactly what it always does: dissipates heat.
Only suddenly, it doesn't really have anywhere to put it.

And here begins the real verification of nameplate power.

Transformer overheating rarely starts dramatically.

First, there are a few extra degrees on the oil. Then more frequent fan operation, if there are any at all. Sometimes the need arises to limit load during peak hours.

Seemingly nothing serious, but each such episode adds its brick to the accelerated aging of the insulation.

AF fans for transformer cooling are the answer precisely for this moment when theory meets climate. Their task is simple and very specific. To increase heat exchange where natural convection is no longer sufficient.

Without interfering with the transformer's construction, without replacing it, without a revolution in the design.

That's why AF fans are used both in new installations, as a planned element from the start, and in the modernization of existing stations.

They often appear where a transformer is technically sound, but its operating conditions have changed over time. Greater load. A different consumption profile. Higher ambient temperatures than a decade ago.

In practice, it's precisely additional cooling that very often solves a problem that previously seemed serious.

Instead of constantly balancing on the edge of its power rating, the transformer returns to calm operation.
Instead of plans for costly replacement, reasonable support for heat dissipation is enough.

Cooling doesn't magically increase a transformer's power.
It allows it to safely utilize what it already has.

And in operation, that can be the difference between comfort and constantly worrying if it's going to be too hot again today.

Accessories as a system, not an add-on

The biggest mistake in approaching transformer accessories is treating them like a list of options to tick off at the end of a project. One here, another there, just to have them.

Meanwhile, in real operation, they don't work separately.

They cooperate. They form a system of safety, control, and daily operational comfort.

Insulators ensure energy has a stable path.

Bushings guard the boundary between the interior and the external world.

Sensors and monitoring provide information before a problem appears.

Vibration pads and fans take care of mechanics and temperature, things that work continuously, even when no one is looking.

Each of these elements addresses a very specific situation that, in practice, happens more often than we'd like.

A transformer equipped with such accessories isn't more complicated.

It's simply more resilient to reality. To summer, to variable loads, to vibrations, to time. And time, as we know, is the most demanding test for any installation.

If you've made it to this point, it means you think about transformers not as catalog objects, but as systems that need to work for years.

At Energeks, we believe in a partnership approach. We don't look at a transformer as a single device taken out of context, but as an element of a larger system that must operate stably for years. That's why, when designing and selecting transformers, we always consider the operating conditions, future load, and the realities of operation.

If you want to see which transformers and system solutions best fit your installation, we invite you to explore the Energeks offer.

And if you'd like to stay longer, exchange knowledge, and see what the world of transformers really looks like behind the scenes, join us on LinkedIn.

This blog is an invitation to systems thinking. And to further conversations.

Sources:

C57.143-2024 - IEEE Guide for Application of Monitoring Equipment to Liquid-Immersed Transformers and Components

IEC 60076-1: Power Transformers - General Standard via studylib.net

Winter is when everything comes to light.

For most of the year, the installation works correctly.

The oil transformer has a power reserve. Voltage stays within limits. There are no complaints, no alarms, no phone calls from users.

And then the first cold wave hits, and suddenly something no one planned for begins to happen.

Flickering lights. Notifications about voltage being too low.

Heat pumps that shut down exactly when they are needed most.

In the background, a transformer that according to the documentation "should handle this," but in reality is operating on the edge of stability.

This isn't a story about faulty technology.

It's also not a tale of user errors.

It's a story about the collision between a new way of using energy and infrastructure that was designed under completely different circumstances.

Heat pumps have changed the network load profile.

They did it quickly, massively, and often without a parallel shift in thinking about medium voltage transformers. The annual energy consumption still adds up. The nameplate power looks reasonable.

And yet, in winter, voltage drops, alarms, and questions arise that are difficult to answer in a single sentence.

Why do problems start precisely when the temperature drops below zero?
Why does an oil transformer, which operates calmly in summer, react completely differently in winter?
And why does the classical approach to power rating selection stop being sufficient in a world of mass-scale heat pumps?

This article was created to organize these phenomena.

Without scaremongering about failures. Without oversimplifying the physics. Without shifting blame to one side.

We will show what the load generated by heat pumps really looks like during the heating season, how an oil transformer reacts to it, where voltage drops occur, and why they are not random.

And what can be done before the only answer becomes a costly modernization.

If you are responsible for the network, a project, a facility, or investment decisions, this text will help you look at the problem from a broader perspective. One that considers both the technology and the real operating conditions.

Reading time: approximately 13 minutes

How heat pumps really stress the grid in winter

In summer, a heat pump is almost invisible to the grid.

It operates sporadically, mainly for domestic hot water. Its momentary power draw is moderate, and its load profile blends into the background of other consumers. An oil transformer sees it as just one element among many in the landscape.

In winter, the situation changes radically.

The heat pump stops being an add-on. It becomes the primary source of thermal energy, and therefore a device operating for long periods, intensively, and often in sync with hundreds of other similar installations on the same network.

One key word here is: momentary power.

Project documents most often analyze annual consumption. The kilowatt-hours add up, the SCOP coefficients look good, and the energy balance seems reasonable. The problem is that a transformer doesn't see kilowatt-hours. It sees amperes, here and now.

And in winter, "here and now" looks different than in summer.

When the temperature drops below zero, the demand for heat increases. The heat pump's compressor runs longer and more frequently. Its momentary efficiency drops, so generating the same amount of thermal energy requires more electrical energy. Add to this the defrost cycles of the evaporator, which generate short-term but repetitive power draw spikes.

On the scale of a single house, this still looks innocent.

On the scale of a housing estate, a facility, or an area supplied by one MV/LV transformer, the cumulative effect begins.

Everyone heats at the same time.

The coldest days mean peak load occurs at exactly the same morning and evening hours. The grid has no time to "breathe," and the transformer enters prolonged operation near the limits of its thermal and voltage capabilities.

This is where the first paradox appears, which often surprises investors and designers.

An oil transformer may not be overloaded in terms of power, yet it can still cause problems.

Why?

Because the problem isn't always exceeding the nameplate rating. Often, it is the voltage drop resulting from the nature of the load.

Heat pumps, especially inverter-driven ones, are not linear loads. Their current draw changes dynamically. At low temperatures, the current on the low-voltage side increases, and every additional ampere means a greater voltage drop across the transformer's impedance and the supply line.

In summer, the same transformer operates at a higher secondary voltage, lower current, and with a large regulatory margin. In winter, that margin disappears.

If we add to this networks designed decades ago with the assumption that the main loads would be lighting, appliances, and occasional electric heating, the picture becomes clear.

This isn't a failure.

This is a change in boundary conditions that the infrastructure simply wasn't designed for.

In the next part, we'll take a closer look at how an oil transformer reacts to such a load from a physics perspective. Without myths about "overheating in winter" and without magical explanations. Only what really happens in the core, windings, and oil when the grid starts breathing frost.

What really happens inside an oil transformer during a frost

From the outside, a transformer looks the same in July and January.

The same enclosure. The same oil. The same parameters on the nameplate.

The difference begins on the inside.

An oil transformer does not react to winter in an intuitive way. The low ambient temperature is not a problem in and of itself. Quite the contrary. Cooling is more efficient then. The oil dissipates heat to the surroundings more easily, and the thermal headroom seems larger than in summer.

And it's right here that a false sense of security is born.

Because in winter, the problem is not the transformer's temperature. The problem is voltage and current.

When the load on the low-voltage side increases, the current in the windings rises. Along with it, copper losses—proportional to the square of the current—increase. This phenomenon is well known and accounted for in design.

But simultaneously, the voltage drop across the transformer's impedance increases.

Every transformer has its short-circuit impedance. This is not a flaw or a random feature. It is a design parameter that determines how the transformer will behave under load and during a short-circuit.

The greater the current, the greater the voltage drop.

In summer, this drop is hardly noticeable. In winter, under prolonged load close to peak, it begins to be felt by the connected equipment.

Heat pumps are particularly sensitive to this.

The inverters controlling the compressors have their own lower voltage thresholds. When the voltage drops too low, the electronics react immediately. First, it limits power. Then it goes into an alarm state. Finally, it shuts the device down.

From the user's perspective, this looks like a random failure.
From the transformer's perspective, it's a logical consequence of operating under conditions the network wasn't designed for.

A further domino effect occurs.

When some heat pumps shut down due to low voltage, the load temporarily decreases. The voltage bounces back up. The devices attempt to restart. The inrush current appears simultaneously at many points in the network.

The transformer receives a series of load impulses that further destabilize the voltage.

This is not an overload in the classical sense.

It is an operational instability resulting from the nature of the loads and their synchronization.

This often leads to a question about the transformer's tap changer.

If the voltage is dropping, maybe it's enough to raise it.

Sometimes this helps. Sometimes it just shifts the problem elsewhere.

Raising the secondary voltage increases the margin for heat pumps, but it also raises the voltage during hours of lighter load. This can lead to exceeding permissible voltage levels for other consumers. Especially where the network is short and has low impedance ("stiff").

A transformer does not operate in a vacuum. It is a part of a system.

If the system has changed, the transformer begins to reveal its weak points.

In the next part, we will examine why classical methods for selecting transformer power ratings are becoming insufficient in a world of mass-scale heat pumps and what warning signs appear long before the first winter alarm.

Why the classical power rating selection method stops working

For years, everything was logical and predictable.

Selecting a transformer was based on installed power, simultaneity factors, and annual energy consumption. Add a small safety margin—sometimes 10 percent, sometimes 20. In most cases, that was enough.

Because the loads were passive and spread out over time.

Lighting, motors, household appliances. Each had its own operating rhythm. Even if several devices turned on at the same time, the scale of the phenomenon was limited.

Heat pumps have changed this order.

Not because they are faulty. Not because they draw "too much current." They changed it because they introduce a strong temporal correlation of load.

When it gets cold, they all want to run. At the same moment. For many hours without a break.

Classical simultaneity factors begin to lie. On paper, everything adds up. In reality, the network sees nearly the full load for a long time, not short inrush peaks.

Another element, often overlooked in analyses, comes into play.

A transformer is selected based on active power. Winter problems very often start with reactive power and the nature of the current.

The inverters in heat pumps improve the power factor (cos φ), but they don't completely eliminate current distortions. Harmonics, especially lower-order ones, increase the effective current without a proportional increase in active power. The transformer sees a greater current load, even though the energy meter doesn't show it directly.

This is another reason why "the kW adds up," but the voltage drops.

In practice, this means a transformer selected perfectly according to the old methodology can operate in winter under conditions no one considered. Not as a short-term exception, but as a new norm.

The first warning signs appear early.

They are not failures or protection tripping.

They are subtle symptoms that are easy to ignore.

Voltage at the lower limit of the norm in the morning hours. An increased number of voltage alarms in the inverters. User complaints that "something sometimes flickers." Logs from monitoring systems showing long periods of high load without distinct peaks.

This is the moment when the network is still working. But it has no margin left.

Many investment decisions are made only after the first serious problem appears. In winter, under time pressure, user dissatisfaction, and weather conditions. This is the worst possible moment for a calm analysis.

That's why, in the next part, we will move on to what can be done earlier.

What diagnostic tools truly provide answers, how to distinguish a power problem from a voltage problem, and when a transformer is actually undersized, versus when it's simply poorly matched to a changed network.

What to check before a real problem begins

In winter, the network doesn't forgive illusions.

If the first signs of instability appear, it means physics has already sent a warning signal. It's just not screaming yet.

The most common mistake is trying to answer with a single parameter. Transformer power rating. Cable cross-section. Protection setting. However, winter problems rarely have a single cause.

It starts with measurements. But not the kind that last a few hours on a random day.

A seasonal picture is needed.

Load profiles from summer and winter periods. At least several weeks of data. Preferably with fifteen-minute or shorter resolution. Only then can you see whether the load is impulsive or continuous. Whether the voltage drops slowly or collapses sharply at specific times.

A transformer rarely lies. It simply shows what the network is doing to it.

The next step is to analyze voltage at several points in the low-voltage network, not just at the transformer terminals. The voltage drop at the transformer might look acceptable, while at the end of a supply line it exceeds permissible limits.

This is especially important where heat pumps have been added to existing buildings without upgrading lines and distribution boards.

It's also worth looking at what happens with reactive power and effective current.

If the current rises faster than the active power, it's a signal that the transformer is being loaded in a way that isn't visible in standard energy consumption summaries. Harmonics, phase imbalance, and uneven switching of loads can eat up the margin faster than you think.

A frequently overlooked element is voltage regulation.

Transformer tap settings are often based on historical conditions, from before the facility's modernization. Changing one tap step can improve the situation in winter, but only if preceded by an analysis of voltages across the entire load range. Otherwise, the problem will shift to summer.

This brings us to an important distinction.

Not every winter problem means the transformer is too small.

Sometimes its power rating is sufficient, but it's operating in a network with too high impedance. Sometimes it's correctly sized, but the load is too strongly time-correlated. And sometimes the limit has indeed been exceeded, but no one wanted to call it by its name earlier.

A good diagnosis allows you to choose the right tool.

Upgrading the transformer is one of them. But it's not always the first, nor the most sensible, option.

We've covered this topic in more detail in a separate article:

Renovate or replace? The last chance for your transformer!

In the next part, we'll show which action scenarios are realistic in practice. From the simplest operational adjustments, through changes in network configuration, to investment decisions that only make sense when they are based on data, not winter panic.

How to design and operate transformers in a world of heat pumps

The biggest change in recent years hasn't been about the transformers themselves.

It's about the way we think about the network.

For decades, design was an attempt to predict averages. Average consumption. Average peaks. Average customer behavior. This model worked as long as appliances had different rhythms and didn't respond en masse to the same stimulus.

Heat pumps respond to temperature. Simultaneously. Without negotiation.

This means the network must be designed for extreme scenarios, not just for the annual balance.

A transformer ceases to be merely a source of power. It becomes an element of voltage stabilization under conditions of prolonged load. This changes the selection criteria.

Increasing importance is placed not only on the nameplate rating, but on the transformer's impedance, its voltage regulation characteristics, and its cooperation with the rest of the infrastructure. Two transformers with the same power rating can behave completely differently in winter if they have different short-circuit impedances or different regulation capabilities.

Operation also requires a new approach.

Instead of reacting to failures, it's worth observing trends. Are minimum voltages dropping year by year? Is the operating time under high load lengthening? Is the number of power electronic loads growing faster than assumed?

These are signals that appear long before a crisis.

A well-designed network with oil transformers is not afraid of winter. It has a margin. It has flexibility. And above all, it has the awareness that the way energy is used has already changed and will not return to the state before mass-scale heat pumps.

Therefore, the key question today is not: will the transformer survive this winter?

The question is: will it still operate stably in five years within a network that is increasingly reactive to weather, automation, and simultaneity?

If the answer isn't clear, the best time to act is now. Calmly. With data. Without winter panic.

Because winter will always come. And the network should be ready for it before it gets truly cold.

In the end, it's worth putting a period in a place that doesn't close the topic, but opens up possibilities.

Today, the oil transformer is no longer a passive piece of infrastructure.

In the reality of mass-scale heat pumps, it becomes a tool for conscious management of voltage, losses, and network stability. A well-chosen, properly configured unit that meets current Ecodesign Tier 2 requirements — like the MarkoEco2 from Energeks — can regain the margin that is most sorely missed in winter. Not through oversizing, but through better power quality, lower load losses, and a true match for modern operating profiles.

Our current transformer offering has been designed precisely for such scenarios, where the network must operate stably not only today but also in the heating seasons to come.

It includes both oil transformers, proven in demanding operating conditions and resilient to prolonged winter loads, and dry-type transformers, chosen where fire safety, environmental conditions, or indoor installation are of key importance.

In both cases, the starting point is the same. Voltage stability, low losses, compliance with current energy efficiency requirements, and a genuine fit for modern load profiles—where heat pumps are no longer the exception, but the norm.

Thank you for your time and attention. If you are interested in such analyses, real project experiences, and thoughtful conversations about how the energy sector is changing from within, we invite you to our community on LinkedIn.

Sources:

International Energy Agency (IEA)

https://www.iea.org/reports/the-future-of-heat-pumps

ENTSO E

https://www.entsoe.eu/publications/system-development-reports/

2025. The year theory stopped being enough

The year 2025 did not bring a single, great technological breakthrough.

No miracle material appeared. Physics didn't change. No new law of electrical engineering was discovered.

Instead, something much less spectacular but far more painful happened.

Reality started to test assumptions.

Those that had worked "well enough" for years suddenly stopped holding up.

Projects copied from previous years began to fall apart during the execution phase. Budgets that were supposed to balance on paper started to leak in areas previously considered safe. Schedules based on standard solutions had to be corrected mid-game.

And it quickly became apparent that the transformer was no longer just part of the background.

In 2025, the transformer became a topic of conversation on construction sites, in design offices, and at investors' tables. It appeared in questions about energy losses, compliance with Ecodesign Tier 2, real operating costs, dimensions, logistics, and acceptance procedures. Increasingly, not as an isolated problem, but as an element that could decide the success of an entire project.

This was the year theory was invited onto the construction site. And it didn't always come out unscathed.

This text is not a product summary. It is a summary of experiences.

It is an attempt to gather conclusions from a year that very effectively separated convenient assumptions from true ones. It is written with designers, contractors, and investors in mind who don't want to enter 2026 relying on memory or shortcuts. Only with greater peace of mind and better insight.

Because if 2025 taught the energy industry anything, it's that not everything that worked yesterday works just as well tomorrow.

We didn't ask which transformer is the best. We asked which one stopped being a problem.

We are not creating a ranking. We are not selling promises. We are looking at the tensions that emerged in 2025 between regulations, physics, and budgets. We examine where theory diverged from practice and what decisions began to win out in real projects.

This is a story about losses that suddenly started to matter.

About power that stopped being just a number in a table. About documentation that could either save or stall an investment. And about why, in 2026, the question is no longer "what is the most powerful," but "what provides predictability."

Reading time: ~11 minutes

Ecodesign Tier 2 Stopped Being Theory. It Became a Reality Filter

Just a few years ago, Ecodesign Tier 2 was mainly a future concept in the industry.

Something that would "come into effect," "be mandatory," "need to be considered." In 2025, this mindset stopped working.

Tier 2 ceased to be a clause in a directive. It became a very practical filter through which real projects either started to pass or began to fail.

On paper, everything looked simple.

Lower no-load losses, better efficiency, compliance with the regulation. In practice, 2025 showed that not every transformer that "almost meets" the requirements actually meets them in the context of a specific installation. Differences of a few watts in no-load losses, previously ignored, started to matter. Not because everyone suddenly fell in love with efficiency.

But because energy stopped being cheap background noise and became a real cost.

In many projects, Tier 2 exposed old design habits.

Selecting a transformer "by eye," based on previous projects, stopped being safe. Solutions that had passed acceptance for years without major questions began to raise doubts in 2025. Additional queries, clarifications, and corrections appeared. Sometimes at the design stage, sometimes during execution, which always hurts more.

The problem wasn't the regulation itself.

It was that Tier 2 forced a confrontation with the transformer's actual operating profile. No-load losses, previously treated as a "fixed and negligible" cost, began to be analyzed on a yearly scale, not just at the moment of acceptance. In installations where transformers operate at low load most of the time, it suddenly turned out that these very losses determined the economics of the solution.

2025 also showed that not every project is equally ready for Tier 2.

In new installations, it was easier to incorporate the requirements from the start. In modernizations and expansions, the situation was often more complicated. Space constraints, existing infrastructure, and previous design assumptions could clash with the new requirements in a very unpleasant way.

Added to this was the issue of availability.

Last year, the market felt very clearly that a Tier 2-compliant transformer is not always an "off-the-shelf" item. Lead times, logistics, and delivery planning began to have a real impact on investment schedules. Projects that didn't account for this in advance often had to make up for lost time in other areas or postpone deadlines.

Another interesting phenomenon was how the narrative around Tier 2 changed.

The question "do we have to?" disappeared, and the question "how to do it sensibly?" appeared. Conversations increasingly focused not just on meeting the standard, but on the consequences of choosing a specific solution.

How will it affect losses in the long term? What about servicing? And future load changes?

In this sense, Ecodesign Tier 2 did the industry a favor. It didn't simplify life.

But it forced thinking in holistic, not just formal, terms. And it quickly became clear that in 2026, Tier 2 will no longer be a topic for discussion. It will be the starting point.

We wrote about no-load losses in Tier 2 and their translation into specific financial figures here—it's worth familiarizing yourself with this knowledge:
No-load losses in Tier 2 transformers. How to calculate the real cost?

Nameplate Rating Versus Real-World Usage

If one assumption was tested with particular harshness in 2025, it was the belief that a transformer's nameplate rating tells you everything about it.

For years, it was treated as a safe anchor. There's the number. There's the margin. There's peace of mind. The problem is that reality very rarely operates according to the same chart.

In 2025, many projects painfully collided with the fact that a transformer doesn't operate in a vacuum. It operates over time. In daily cycles. With seasonal patterns. In an environment of loads that changed their character faster than most design assumptions.

The classic mistake looked innocent. "Let's take a larger transformer, it will be safer."
Or the opposite. "The load profile looks light, we can reduce the power." On paper, it all added up. In the spreadsheet too. On the construction site and in operation, problems began.

Oversizing in 2025 ceased to be neutral.

A transformer operating most of the time at a very low load generates no-load losses regardless of whether it's delivering power or not. With rising energy costs, this became noticeable not after a year, but after a few months. Investors, who not long ago would have waved it off, began asking questions. Where do these numbers come from? Why don't the bills look as projected?

On the other hand, problems with undersizing emerged.

Especially where the load profile was based on historical data that didn't account for changes on the consumer side. Heat pumps, electric vehicle chargers, inverters, irregular operating cycles. All this meant that momentary overloads, starting currents, and short-term power peaks began occurring more frequently than anticipated.

In 2025, many people truly saw, for the first time, the difference between the nameplate rating and the transformer's actual behavior over time. A transformer can have a power reserve, yet operate under conditions that cause excessive heating.

It can formally meet requirements, yet practically shorten its lifespan. It can "manage," but at the cost of losses and operational stress.

A common source of the problem was a simplified approach to the load profile.

The average power over a day or month says little about what happens at specific moments.
And it is precisely these moments that determine how the transformer behaves. Short but intense loads can do more damage than stable operation at a higher level.

The year 2025 also showed that the conversation about a transformer's power cannot end with the number in its name. Increasingly, questions about the nature of the loads, their variability over time, and plans for installation development came to the fore. Designers began returning to investors more often with questions previously deemed unnecessary.

What will the load look like in two years?
What will change after expansion?
Which scenarios are realistic, and which are only theoretical?

All of this meant that in 2025, selecting a transformer's power rating stopped being a "just-in-case" decision. It became a strategic decision. One that must consider not only what is today, but what is very likely tomorrow.

And that is precisely why, heading into 2026, fewer and fewer people ask which transformer has the highest power rating. More and more ask which one best fits the actual way it will be used.

And that is a change that makes a huge difference.

Energy losses stopped being abstract. They started to cost, truly

For many years, transformer losses were one of those topics everyone was aware of, but few truly calculated. Sure, they appeared in documentation. Sure, they were listed in catalog sheets. But in practice, they were treated as a background cost. Something that "just exists" and doesn't require deeper attention.

The year 2025 ended this comfortable stage.

At the moment when energy prices stopped being a stable reference point and began to fluctuate in reality, transformer no-load losses stepped out of the shadows.

And they did so in a very unpleasant way. It suddenly turned out that differences which previously seemed cosmetic began to be noticeable in the operational budget over the course of a year.

The biggest surprise for many investors wasn't the load losses. Those are intuitively associated with the device's work. The real discovery turned out to be the no-load losses. Constant. Independent of the load. Present always, even when the transformer is mostly just "waiting."

In installations with uneven or seasonal operating profiles, it was precisely these losses that began to play the leading role. A transformer that was formally well-matched spent a large part of the year operating far from its optimal point. And energy was leaking away. Day after day. Without noise. Without alarms. Without visible symptoms, except for one thing that cannot be ignored: the bill.

2025 was also the moment when more and more projects began to be analyzed in terms of Total Cost of Ownership (TCO), not just the purchase price. TCO stopped being a trendy acronym. It became a defensive tool. Investors began asking not what a given transformer would cost at the moment of acceptance, but after five, ten, fifteen years of operation.

This changed the dynamic of conversations.

Cheaper solutions began to lose in the long-term horizon. A difference of a few percent in efficiency, previously considered a detail, in the new calculations could determine the profitability of the entire investment. And interestingly, these conversations increasingly took place not at the tender stage, but after the first year of operation, when the data stopped being theoretical.

It's worth noting that 2025 coincided with a clear increase in energy awareness on the part of regulators and international institutions as well. Reports on energy efficiency increasingly pointed out that losses in transmission and distribution infrastructure are not a marginal problem, but one of the real areas for optimization.

In practice, this meant one thing. The transformer stopped being a one-time cost. It became an element that generates a constant stream of costs or savings. Depending on how it was chosen. And how it really operates.

This also changed the way designers and investors talk to each other. More questions appeared about long-term scenarios. About load changes. About installation flexibility. About whether the solution chosen today won't become a burden in a few years.

Heading into 2026, it's increasingly difficult to ignore the topic of energy losses. Not because someone requires it. But because the numbers have started to speak for themselves.

And with such data, as we know, you can't win with narrative alone.

What the IEA's "Energy Efficiency 2025" Report Really Says and Why It Matters for Transformers

The International Energy Agency's Energy Efficiency 2025 report clearly shows that energy efficiency has ceased to be an add-on to the energy transition. It has become its foundation. Significantly, the IEA is not talking about futuristic technologies here, but about devices already operating in power grids today.

According to the IEA, the pace of global energy efficiency improvement is still too slow to meet climate goals while maintaining the stability of energy systems. The agency points out that the global rate of efficiency improvement should be around 4 percent annually, while in recent years it has realistically hovered closer to 2 percent. This difference translates directly into greater energy losses, higher operational costs, and increased strain on infrastructure.

The report strongly emphasizes the topic of power infrastructure. The IEA stresses that reducing losses in energy transmission and distribution is one of the quickest and most cost-effective ways to improve the efficiency of entire energy systems. It does not require a technological revolution, but the consistent application of proven, more efficient solutions in equipment like transformers.

Particular attention is paid to no-load losses and load losses in devices operating continuously. The IEA indicates that even small differences in the efficiency of individual infrastructure elements, on a systemic and multi-year scale, translate into very tangible economic effects. This refers to savings counted not in percentages, but in real energy costs and reduced demand for its generation.

The report also notes the changing nature of loads in grids. The growing share of renewable sources, energy storage systems, electric vehicles, and the electrification of heating is causing greater variability in energy flows. In such an environment, devices with lower losses and better partial-load efficiency gain importance, as they operate efficiently not only at nominal points but also under loads far from maximum.

The IEA also emphasizes the cost aspect. Investments in energy efficiency are among the fastest-returning actions in the energy sector. Reducing losses in power equipment decreases the demand for primary energy, lowers operational costs, and reduces pressure to expand generation capacity. This is particularly important under the conditions of unstable energy prices that the market has faced in recent years.

In practical terms, the IEA report sends a very clear signal: the efficiency of infrastructure equipment is no longer an image-related or regulatory choice, but a systemic decision. How transformers are designed and selected directly impacts not only the balance of a single installation but the resilience and costs of entire power grids.

For the industry, this means one thing. In the coming years, it will be increasingly difficult to justify choosing solutions with higher losses based solely on a lower purchase price.

Energy Efficiency as Industry's Key Response to Rising Energy Costs | Source: International Energy Agency, Industrial Competitiveness Survey 2025.

An infographic based on a 2025 International Energy Agency survey shows how industrial enterprises are responding to rising energy costs and price volatility. The survey results from 1,000 respondents across 14 countries clearly indicate that energy efficiency is today the most important strategic priority, surpassing on-site renewable energy investments, passing costs to customers, or reducing production.

The second part confirms that energy efficiency actions genuinely increase companies' resilience to energy price fluctuations. Over 80% of respondents rate their impact as critical, strong, or moderate, with only 7% noticing no effect. This data shows that modernizing power infrastructure, reducing losses, and better energy management directly translate into the stability of operational costs and the continuity of plant operations.

The conclusions from the IEA study clearly indicate that in 2025, energy efficiency ceased to be an environmental add-on and became one of the key tools for building industrial competitiveness and resilience to energy crises.

Dimensions, Logistics, and Installation. Seemingly minor details that caused major pain

If anything consistently derailed schedules in 2025, it wasn't spectacular failures. It was the details. Dimensions. Weight. Site accessibility. The sequence of work. Things that seem obvious at the design stage but in the real world can dominate the entire process.

For a long time, a transformer was treated as an element that would "somehow fit in." In practice, 2025 showed this assumption is becoming less and less valid. Especially when talking about prefabricated transformer substations, modernizations of existing facilities, or projects in densely built-up areas.

The first flashpoint turned out to be dimensions.

Differences of a few centimeters in width or height, which don't raise eyebrows in a catalog, on a construction site could mean having to change the entire foundation concept. In 2025, many projects painfully felt that a substation designed for a "standard transformer" is not always compatible with the actual device available at a given time.

The second problem was weight.

Transporting a transformer stopped being a simple logistical operation.

Load-bearing limits of local roads, access to the construction site, the availability of a crane with specific parameters. All of this started to matter earlier than ever. Projects that didn't consider these aspects during the planning stage often had to make up for it frantically at the end.

In 2025, situations increasingly arose where the transformer was ready, but there was no physical possibility to install it safely according to the original schedule. Additional days of downtime. Additional costs. Additional negotiations. And the question that came too late: did it really have to be this way?

The third aspect is servicing and accessibility after commissioning.

More and more people started thinking not only about how to install the transformer, but how to access it in five or ten years.

In 2025, there were more questions about service space, the possibility of safely removing components, and access to inspection points. This isn't a topic that impresses in a sales presentation. But it's a topic that comes back very consistently in operation.

An interesting phenomenon was that in 2025, more and more logistical problems began to be seen as systemic, not accidental.

International reports on infrastructure project implementation clearly show that underestimating logistics and the integration of technical elements is one of the main causes of delays and cost overruns. In a McKinsey report on productivity in infrastructure construction, it was pointed out that a lack of coordination between design and actual installation capabilities is one of the most frequent sources of time and money losses in energy investments.

In the practice of 2025, this meant a change in approach.

Designers began asking more frequently about things previously taken for granted. Contractors began incorporating logistics into the planning process earlier. Investors began to understand that compactness and predictable installation are not a luxury, but a real saving.

Dimensions stopped being a secondary parameter. They became one of the selection criteria.

Not because someone suddenly started liking smaller devices.
But because in 2025, the market saw very clearly what a mismatch costs.

Heading into 2026, it is increasingly difficult to think of a transformer in isolation from the place where it is supposed to work. Physical reality has returned to design conversations.

And it's likely here to stay.

Documentation, repeatability, and peace of mind during acceptance

If there was one thing that could halt a technically ready investment in 2025, it wasn't a lack of power or equipment failure. It was documentation. Or more precisely, its absence, ambiguity, or a disconnect between what was written and what was actually on site.

For years, documents were treated as a formality to be checked off.

Something that "has to be there" but doesn't necessarily require particular attention. In 2025, this way of thinking stopped working. Distribution System Operators (DSOs), inspectors, and investors began looking at paperwork not as an add-on, but as proof of the entire project's coherence.

The most common problem wasn't the complete absence of documents. They existed. But they were inconsistent. Declarations that didn't fully match the actual execution. Technical data sheets current "at the moment of order" but not necessarily at the moment of acceptance. Operation manuals that resembled a generic product description more than real support for the user.

In 2025, questions that were rarely asked before began to appear more frequently.

Does this transformer actually meet the specific requirements of the grid operator?
Do the parameters stated in the documentation match what was delivered?
Did the manufacturer anticipate operating scenarios that are now the norm, not the exception?

Repeatability proved to be a particularly sensitive point. Serial projects implemented in different locations began to painfully feel the differences between successive deliveries. The same transformer model, but with minor changes in execution. Different component placement. Different documentation. For operation, this isn't a detail. It's a source of unnecessary questions, risk, and stress.

Many contractors admitted openly that in 2025, the greatest relief during acceptance procedures was simply when the documentation matched up. Without excuses. Without "it's similar." Without handwritten additions. Consistency between the design, execution, and paperwork began to be treated as a technical value, not an administrative one.

Operational documents also began to carry increasing weight.

Manuals that actually help the user understand how the transformer works, when to react, and what to watch for. In a world where technical staff are increasingly stretched thin, the clarity and readability of documentation ceased to be a luxury. They became a safety element.

This trend is not accidental.

According to reports from international institutions dealing with technical infrastructure safety, one of the main sources of operational problems is communication errors and a lack of unambiguous technical information. Studies on the reliability of critical infrastructure explicitly state that standardizing documentation and procedures significantly reduces the risk of downtime and unplanned interventions.

In the practice of 2025, this meant a shift in emphasis.

Solutions were increasingly chosen that may not have been the most impressive, but were predictable. Ones that wouldn't cause surprises at the next acceptance. Ones that could be easily compared, serviced, and integrated into existing procedures.

Documentation stopped being an add-on. It became part of the infrastructure. And the peace of mind during acceptance that results from it turned out to be one of the most underrated benefits of a well-chosen transformer.

What to Choose After All This for 2026, and Why Peace of Mind Became the New Currency

After a year like 2025, the temptation to ask directly is natural. If so many things went off track, if theory was verified by practice, if details turned out to be decisive, then what transformer should be chosen for 2026.

And here it's worth slowing down for a moment.

Because the biggest takeaway from the last twelve months is not that the market needs something new. The biggest takeaway is that the market needs something predictable. Solutions that don't cause unpleasant surprises. That fit not only in the documentation but also in the substation, the schedule, and the budget. That comply with regulations not at the edge of tolerance, but with a real safety margin.

In this sense, choosing a transformer for 2026 is less and less a choice of the "technically best" option. Increasingly, it is a choice of the most sensible option in the context of the entire system. Energy losses. Load profile. Logistics. Documentation. Acceptance procedures. Operation in 5, 10, 20... years. This is why the conclusions from 2025 naturally lead to solutions like the MarkoEco and Teo Eco Tier 2 lines in the Energeks offering.

Not because they are the most impressive.

Not because "you have to."

But because they respond precisely to the problems this year exposed.

• Meeting Ecodesign Tier 2 requirements without interpretive gray areas.

• Low no-load losses where the transformer operates most of the time away from its nominal load.

• Predictable dimensions and construction compliant with Distribution System Operator requirements.

• Documentation that doesn't require explanations during acceptance.

This isn't a story about a single product. This is a story about an approach. About the fact that after 2025, fewer and fewer people want to improvise. More and more want to know that the decision made today won't come back in two years in the form of a problem.

This entire analysis, from the first section to the last, stems from a very simple assumption: listen and respond to the actual needs of the market.

In the end, we want to say one thing. Thank you.

For the conversations on investment sites.

For the tough questions in projects.

For the exchange of observations and knowledge.

For the feedback that sometimes stings but always teaches.

And for the fact that we increasingly think about the energy sector not only in terms of power, but in terms of responsibility and long-term consequences.

A new year in the energy industry is rarely calm. And that's good.

We wish you for 2026 not an absence of challenges, because they drive progress…

but more predictability where it matters. Less firefighting. More decisions that stand the test of time.

If these topics are close to you, we invite you to our community on LinkedIn.

We share market experiences, implementation insights, and conversations that usually don't fit in product brochures, for people who want to see further than the next acceptance procedure.

2026 is coming fast. It's good to enter it with energy that works for you!

Sources:

Cover Photo: Juan Soler Campello/pexels

International Energy Agency (IEA) - Energy Efficiency 2025

McKinsey Global Institute - Reinventing construction through a productivity revolution

When you stand next to a transformer substation and hear its soft hum, it's hard to believe that within that metal box, the lifeblood of the power network pulses.

And yet, most of us carry within us the same curiosity from childhood: the very same curiosity that made us wonder what was inside a golf ball, a ping-pong ball, or a tennis ball.

Who among us hasn't tried to drill, cut, or pry one open just to see what the "inside of the world" looks like? Let him who has not cast the first fuse ;-)

The transformer operates on this exact same archetypal impulse: the desire to peek where we don't usually look.

Inside a transformer, something fascinating happens. Current transforms as if in an alchemical process, and its heart is cooled by oil of near-laboratory-grade parameters.

What exactly lies beneath the steel cover?

And why does this structure work continuously for decades, despite extreme temperatures, vibrations, and voltages reaching thousands of volts?

At Energeks, we work with medium-voltage transformers every day – from design and testing to field implementations. We know that understanding the inside of a transformer is not just a matter of curiosity, but also of safety, efficiency, and compliance with standards.

This article is for contractors, investors, designers, and technology enthusiasts who want to look inside without the risk of electric shock.

After reading, you will know:

• What key components make up an oil transformer.

• What role the oil plays and how it works with the magnetic system.

• How the construction of a sealed transformer differs from one with a conservator.

• Which design flaws most commonly shorten its lifespan.

At the end, a bonus awaits you: a list of 5 operational errors that can destroy even the best-designed transformer.

Reading time: approx. 7 minutes

The magnetic core – the iron heart of the transformer

When you look at an oil transformer from the outside, you see a solid steel box, often enclosed in the concrete housing of a prefabricated substation. But the true life of this device pulses inside – where its iron heart beats: the magnetic core. Without it, a transformer would be like a body without a circulatory system – it would have no way to transfer energy from the primary to the secondary windings.

To understand how this works, we need to briefly revisit basic physics. A transformer doesn't "transmit" current directly between its windings. Instead, it uses the phenomenon of electromagnetic induction. When alternating current flows through the primary winding, it generates a varying magnetic field, which in turn induces voltage in the secondary winding. And all of this happens thanks to the core – the element that guides and concentrates this magnetic flux, like a well-laid highway for the electromagnetic field.

What is a transformer core made of?

Not from "iron," as is commonly said, but from electrical steel laminations – thin, precisely rolled sheets of silicon steel with low magnetic losses.

This is a very special material. Each lamination is coated with insulation to minimize the phenomenon of eddy currents, which could turn the transformer into an unwanted heater.

The thickness of a single lamination is usually 0.23–0.30 mm – about the same as a sheet of technical drawing paper.

The laminations are stacked in layers, like the pages of a book on energy, and clamped into packages.

This is called a laminated core. The thinner the laminations and the higher their quality, the lower the no-load losses – the energy the transformer consumes just to be "on," even without any load.

Two main types of cores are used in oil transformers:

• Core-type, where the windings are wound around the vertical limbs of the core.

• Shell-type, less common in medium-voltage power systems, where the windings surround the core.

Core-type designs have the advantage of being more compact and dissipating heat better – ideal for use with cooling oil.

What does core assembly look like in practice?

This is where theory ends, and true craftsmanship begins. A transformer core cannot have gaps or air spaces because every such micro-gap is a potential source of losses and noise. Therefore, the laminations are stacked with surgical precision. In large production plants, robots and presses are used for automatic stacking, but in smaller MV transformers, you can still literally see the human hand at work.

The laminations are overlapped in a "step-lap" configuration, which limits losses at the joints and reduces the characteristic hum. That hum you hear when standing by a substation is precisely the micro-vibrations of the laminations under the influence of the alternating magnetic field. For some, it's the sound of a stable, reliable grid; for others – a signal that "the transformer is working as it should."

What is the significance of grain orientation?

This is a term that sounds like it's from a metallurgy course, but it has enormous significance for a transformer's efficiency.

Silicon steel can be either non-oriented or grain-oriented (GO).

The latter has a crystalline structure oriented in one direction, allowing it to conduct magnetic flux more easily.

The result? Lower losses and quieter operation.

A transformer with a grain-oriented lamination core can have no-load losses 30–40% lower compared to older designs.

In practice, this translates to tens of megawatt-hours of saved energy over the entire life of the equipment.

What you see here is the moment when the oil-filled giant stands almost stripped to the bones, showing off its copper muscles without a hint of shame: the copper windings gleam like lacquered alloy rims, the insulation is layered like a perfect haircut from a master barber, and the core serves as the solid backbone of the entire structure. Here, you can see the precision, the craftsmanship, and the obsession with quality that defines this work.

Oil meets iron – how the core cooperates with cooling

The core is fully immersed in transformer oil, which serves a dual function: insulating and cooling. Heat generated by magnetic losses and eddy currents is absorbed by the oil and transferred to the tank walls, where it is dissipated. Modern transformers use forced oil circulation systems, allowing for higher unit power without overheating the core.

Why does all of this matter?

Because the core is not just a metal skeleton – it is the starting point for the transformer's entire efficiency. Its quality determines:

• The level of no-load losses (i.e., the cost of energy the network "consumes" without any load).

• Noise and vibration levels.

• Operating temperature and the durability of the insulation.

• And consequently – the transformer's lifespan.

As assembly floor engineers like to say:

"A bad core will eat up the best oil, the best windings, and the best design."

This is why, before a transformer reaches the substation, its core undergoes tests for inductance, losses, and magnetic permeability.

These are the tests that determine whether the iron heart will beat with a steady rhythm for decades to come.

Windings that transform voltage into usable energy

In the world of transformers, windings are like a bodybuilder's muscles.

They don't shine as much as a lacquered enclosure, nor do they buzz as distinctly as the core, but they do the heaviest lifting. They transform voltage, stabilize energy flow, and do it with a precision that begs for a comparison to martial arts masters: minimum movement, maximum effect.

An oil transformer has two main types of windings.

Primary, which receives high voltage like a gatekeeper at a power plant, and secondary, which outputs current in a form digestible for the network.

Copper – or aluminium – forms neatly layered, multiple turns that somewhat resemble a perfectly layered mille-feuille pastry.

Every layer has its insulation. Every turn must be in its place. Every millimeter matters, because we're talking about electric fields capable of generating voltages that can, in a second, turn a simple assembly error into a fire, an oil blockage, or a flashover nobody wants to witness.

The windings in an oil transformer are also the element that most reveals the manufacturer's character.

A single glance at the geometry, cooling layout, and the way the leads are brought out is enough for an experienced engineer to assess whether they are dealing with top-tier craftsmanship or a budget experiment that probably shouldn't get anywhere near an MV switchgear room.

The winding line tells the truth. It's either clean, uniform, and perfectly wound, or it screams that something was rushed.

It's worth remembering that windings operate at temperatures that can exceed one hundred degrees Celsius. Oil cools, but you can't cheat physics.

This is why insulation materials are so crucial – typically oil-impregnated electrical paper, which acts as both a blanket and a barrier.

The better the impregnation and the more uniform the layers, the longer the transformer will work without complaint. Leaving micro-gaps, overheated copper, or using the wrong insulation class – all these shorten a transformer's life like sleepless nights shorten a human's.

This is precisely where all the magic of voltage conversion happens.

A varying magnetic field arises in the core, which induces voltage in the secondary winding. It's like a dialogue you can't hear, but you see the results – in the form of usable energy that reaches homes, pumps, factories, energy storage systems, and all the other infrastructure we take for granted.

Well-designed windings also guarantee stability during short-circuits and overloads. A transformer that is "copper-resistant" will withstand more, because its windings won't collapse, shift, or break in critical moments.

The difference between a robust and a weak transformer often only reveals itself after the first short-circuit – and then there's no more debate about which copper was "the right one."

Finally, it's worth noting that windings have their subtle charm. There is a certain geometric aesthetic, order, and rhythm to them. A transformer with such windings will reward you with years of quiet operation. It's one of those relationships where precision truly matters.

If you want to see how these windings are created step by step, check out our article:

How a transformer is made: 10 stages of oil transformer production

It's a great complement to this part of the post, as it shows the entire process from the first lamination, through winding the copper, to final testing and assembly. It perfectly rounds out the topic.

Insulating oil, the invisible guardian of temperature

If a transformer were a living organism, the insulating oil would be its lifeblood.

A quiet, hardworking substance that doesn't demand attention, doesn't shine, doesn't smell spectacular, but performs a task so vital that without it the entire system would collapse like a house of cards.

This insulating oil stands on the boundary between smooth operation and the kind of catastrophe operators prefer to see only in training scenarios.

Transformer oil serves two main roles.

First, it insulates, pushing voltages apart as effectively as if it stretched an invisible protective net between conductors.

Second, it cools—and it cools literally every element that generates heat.

Copper (or aluminium) and the core have a tendency to heat up their surroundings. The oil absorbs this heat, transports it to the tank walls, and dissipates it to the environment. Without it, the transformer would be like a convection oven, only decidedly less pleasant.

Two main categories of oil dominate the market.

The first is mineral oils, the classic of the power industry. Stable, predictable, cost-effective, with well-researched characteristics.

The second is ester oils. They are increasingly chosen by designers of substations and photovoltaic farms because they are biodegradable and have a higher fire point. In practice, this means an additional safety margin.

For many investors, it also matters that ester oils penetrate the insulating paper better, slowing down its aging.

The operating temperature of a transformer is a complex puzzle.

Every degree increase translates to faster aging of the cellulose insulation. And it's the insulation, not the copper, that determines the longevity of the entire device. Therefore, good oil isn't a fancy extra. It's an investment in decades of stable operation.

Excessive moisture in the oil, contaminants, or chemical degradation can lead to what in the power industry is described succinctly and directly: trouble.

An interesting fact is that transformer oil keeps its own chronicle of the device's life over the years.

Every chemical micro-flaw leaves a trace in it.

This is why DGA testing, or Dissolved Gas Analysis, is like reading a flight recorder.

From the printouts, one can learn whether there is arcing, localized overheating, slow degradation of the insulation, or the beginnings of thermal processes that require attention. An experienced diagnostician can extract more information from this sample than a doctor can from a chest X-ray.

Transformer oil also works as a shock absorber.

It dampens vibrations, protects windings from shifting, and safeguards the system in case of a short-circuit. In sealed transformers, the oil enjoys peace because the entire system is closed. In constructions with a conservator, it "breathes" through a breather system designed to keep moisture at bay.

Why does all this matter?

Because oil quality changes everything. If the oil is clean, dry, and chemically stable, the transformer can work for thirty years without issues. If the oil is neglected, even the best core and the most uniform windings won't save the situation.

At this point, many engineers start treating the oil as a partner, not just a technical medium.

Because when you see how well-impregnated paper, clean oil, and stable temperature translate into quiet operation and low losses, understanding comes naturally. It's this invisible part of the transformer that deserves significantly more attention.

If you're interested in how oil behaves in real operating conditions and how to recognize when something starts to go wrong, it's also worth checking out our article:

Transformer oil leaks – do not ignore these signals

It's a practical guide on the symptoms, diagnosis, and repair of leaks that can determine the fate of an entire transformer.

Tank, conservator, tap-changers, thermometers: the body of the transformer

When we look at an oil transformer as a whole, it's easy to focus on the windings and the core.

That's the heart and muscles, the interior that does the actual work. But all of this interior needs a solid housing.

A body that will protect it, maintain its parameters, and give the transformer a chance to survive three decades even in the most capricious climate.

And here begins the story of the tank, conservator, tap-changers, and thermometers.

Elements that at first glance look like add-ons, but actually determine whether the transformer even has a chance of reaching retirement age.

The tank is the armor that keeps the entire system in check.

Thick steel, often corrugated into radiators, which give the oil a place to dissipate heat. In the field, it looks like an unassuming box, but every designer knows the tank is like a turtle's shell. It withstands overloads, temperature swings, wind gusts, knee-deep snow, and every short-circuit that puts the structure under momentary stress.

Perched atop the tank often sits the conservator, an additional oil reservoir that compensates for volume changes due to temperature. It's like the transformer's technical breath.

When the device heats up, the oil expands and moves into the conservator. When it cools, it returns to the main tank. The presence of a conservator may seem like a detail, but it's a detail that tangibly protects the insulation from moisture. This is precisely why so many specialists seek the answer to the classic question: should one choose a transformer with a conservator or a sealed one?

We've examined both constructions here and encourage you to check out the content:

Transformer with conservator or sealed - when does which make sense?

It's a good reference point if you want to approach an order or substation modernization knowledgeably.

Tap-changers are another key element of the transformer's body.
These small mechanisms allow the voltage to be adjusted to grid conditions. In MV transformers, you most often find off-circuit tap-changers, which are set before the device is energized.
It's a bit like fitting shoes before a long march, because the correct setting determines whether the transformer will start operating smoothly or struggle at voltage limits.

Larger units use OLTCs, or On-Load Tap-Changers.
This is advanced engineering. Mechanics, hydraulics, sparks quenched in oil, and live voltage regulation during operation.

Then we have thermometers, oil level gauges, valves, and relays.
Small components that serve as the transformer's sensory organs. The thermometer shows winding and oil temperature. The oil level gauge signals when something alarming is happening. Valves allow for quick venting or oil draining for testing.

And the Buchholz relay in transformers with a conservator reacts to gas accumulation.
This is a very serious signal. If the Buchholz relay activates, the entire crew knows they must act before a spark turns into a failure.

This entire transformer body is a team that works harmoniously only when every element is perfected.

• The quality of the welds.

• The tightness of the gaskets.

• The mechanical stability of the radiators.

• The condition of the anti-corrosion coating.

These are the things you only truly see in the field, especially when faced with November winds, shin-deep snow, and a standard technical inspection where nobody will overlook even a centimeter.

It's right there that the tank and all its accessory family show whether the transformer is a well-thought-out construction or just an attempt to enter the world of power engineering through the back door.

The transformer's body is more than just a metal can.
It is a shield, a shock absorber, a stabilizer, and a guardian that protects the interior. And if it's well-made, the transformer repays it with quiet operation even in places where the weather and loads can be capricious.

Power engineering does not like surprises.
That's why it's so crucial for the devices operating within it to be predictable, tight, and resilient.

When design fails and the transformer pays the price: the most common design pitfalls shortening its lifespan

An oil transformer can be designed like a dream and produced with the best copper on the continent, but if a design error occurs along the way, the device's life begins to shorten from the very day of assembly.

In the industry, it's sometimes said that a transformer ages not from the number of years, but from the number of misguided design decisions someone once considered a saving or a minor compromise.

And compromises in transformers take revenge slowly but surely.

The most common sin is improper winding layout.

If the copper is laid unevenly, if local stresses appear, or if there are spaces that are later difficult to fill with oil, the transformer starts having problems even before factory testing. Poorly cooled spots heat up faster, and overheated insulating paper ages at a rate that cannot be reversed later.

From a durability perspective, it's like putting a new engine into a car with already worn-out bearings. It will run, but not for long.

The second classic design error is poor cooling system geometry.

Radiators that are too small, poorly positioned, or set at an angle that hinders the natural oil circulation. The consequences are simple. Instead of circulating calmly and dissipating heat, the oil forms hot spots.

In these hot spots, everything ages. The oil. The paper. The gaskets.

The transformer seems to work, but it does so under constant thermal stress. And every degree above the norm shortens the insulation's life exponentially. If someone wants to check how much can be lost due to poor cooling geometry, just look at the oil condition test results after a few years of operation. They reveal everything.

The third problem is tank construction.

It might seem that steel is steel. But not all steel has the same quality, not all welds will withstand the same stresses, and not all connections will remain tight during temperature changes.

Even a slight deformation of a radiator under pressure can alter the oil flow, and a microscopic leak in a weld leads to moisture ingress. Moisture in the oil means an increased dielectric loss factor. An increased dielectric loss factor means the transformer starts working harder. And so on, in a vicious cycle, until the first major alarm.

Another mistake is cutting corners on the sealing system.

In many transformers, the gaskets are the first element to age. Poor rubber quality, ill-fitting rings, lack of proper tolerance for thermal movement. The end result is always the same: oil begins to disappear. And a transformer without oil is a transformer with problems not only for insulation but also for thermal management. It starts working like a furnace with a blocked chimney. Sooner or later, a signal will come, followed by questions about why that gasket cost five złoty less.

A separate category of errors involves poorly thought-out tap-changer designs.

Poorly chosen regulation positions, weak internal insulation, a tap-changer compartment that is too small. All this causes the tap-changers not only to wear out faster but also to create points of risk for arcing. And every spark in oil creates gases. And gases mean a Buchholz relay alarm. And every Buchholz alarm means a phone call from the operator and long discussions about why the device didn't quietly complete another operating cycle.

Finally, it's worth mentioning excessive compromises in noise-reduction design. A poorly designed step-lap configuration, insufficient core bracing, play in the core packages. All this increases vibrations, which over time cause micro-cracks in the insulation.

Even if the transformer doesn't exceed noise limits, vibrations are its internal enemy. Over the years, they do the same thing waves do to a concrete breakwater. Slowly, invisibly, but consistently.

Design errors are like flaws in a building's foundation.

You can't see them on the surface, but they affect everything. Every transformer has its history and its purpose. And the one designed without compromises has the greatest chance of living its twenty-five to thirty years not as a maintenance curiosity, but as a stable network element that simply does its job.

5 operational errors that can destroy even the best-designed transformer

Design is one thing, but a transformer's life truly unfolds in the field.

And here begins the real test of the device's character. Even a perfectly designed and manufactured transformer can be run into the ground if operation goes against common sense.

On construction sites, in substations, and at PV farms, we've seen many situations where the fault lay not with the device, but with human habits, shortcuts, and haste.

And a transformer, though resilient, cannot win against time or operational errors. Here are the most common operational transgressions.

1. The first is ignoring moisture.

A transformer dislikes water in any form. Not in the oil, not in the paper, and not the kind that appears through leaks. When oil's moisture content becomes elevated, its dielectric properties drop drastically. The insulating paper begins to age at a rate comparable to driving a car with the handbrake on. And all of this could be avoided with a single annual oil test and heeding the first warning signs.

2. The second error is overheating the insulation by improper transformer loading.

In power engineering, it's often said a transformer can be overloaded, but with care. The problem is many contractors do it recklessly, assuming that if a transformer has a nameplate with a beautiful MVA rating, it can operate at that level twelve months a year. Meanwhile, every manufacturer provides curves for permissible overloads and temperatures. Ignoring them is like setting a treadmill at too steep an incline and pretending nothing is wrong. Something is wrong. Always.

3. The third problem is a lack of regular mechanical inspections.

Gaskets perish. Bushings get dirty. Valves can be forgotten. Even bolts on radiators can loosen if the transformer is in a location where the wind blows from one direction for half the year. Mechanical neglect leads to leaks, leaks lead to moisture, and moisture leads to failure. A spiral that is quick, predictable, and almost always avoidable.

4. The fourth error is disregarding voltage deviations and power quality.

A transformer that operates at elevated voltage for years is like a person who drinks one too many cups of coffee every day. It will manage, but its heart won't be grateful. Core overheating, increased no-load losses, stressed insulation. In distribution networks, connections are often built quickly and under pressure, causing the transformer to bear the brunt of poorly compensated installations. And what happens at the voltage level later becomes visible in DGA results.

5. The fifth error is unsuitable environmental conditions.

Transformers cope poorly with constant salt exposure, industrial pollution, lack of protection from water running off the installation, and vibrations transmitted through the foundation. If a transformer stands on a poorly executed foundation, every short-circuit impulse and every gust of wind is transmitted to the structure. Over the years, this makes a difference. It becomes visible in the condition of the radiators, connections, bushings, and sometimes even the core itself.

Operational errors are often not the result of ill will, but of routine.

The transformer stands there, works, no alarms are flashing, so "it looks fine." Meanwhile, slow processes are occurring inside that only become visible after years. Good operation isn't just about responding to failures. It's the daily care of a device that repays this care with reliability. A transformer with clean oil, healthy insulation, and stable operating conditions can work so predictably that it's almost boring. And in power engineering, boredom is the highest form of compliment.

What remains when we close the transformer's cover

Looking inside an oil transformer is a bit like opening that golf ball from childhood. The only difference is that here, instead of a rubber core, we find precision, thermodynamics, oil chemistry, and an architecture that keeps thousands of volts in check.

A transformer is not a "metal box with copper." It is a living, responsive system where every detail determines years of operation. The core. The windings. The oil. The tank. The tap-changers. The diagnostics. The operation. It all contributes to the story of a device with just one task: to work quietly, stably, and without drama.

If you are working on a project where reliability, safety, compliance with standards, and long service life matter, we are by your side. We select the power rating, cooling, insulation type, oil type, and parameters that truly make a difference in the field.

Explore our offering of Ecodesign Tier 2 transformers, including units available off-the-shelf and full documentation packages.We also invite you to our community on LinkedIn.

Thank you for being here with us. And if you'd like to discuss your project, define parameters, or prepare an acceptance checklist for an MV transformer, just send us a message.

Let's do it the way the best things are done in power engineering: calmly, concretely, and together.

Sources:

https://electrical-engineering-portal.com/

Cable Comminuty.com

Power Tech Systems

There is a moment of silence before the first ampere trembles.

On the screen glows a 3D visualization, where the core consists of thousands of thin laminations, and the windings resemble precisely laid ribbons.

This is where the life of an oil transformer begins, long before it reaches a substation and powers a residential district or a production line.

A good story isn't magic; it's engineering told in the right sequence.

That is exactly what we are doing today.

At Energeks, we work with medium-voltage transformers, prefabricated transformer substations, switchgear, and energy storage systems every day.

We combine practical experience with the requirements of standards and the expectations of investors.

This text is the result of numerous conversations with designers, technologists, and assembly teams.

We present the process in a way that helps make better decisions and predict outcomes at the concept stage.

If you design, purchase, order, or will be operating an oil transformer, understanding the production chain of cause and effect will save you time, money, and nerves.

In the end, you will know why a specific requirement in the technical specification translates into particular operations, risks, and performance parameters for decades.

Agenda:

• Design and digital visualization

• CRGO lamination core and step lap configuration

• Windings. Conductor selection and geometry

• Insulation system. Kraft paper and DDP

• Active part assembly and preparation for testing

• Tank. Corrugated or with radiators

• Surface treatment and anti-corrosion protection

• Drying of the active part and moisture control

• Vacuum oil filling and heat cycling

• Routine tests and readiness for shipment

Reading time: ~20 minutes - just right for some worthwhile reading during your afternoon coffee and biscuit break!

Design and digital visualization

Every transformer begins with an idea, which looks less like a magical spark and more like... Excel, CAD, and... coffee at three in the morning.

The process of designing an oil transformer is a precise puzzle where physics meets mathematics, and everything must fit inside a tank with specific dimensions and weight.

Before anyone even orders steel or copper, the design team creates a digital model of the transformer, also known as a digital twin.

In this model, they test how the magnetic field will behave under different loads, how heat flows, where mechanical stresses will occur, and what the no-load and load losses will be.

This is not just a "nice 3D visualization of a transformer"—it's a virtual testing laboratory that saves months of work and hundreds of thousands of EUR.

The designer must reconcile several worlds:

• The electrical world: parameters like voltages, ratios, and vector groups.

• The mechanical world: short-circuit forces and cooling.

• The material world: because CRGO steel has different properties than amorphous steel.

• And finally, the environmental world: ambient temperature, humidity, and altitude above sea level.

This is where the engineering dance between theory and practice begins.

For example: increasing the number of turns improves voltage stability but raises the winding resistance and thus the losses. Reducing the conductor cross-section lowers costs but impairs cooling. As always—the devil is in the details, and the angel is in the tolerance table.

In modern factories, the transformer design doesn't end on paper. Digital visualization allows for simulations in environments like ANSYS Maxwell or COMSOL Multiphysics, where one can check how the transformer will behave during a short-circuit, overheating, or a lightning impulse. It's a bit like training—it's better for the equipment to "take a beating" in the computer than in the power grid.

Thanks to such models, it's also easier to adapt the construction to a prefabricated transformer substation, where every centimeter counts. The designer can see in advance if the mounting holes, coolers, tap-changers, and accessories will fit without collisions. This is the magic of 3D transformer design—a virtual factory before the real one is built.

A well-designed digital transformer already has a full data package defined at the design stage:
Technical documentation, a bill of materials, a winding schedule, and a detailed cooling plan.

This shortens production time by up to 20% and minimizes the risk of errors.

CRGO lamination core and step-lap configuration

At the heart of every transformer lies its core – the magnetic core.

It doesn't glow or shine, but its quality determines whether the device will purr like a cat or hum like a refrigerator from the 1980s. The core is precisely what dictates no-load losses, noise levels, and overall energy efficiency.

And it all starts with a material known by a three-letter acronym every electrician memorizes:

CRGO – Cold Rolled Grain Oriented Steel.

This silicon steel, with grains oriented in a single direction, has a unique gift:

It conducts magnetic flux like a well-designed channel conducts water.

As a result, hysteresis losses (the energy consumed with every reversal of the magnetic field) are even 30–40% lower than in ordinary hot-rolled steel.

From an engineer's perspective, it's like an engine running at lower throttle but delivering the same power.

During the production of the transformer core, CRGO laminations are cut with laser or knife-edge precision to within tenths of a millimeter.

It is crucial that they have no burrs or micro-cracks, which could become sources of loss or vibration.

Here, not only geometry matters but also the stacking sequence. Modern designs use a so-called step-lap configuration – a technique of overlapping the lamination edges, resembling roof tiles.

The effect? Magnetic flux flows smoothly, without abrupt "jumps" between segments, which reduces noise and improves efficiency.

Imagine the core as a labyrinth where the magnetic field seeks the shortest path.

Every gap, every misalignment is like a hole in the path = energy escapes as heat and sound.

This is why the following are so critical:

• High-quality laminations (low core loss, e.g., 0.9–1.1 W/kg at 1.5 T and 50 Hz),
• Precision cutting and stacking,
• And solid joints between yokes and limbs that eliminate micro-gaps.

In large units, the core is assembled in segments: first the limbs, then the yoke, and the whole structure is clamped with steel frames.

Some manufacturers use bonded interlayer insulation systems that limit vibration and improve the coherence of the core package. Amorphous cores, which are even more energy-efficient though more difficult to process, are also becoming increasingly popular.

From a user's perspective, you can hear the difference between a "good" and a "bad" core.

Literally. A transformer with a perfect step-lap configuration and the right CRGO steel can be several decibels quieter, meaning in practice you can hold a normal conversation next to the operating equipment. For urban substations installed near buildings, this isn't a minor detail, but a condition for project acceptance.

An interesting fact

Some production lines use algorithms to optimize the core cutting angles based on the working flux density.

This is pure field mathematics: the better the grain orientation, the smaller the magnetic distortions and the lower the losses at high voltages. As a result, the transformer gains a few percentage points in efficiency without additional material costs.

This is how the foundation of the entire device is created – both literally and figuratively.

The CRGO lamination core is an engineering compromise between physics, economics, and the quiet that speaks of perfection.

Windings. Conductor selection and geometry

If the core is the transformer's heart, then the windings are its muscles – they carry the energy, and their shape, material, and insulation determine how effectively they do so. In theory, it's simple: we have a primary winding, a secondary winding, the right number of turns, and Faraday's law of induction. In practice, it's a world of hundreds of nuances that can determine whether the transformer survives its first short-circuit.

First, the choice of metal. Copper or aluminium?

Contrary to myths, it's not just about price.

Copper has higher conductivity (approx. 58 MS/m), but it's heavier and more expensive.

Aluminium (approx. 35 MS/m) requires a larger cross-section but facilitates cooling thanks to better temperature distribution. For transformers with powers up to a few MVA, the choice often depends on material availability and client requirements. You can find more about differences in conductivity and material properties in analyses by the International Copper Association, which has been researching the efficiency of copper in the power industry for years.

Shape and geometry – a dance between the magnetic field and oil

The low-voltage (LV) winding is most often made from paper-insulated rectangular strip or wire, wound in layers. The high-voltage (HV) winding – from round or rectangular wires, also in paper, but with a more complex geometry. All this is done to minimize the stray field and distribute temperature evenly in the oil.

The principle is simple: the shorter the current path, the smaller the losses. But engineers know that reality is rarely straightforward. HV windings often use helical, cylindrical, or disc-type arrangements, which allow for controlled magnetic field distribution and oil cooling through microchannels.

In laboratories, you can see how such a winding in cross-section somewhat resembles a multi-layer cake – except instead of cream, we have cellulose Kraft paper and epoxy resin.

Insulation secrets – cellulose and DDP in action

Every winding needs protection from voltage and temperature. This is where Kraft paper and its enhanced version, DDP (Diamond Dotted Paper), come into play. This is a material where micro-dots of resin are arranged in a regular grid – during the heating process, they create a "weld" between the winding layers. The result? A rigid structure resistant to vibration and discharges. The layer insulation made from DDP paper has another advantage: it allows for precise control of the so-called "creepage distance." A high value for this parameter reduces the risk of flashover, which is crucial at voltages of 15–36 kV.

Insider jokes

In the industry, they say that "a winding can be made beautifully, but only once" – because if something goes wrong during the winding process, there is no second chance. Too much pressure? Damaged insulation. Too little? Vibration. That's why winding machine operators often have the status of artists – they can feel the tape's resistance with their fingers before a sensor shows any deviation.

Anyone who has had the chance to see the winding of an oil transformer coil live knows it's like watching a watchmaker at work on an XXL scale.

Precision, rhythm, and focus – all so that the current can flow for decades in perfect rhythm

Manual winding of oil transformer coils using copper conductors and DDP paper insulation.

A key manufacturing stage ensuring transformer efficiency and long-term reliability.

Insulation system. Kraft paper and DDP

Insulation in a transformer is somewhat like skin in a living organism – invisible from the outside, but absolutely crucial for the life of the entire system.

Without it, even the most beautifully designed core and windings wouldn't stand a chance of surviving the first overvoltage. And just as human skin relies on elasticity, resistance, and regeneration, the most important properties in a transformer are dielectric strength, mechanical stability, and resistance to thermal aging.

The primary material that meets these requirements remains Kraft paper – a cellulose classic with an extremely long history.

It is made from wood fibers of high chemical purity, which ensures low ash content and excellent electrical strength. In transformers, it is used in the form of tapes, sleeves, and spacers. In contact with mineral or synthetic oil, the paper swells minimally, maintaining dimensional stability, and its micropores allow for the exchange of gases and oil.

But the world of insulation has taken a step further. In higher voltage windings, DDP (Diamond Dotted Paper) is used, coated with a regular grid of micro-dots of epoxy resin. When the winding enters a vacuum oven and reaches the appropriate temperature, the resin melts, fusing the paper layers into a rigid, homogeneous structure.

The result? Insulation that doesn't shift even under severe electromagnetic transients and vibrations. It is this "glue" that prevents the transformer from "humming" during the startup of large drives.

A properly designed insulation system isn't just about the paper. It also involves vacuum impregnation, which removes air bubbles, and protective layers made from pressed cellulose boards that absorb mechanical stresses. A key parameter remains the breakdown voltage – values in the range of 40–60 kV/mm indicate the quality of the material and the purity of its structure.

A well-chosen insulation system for an oil transformer is an investment in peace of mind for maintenance crews for the next 25–30 years. It determines whether the equipment can withstand not only voltage overloads but also thousands of heating and cooling cycles, which act like slow, yet relentless, fatigue tests.

A tidbit from high-voltage laboratories

Modern research on dielectrics shows that even a slight increase in the paper's moisture content from 1% to 3% can reduce its electrical strength by over 50%. This is why drying and controlling the water content in cellulose is a topic that will reappear later in this article.

Active part assembly and preparation for testing

At this point, the transformer begins to resemble more than just a collection of parts – it slowly becomes a living organism.

The active part assembly stage is an engineering orchestra, where every element has its place, its specific torque, and its tolerance. The precision of these actions determines whether the device will operate without vibrations or failures for decades to come.

The active part is the combination of the core, windings, yokes, spacers, and insulation – everything responsible for conducting and transforming energy.

First, the low-voltage and high-voltage windings are placed over the core limbs.

Some designs require additional electrostatic screens or grading rings, which distribute the electric field evenly along the entire length of the winding.

Once the windings are in place, it's time to assemble the yoke, the top part of the core. It's like closing the lid of a well-fitted watch. Here, wedges, clamping frames, and spring-loaded bolts are used to mechanically stabilize the structure.

The whole assembly must be rigid, but not overly so – a transformer needs a minimal degree of flexibility to withstand short-circuit forces without cracking the insulation.

Next, the tap changer (OLTC or NLTC) is installed – this is what enables voltage regulation on the high-voltage side, compensating for fluctuations in the grid. In large units, it is mounted in a separate oil compartment; in smaller ones, directly on the cover.

Each tap changer is tested electrically before the oil is filled, as access to it becomes difficult after final assembly.

Stability, tightness, and cleanliness

Three words that govern this phase. Every speck of dust, every under-torqued yoke, every poorly positioned wedge can turn a future transformer into a potential source of failure. This is why assembly takes place in clean, controlled conditions – often in halls with positive pressure to prevent dust ingress.

After the active part is assembled, it's time for preliminary tests.

These are "dry tests" that ensure everything is according to design:

• Winding resistance measurement,

• Vector group verification,

• Ratio measurement,

• Inter-system insulation check.

These tests are the first moment the transformer "speaks" – its parameters begin to form graphs and numbers.

Find out how we test our transformers at Energeks, insider knowledge you won't find on Google:

How do we test our transformers? A symphony of factory quality!

A short digression on vibrations and patience

In experienced assembly teams, a rule prevails:

"Don't rush the clamping – the transformer will reward you with quietness."

Properly torquing the yokes and selecting the right elastic elements ensure the device does not produce unwanted sounds during operation.

After all, sound is energy that could have been better utilized – for example, for transmitting current instead of an acoustic concert in a substation.

Where theory meets practice

It is at this stage that many young engineers understand for the first time that a transformer is not just a CAD project, but a physical machine with its own dynamics, weight, and rhythm.

In theory, every current transformer, coil, and screen can be described by equations.

In practice – you need an eye for detail and respect for mechanics.

For those who would like to explore the topics of short-circuit forces and the stability of the active part in greater depth, I recommend publications from Transformers Magazine, in which experienced designers analyse the influence of assembly on the mechanical overload resistance of transformers.

Tank. Corrugated or with radiators

Every transformer needs armor. Not to look combat-ready, but so its interior—full of windings, cores, and insulation—can peacefully bathe in oil and avoid interacting with the external environment.

This armor is the tank of the oil transformer, a steel vessel that provides cooling, tightness, and safety for the entire structure.

Simply put, the tank is the transformer's "shell of life." Its construction must withstand vibrations, temperature differences, and pressure, while remaining absolutely sealed for decades. This is why designers choose between two main types: the corrugated tank and the tank with radiators.

Corrugated tank – the master of compact solutions

A corrugated tank somewhat resembles an accordion made of steel sheet. Each of its "ribs" acts as a natural radiator, increasing the oil's cooling surface area. When the internal temperature rises, the oil expands, and the corrugated walls flex elastically, compensating for the volume changes.

No conservator, valves, or breather pipes are needed – everything happens within a hermetic space.

This solution is ideal for distribution transformers and applications where compactness and maintenance-free operation are key. The lack of a conservator reduces the risk of moisture ingress and oil oxidation, thus extending its lifespan. Fewer moving parts also mean quieter operation and a smaller service footprint – engineers like that, and accountants even more so.

Tank with radiators – industrial-grade classic

For larger units (typically above 2.5 MVA), corrugated walls are insufficient.

This is where plate radiators come into play – vertical panels welded to the sides of the tank. They work like car radiators: hot oil rises, flows through the panels, transfers heat to the air, and then descends, creating a natural circulation (ONAN – Oil Natural Air Natural) or a forced one (ONAF – Oil Natural Air Forced) with fans.

Radiators can also be easily replaced and expanded, making this system more serviceable.

The downside is greater weight and the need for regular checks of weld integrity, but it offers better thermal stability under heavy loads. High-class designs additionally feature safety valves, thermometers, oil level gauges, and Buchholz relays, which react to gases generated during internal faults.

From steel to tightness – the engineering of precision welding

The foundation of every tank is steel with high purity and controlled carbon content. After the sheets are cut, the tank is welded using MAG or TIG methods, and the welds are tested with non-destructive methods – most commonly ultrasound or penetrant testing. Factories also perform pressure tests: the tank is filled with compressed air or helium and immersed in water to observe for any bubbles. Simple, yet effective.

After leak tests, the tank is chemically cleaned and degreased. The interior is coated with a special varnish resistant to transformer oil, while the exterior receives an anti-corrosion coating system tailored to the environmental category – from C2 for urban areas to C5-M for marine environments.

The sustainable direction – recycling and hot-dip galvanizing

Modern production increasingly emphasizes tank corrosion resistance and material recyclability. Hot-dip galvanizing can increase the coating's lifespan up to five times, which is particularly important in coastal and industrial areas. Interestingly, some manufacturers are also testing powder coatings based on nano-ceramics – lighter but just as durable as classic zinc.

For those interested in the details, it's worth visiting the Hydrocarbon Engineering portal, where research on protective coatings and welding techniques for the power industry is published.

Vacuum oil filling and heat cycling

At this stage, the transformer resembles an astronaut before a mission – ready, sealed, dry, and waiting only for the medium that will allow it to live.

That medium is transformer oil, which serves two functions: cooling and insulating.

Without it, the transformer would be like an engine without oil – it would overheat, lose its parameters, and fail faster than it could receive a serial number.

Oil under vacuum – the physics of pure calm

The process of vacuum oil filling is an engineering spectacle of Swiss watch precision. The active part of the transformer, now enclosed in its tank, is placed in a chamber where a deep vacuum is first created – typically below 1 mbar.

Why? Because even microscopic air bubbles trapped in the windings or insulation could later cause partial discharges and local overheating.

When the pressure reaches the required level, the slow filling with oil begins, usually from the bottom. The oil penetrates every gap, displacing the air. Sometimes the entire process takes several hours – especially for large power transformers requiring thousands of liters of oil.

The fill rate is strictly controlled to prevent the formation of gas pockets or pressure differentials that could damage the delicate insulation.

After filling, the unit is left undisturbed, still under vacuum conditions, to allow all micro-bubbles of gas time to rise and dissipate. Only then can the transformer be said to be "impregnated" – ready for the first flow of current.

Heat cycling – a spa for the windings

After filling comes the heat cycling process, which has two goals: to stabilize the structure of the paper and resins and to reduce residual moisture to an absolute minimum.

The transformer is maintained at a temperature of around 80–90°C for several hours. During this time, the oil and insulation reach a state of thermal and moisture equilibrium.

This isn't a stage visible from the outside – but it's when the transformer "matures." Every layer of paper, every impregnation, acquires its final structure. After this process, a key quality parameter is measured: the oil's breakdown voltage.

A value above 60 kV for a 2.5 mm gap indicates a perfect insulation system.

Oil quality and purity control

High-grade transformer oil (e.g., mineral oil like Nynas, Shell Diala, or synthetic fluid like MIDEL) undergoes a series of tests before use: measurement of dielectric strength, viscosity, dissipation factor (tan δ), and dissolved gas content.

Some manufacturers use Chromatographic Dissolved Gas Analysis (DGA), which can detect even trace amounts of hydrogen, carbon monoxide, or methane – signals that something might later go wrong inside the transformer.

Learn more:

Gas laws in DGA transformers: 5 rules that will warn you of a failure

To maintain its parameters for years, the oil must be perfectly clean – even a single drop of water or a dust particle per liter can reduce the breakdown voltage by several thousand volts.

Therefore, after filling, the system is hermetically sealed, and all bushings, breathers, and plugs are secured against contact with air.

When oil becomes a witness to history

An interesting fact for enthusiasts: in service, transformer oil retains a memory of the unit's life. Analyzing its composition allows experts to read how long the equipment operated under overload, if it experienced a short-circuit, and even what temperatures it reached in recent years.

In maintenance laboratories, it's from the oil that the first signs of insulation aging are read – long before any smoke appears from the tank.

Now that the transformer is sealed, filled and cooling down after heating, the final stage of its journey through the factory remains – routine tests and final checks that will determine whether it can be shipped out into the world and power its first network.

Routine tests and readiness for shipment

An oil transformer may look ready – closed, filled with oil, and shining with fresh paint. But until it passes its tests, it's merely a candidate for a transformer, not a full-fledged participant in the power grid. In the world of electrical power, final tests are like a state exam: there's no room for a second attempt.

Routine tests – or "mandatory exams of everyday life"

According to the IEC 60076 standard, every transformer must undergo a set of so-called routine tests before leaving the factory. Their goal is to verify that the device operates exactly as designed – without compromises, shortcuts, or guesswork.

• Winding resistance measurement – A test that detects interturn short circuits, connection discontinuities, and assembly errors. Even a small resistance difference between phases can reveal a loose terminal.

• Vector group and ratio verification – Checking that the voltage on the secondary side has the exact ratio specified in the design. This test immediately detects mistakes in the winding direction of the coils.

• No-load and load loss measurement – A true barometer of the quality of the core and windings. If values exceed norms, it indicates excessive magnetic losses (core) or resistive losses (windings).

• Impedance voltage measurement – A test simulating a short-circuit on the secondary side, checking the mechanical and electromagnetic stability of the system.

• Dielectric tests – One of the most critical tests, checking the insulation's resistance to impulse voltages and long-term operating voltage.

Every measurement is recorded and compared with the design values. A transformer that passes everything within tolerance receives a Factory Acceptance Test (FAT) certificate.

Additional tests for demanding applications

Depending on the voltage class and customer requirements, type tests (on reference units) or special tests are also conducted, for example:

• Sound level measurement to confirm compliance with environmental requirements (for urban units, this is often a condition for acceptance).

• Measurement of magnetic circuit losses at different temperatures.

• Partial Discharge (PD) test, assessing the cleanliness of the insulation and the quality of impregnation.

These tests are particularly important for transformers intended for use in sensitive networks or in prefabricated substations where the level of interference must be minimal.

Engineering Aesthetics: Preparation for Shipment

After passing all tests, the transformer enters a stage underappreciated in textbooks but highly valued by installation crews – preparation for transport.

This includes:

• Draining excess oil and filling hermetic tanks with nitrogen.

• Sealing all openings and securing transport fittings.

• Installing lifting lugs, sensors, and the rating plate.

• A final visual inspection of coatings and welds.

At this stage, the transformer looks ready for a parade: painted, labeled, tested, and packed in a steel transport frame. But before it hits the road, engineers perform a final vibration and leveling check to ensure nothing loosens or shifts during transit.

Documentation – The Transformer's DNA

Along with the unit, the customer receives a complete set of documents:

• Technical and operational documentation.

• Measurement and test reports.

• Oil test results.

• Material certificates for components used.

• Certificates for weld quality and anti-corrosion coatings.

This is the transformer's DNA – a record of its entire "life" from design to the final test. In practice, this documentation determines whether the unit will be approved for operation by the Distribution System Operator (DSO).

More on transformer testing standards and certification can be found in publications from the IEC Webstore, where current editions of the IEC 60076 standards and guidelines for routine and special tests are available.

And so its factory journey ends – the transformer, which has been through design, core, windings, tank, drying, oil, and tests, is ready to hear the hum of the grid for the first time and to see the world not through an engineer's microscope, but through the current that begins to flow within it.

Conclusion

The production of an oil transformer is a fascinating journey from an idea to a finished source of energy – a journey where engineering meets patience, and precision meets practice. Every stage – from design to final testing – is a testament to the fact that reliability is not born by chance, but from consistency and a respect for detail.

For years, we have supported designers, contractors, and grid operators in selecting solutions that will stand the test of time and operating conditions. We help choose the right type of transformer, optimize cooling, select oil and insulation systems for specific environments, and plan maintenance over the entire lifecycle of the equipment.

If you are working on a project where reliability, energy efficiency, and compliance with Ecodesign Tier 2 are crucial, we are here to translate technical requirements into real-world solutions.

Discover Energeks’ middle voltage transformers solutions, including:

• MarkoEco2 Ecodesign Tier 2 Oil Transformers – Selection of power rating, parameters, and cooling for specific environmental conditions.

• TeoEco2 Tier 2 Cast Resin Transformers – For facilities with high safety requirements and limited space.

• Units available immediately, full documentation, 60-month warranty – for selected medium voltage models.

If you want to stay updated with our technical analyses, practical tips, and case studies from construction sites, join the Energeks community on LinkedIn. It's a place where we share knowledge without marketing fluff – substantively, practically, and with respect for the industry we help build.

Thank you for your trust and the opportunity to be part of projects where sense, precision, and safety are as important as innovation. If you need to clarify technical requirements, select a model, or prepare an acceptance checklist for your investment – just send us a message.

Let's do it together.

References:

1. IEC 60076 1-3 – Power Transformers. International Electrotechnical Commission

2. CIGRÉ Technical Brochures

3. MDPI Energies - MDPI researches

4. Siemens Energy - Power Engineering Guide

Autumn-winter morning.

Dawn is just beginning to filter through the pine needles. On a white meadow, a transformer station stands alone, yet alive.

A light mist rises from the tank, like a breath in the frosty air. The engineer beside it looks up at the silvery vessel above the transformer. It is the oil conservator.

A metal safety shell that many mistake for an unnecessary accessory.

The question keeps coming back like a boomerang: does a transformer need an oil conservator?

In practice, the choice between an oil-immersed transformer with a conservator and a hermetically sealed design depends on the operating environment, load profile, diagnostic strategy, and requirements of the distribution system operator (DSO).

This article gathers both textbook knowledge and field experience in one place, clarifying concepts and showing the technical implications of each approach. We do not promote either option; instead, we compare them fairly so that the decision can be made predictably over the transformer’s entire life cycle.

At Energeks, we work with medium-voltage substations, transformers, and switchgears in diverse climatic and operational conditions. We see where hermetically sealed designs shine with simplicity and minimal maintenance, and where an additional compensating volume and traditional diagnostics provide operational peace of mind. This text distills those lessons into practical criteria.

The decision is not about conservator versus modernity.

It is about context versus coincidence.

A properly selected transformer reduces risk, costs, and the temperature of emotions during acceptance.

Who is this article for?

For designers, contractors, operators, and investors who want to select a transformer consciously, based on location, load profile, and maintenance policy. After reading, you will gain the knowledge needed to make better decisions, understand when an open oil circulation system makes sense, when a hermetically sealed unit is sufficient, how to plan diagnostics and maintenance, and how to avoid the most common mistakes.

Agenda

• Oil conservator in a transformer: what it is and how it works

• Transformer with an oil conservator: when to use it

• Transformer with an oil conservator: when it is necessary

• Selecting an oil-immersed transformer: service and operational best practices

• Maintenance comparison: hermetically sealed transformer vs. transformer with conservator

Reading time: approximately 10 minutes

1. Oil conservator in a transformer – what it is and how it works

Imagine a transformer as the powerful heart of the electrical grid.

It pulses with current, responds to load fluctuations, heats up, and cools down. And like any heart, it needs space to beat in rhythm. For a transformer, that space is provided by the oil conservator – a modest cylindrical tank mounted above the main vessel.

It absorbs changes in the volume of oil as it expands in the heat and contracts in the cold.

Technically speaking, the oil conservator is a compensating reservoir connected to the transformer tank by a pipe through which the oil can flow freely. Inside, there is an air space, and between that space and the atmosphere operates a breather filter, also known as an air dryer – a small device filled with silica gel that removes moisture from the incoming air.

This setup allows the transformer to “breathe” without drawing in water, dust, or oxides.

It protects both the paper insulation and the oil from humidity, preventing premature aging.

If this description reminds you of anatomy, that is intentional.

A transformer with an oil conservator truly behaves like a living organism: during operation, it exhales heat and gases, and when it cools down, it inhales air. Without a conservator, it would also absorb moisture – and that moisture is to insulation what rust is to steel.

So, when someone asks “What is an oil conservator in a transformer?”, the answer is simple: it is a system that protects the oil from moisture and oxidation, extending its service life and maintaining stable electrical properties. In practice, the conservator often determines whether the oil will last thirty years or ten.

But its function doesn’t end with breathing.

The conservator also serves as a diagnostic indicator. It is equipped with a float-type oil level gauge, showing how the oil volume changes depending on temperature and load.

A sudden drop in oil level may indicate a leak, overheating, or an early sign of failure. For an experienced technician, this gauge is like the patient’s pulse – a small movement can reveal a great deal.

In higher-power units, the conservator also works together with a Buchholz relay, which detects gases generated by winding faults.

Thanks to this, the system can alert operators to a developing issue before it becomes critical.

In short: the conservator is the breath and the memory of the transformer.

And if someone asks, “When is a transformer with a conservator necessary?”, one might half-jokingly say: whenever you want your transformer to have healthy lungs and a long life.

A conservator is not always necessary

It is important, however, to maintain an engineering sense of balance.

A conservator is not a magical cure-all, and its absence does not signify a flaw in design.

Modern sealed transformers are not an inferior version; they represent an entirely different design philosophy.

Instead of the classic "breathing" provided by a conservator, their tank is completely sealed.

The changes in oil volume are compensated for by flexible corrugated walls or an internal elastic diaphragm.

This means the oil has no contact with the outside air whatsoever – it doesn't require a breather filter, it cannot absorb atmospheric moisture, and there is no need to monitor silica gel.

This solution proves its worth in environments that are clean and predictable: in indoor switchgear rooms, containerized substations, energy storage sites, and modern industrial facilities.

A sealed transformer requires less additional equipment, making it less susceptible to operator error and simpler to maintain. For many investors, this is a significant advantage – fewer inspections, fewer potential points for leakage, and lower operational costs.

Therefore, it is incorrect to claim that a transformer with a conservator is "better," and a sealed one is "worse."

They simply have different temperaments.

One is lik

e a marathon runner – built for endurance and resilience in changing conditions. The other is like a sprinter – compact and precise in a controlled environment.

A good engineer does not choose out of habit, but based on context: temperature, humidity, location, and the device's duty cycle.

So, if someone tells you a conservator is "mandatory," it's wise to smile and ask:

What is your actual operating environment?

Perhaps, instead of needing "lungs," what you truly need is a well-sealed construction that will operate reliably for its full 25-year lifespan in hermetic tranquility.

In the next part of this article, we will examine this with technical curiosity:

• Where a transformer with a conservator truly makes sense.

• Where a sealed design is the more rational choice.

We will compare how the two designs handle temperature, moisture, and oil aging.

We will also explore the real-world advantages of a conservator tank in practice and answer the question of when it is worth choosing one, and when a simpler sealed transformer will be the better option.

Because in engineering, as in life – more is not always better.

2. Transformer with an oil conservator – when to use it

The question “when to use a transformer with an oil conservator” is far from academic. In practice, the decision depends on the operating environment, the load profile, and the maintenance philosophy of the facility.

To clarify: the conservator is a compensating tank connected to the transformer vessel, allowing the oil to “breathe” as its temperature changes. The air entering from the outside passes through a silica gel breather, which captures moisture to prevent the degradation of insulation and the loss of dielectric properties in the oil.

Modern standards – including PN-EN 60076-1 and IEC 60076-7 – do not mandate a specific design type. Instead, they emphasize that the choice depends on operational conditions.

The selection criteria and the influence of environmental factors are discussed in detail in: IEC 60076-7: Loading guide for oil-immersed power transformers

And this brings us to the core of the matter: a conservator is neither better nor worse than a sealed design. It is simply a different method for managing the thermal expansion of the insulating oil.

Environments where a conservator makes sense

So, when is the environment favorable for a conservator?

Typically, in applications with significant temperature fluctuations—exceeding 50–60 °C annually—or where the thermal load changes dynamically. In these cases, the conservator acts as a pressure and temperature buffer, reducing mechanical stress on the main tank and enhancing the overall thermal stability of the system.

This solution is still commonly found in higher-power transformers (above 2.5 MVA) or those with on-load tap changers (OLTC), where easy diagnostic access and the use of classic Buchholz gas protection are important.

Furthermore, in locations with high humidity or significant microclimatic variability, a conservator can be beneficial—it helps limit moisture ingress into the system and slows down the oil aging process.

However, it must be emphasized: such a system requires oversight. If the breather filter is not regularly serviced, it can itself become a source of contamination, and its advantages are quickly lost.

Where a conservator is not needed

For the majority of modern installations, there is no longer a necessity to use a conservator.

Sealed transformers, with their corrugated tank walls or flexible diaphragms, compensate for oil volume changes without any contact with the external air. This reduces the need for servicing, eliminates breathers, and minimizes the risk of contamination. This is why in containerized substations, urban medium-voltage switchgear, at energy storage sites, PV farms, or within e-mobility infrastructure, the sealed design has become the default choice.

This is not a matter of trends, but of the operating environment.

In a temperate climate, with limited humidity and stable temperatures, a conservator offers no real advantage—it merely adds more components that require monitoring and maintenance.

In many contemporary projects, a standard transformer with a conservator is not so much an option as it is superfluous.

So when does a conservator come back into play?

When a project demands high thermal stability, easy diagnostic access, and compatibility with a Buchholz relay, the conservator remains a justified solution—not out of habit, but due to physics.

In high-power transformers, where the oil volume is measured in thousands of liters, temperature changes cause significant pressure differentials. The conservator then acts as a dampener—it absorbs the excess fluid during heating and returns it during cooling. It stabilizes internal pressure, relieves stress on seals, and slows the aging rate of the insulation.

The second area is diagnostics. A system with a conservator allows for easy visual or SCADA-sensor monitoring of the oil level, as well as simple oil sampling for Dissolved Gas Analysis (DGA). DGA is a crucial tool for assessing the condition of the paper-oil insulation, and in a sealed transformer, it can be more complicated as it may require breaking the tank's seal and risks exposing the sample to air.

The third aspect is gas protection—the Buchholz relay.

Mounted in the pipe between the main tank and the conservator, it reacts to gases generated by internal overheating or minor winding faults. Its operation is purely mechanical, requiring no external power—which is why it remains one of the most reliable protections for oil-filled transformers. In sealed transformers, where there is no gas cushion, the Buchholz relay simply has no place to function.

These requirements are found mainly in medium and large power network transformers, municipal infrastructure, and transmission substations, where durability, predictability, and rapid diagnostics are valued over absolute maintenance-freedom.

In these cases, the conservator is not a relic, but a functional element of the safety architecture.

In short then:

When to choose a transformer with a conservator?

• When the project demands superior thermal stability and pressure management.

• When full diagnostic control and easy oil sampling for DGA are required.

• When compatibility with a classic, highly reliable Buchholz relay protection system is necessary.

And when to opt for a sealed transformer?

• In the majority of modern projects located in temperate climates.

• Where the top priorities are simplicity, cleanliness, and minimal maintenance.

This is not a competition between solutions, but a matter of matching the right technology to the specific context. For the engineer, the goal is not to champion one design over another, but to ensure that the transformer operates for a long time, reliably and safely, precisely in the environment where it is installed.

Transformer with conservator at a power station. The visible conservator tank is located above the vat, which allows for oil volume compensation and protection against moisture. The photo shows a robust industrial design used in medium and high voltage networks.
Photo Credit: Johann H. Addicks, via Wikimedia Commons (CC BY-SA 3.0).

3. A conservator for a transformer when is it necessary

There are certain scenarios where a conservator moves from being a simple option to an absolute necessity.

This isn't about a preference for classic designs or nostalgia for "old, reliable" solutions. It's about situations where the operating conditions, the specific demands of the operator, or the fundamental physics of the system mean that a sealed transformer simply won't suffice.

In this section, we will explore the circumstances that make a conservator a technical requirement, focusing on standards, operational practicality, and safety.

3.1 Requirements of distribution system operators (DSOs)

Distribution system operators across Poland and Europe are increasingly implementing technical specifications that clearly mandate the use of a conservator.

This typically applies to high power installations, with an operational lifecycle measured in decades think 30 years or more. For such critical assets, the focus shifts from the lowest initial investment to the total cost of ownership over the equipment's entire life. DSOs prioritize solutions that can be easily diagnosed, serviced, and whose behavior is predictable.

A conservator meets these criteria perfectly. With its oil level gauge, Buchholz relay, and the ease of drawing oil samples, it provides the operator with vital health information about the unit often before the alarm system is even triggered. It’s a design that offers transparency into the transformer's condition.

For a deeper dive into Buchholz relay systems and conservators, refer to the CIGRE Technical Brochure 445 – Transformer reliability survey

3.2 When the environment demands flexibility

The second category involves challenging climatic conditions significant temperature swings, prolonged periods of freezing cold or intense heat, substations without air conditioning, or those with limited ventilation. In these environments, a sealed transformer, while theoretically maintenance free, can be pushed to the limits of its mechanical resilience.

In a closed system, every rise in temperature causes a corresponding increase in internal pressure. Under sustained load, this continuous pressure cycling can lead to micro fractures or deformations in the corrugated tank walls.

In a sealed unit, even minor leaks are critical; they break the vacuum, expose the insulating oil to air, and trigger accelerated degradation of the paper insulation.

A conservator eliminates this core problem. Its function can be compared to a heart's atrium it acts as a buffer, absorbing the pressure pulsations and allowing the entire system to maintain a stable rhythm.

The oil is free to expand and contract without risking mechanical overload, and any air exchange with the atmosphere is carefully managed through a controlled, dry breather filter.

3.3 Longevity and parameter stability

In infrastructure projects like MV/LV distribution substations, industrial plants, municipal utilities, or large manufacturing facilities, the expected service life of the equipment can stretch to thirty years.

Over such a long time horizon, ease of diagnostics and long term thermal stability become far more critical than a minimal footprint or a "maintenance free" label.

A transformer equipped with a conservator enables planned oil quality checks, dissolved gas analysis (DGA), assessment of insulation aging, and a rapid response to the earliest signs of a fault. With a sealed transformer, many of these essential diagnostic activities require breaking the tank's integrity which is not only a costly procedure but also introduces the risk of human error during reassembly.

3.4 When simplicity is not enough

Seated transformer designs are excellent, but they do have their limitations.

In high temperature applications, where there are significant power losses and load cycles frequently approach maximum ratings, the lack of a pressure buffer becomes a genuine operational liability.

After several years, the cumulative effect of pressure differentials can weaken welds, cause distortions in the main tank, and lead to leaks that are, for all practical purposes, impossible to repair without replacing the entire unit.

A conservator serves as a straightforward mechanical safeguard against this exact scenario.

It is not needed for every installation but in applications where oil longevity and thermal stability are paramount to reliability, its inclusion is thoroughly justified.

3.5 Summary

A transformer with a conservator is necessary when:

• The unit has a high power rating and a long expected service life.

• It operates in an environment subject to large temperature variations.

• It requires classic gas protection (Buchholz relay) or demands ongoing diagnostic capabilities.

• The substation lacks air conditioning or active cooling systems.

• The local distribution system operator (DSO) mandates a conservator system for safety and technical monitoring reasons.

Under these conditions, the conservator is far from an anachronism; it is a vital tool for stabilization a mechanical heart atrium that ensures the transformer continues to beat calmly and reliably for decades to come.

4. Oil transformer selection, service and good practices

Having decided, after analysing the conditions, requirements, and risks, that a transformer with a conservator is the right choice for our project, one question remains:

how do we use it to ensure it truly fulfils its purpose.

A conservator does not operate in a vacuum—it requires a measure of attention, regularity, and engineering discipline.

A well-maintained conservator is a guarantee of long oil and insulation life, whereas a neglected one is a source of predictable problems.

This section covers the four most critical areas that determine transformer reliability: maintaining the breathing system, monitoring oil level and quality, selecting the right conservator for the operating conditions, and day-to-day operation in the context of grid stability.

4.1 Maintaining the transformer's breathing

A conservator is an open system that interacts with the environment—this is why its breather, also known as an air filter with a dehydrating breather, is the first line of defence against moisture.

Filled with silica gel, it filters the air drawn into the transformer when the oil volume decreases due to a drop in temperature.

Over time, the gel gradually becomes saturated and changes colour—from blue or orange to pink. This is a simple but highly reliable indicator of when a replacement is needed.

Inspections of the dehydrating breather should be carried out every 6 to 12 months, and even more frequently in high-humidity environments. It is also important to check the condition of the connections and the cleanliness of the pipe connecting it to the conservator. Contamination can restrict airflow, which may lead to an increase in tank pressure and cause unwanted mechanical stress.

A good practice is to maintain a breather log—recording the dates of gel changes and its colour at the time of inspection.

In the long term, this helps identify correlations between seasonal operation and the saturation level of the desiccant.

4.2 Monitoring oil level and quality

The life of a transformer with a conservator follows the rhythm of its oil—the oil level and condition are the most transparent indicators of the system's health. Fluctuations in the level of around 5–10 percent are normal and result from temperature changes and load cycles.

Sudden drops, or a lack of change despite significant temperature differences, should raise concern—they could indicate a minor leak, a blockage in the pipe connecting the conservator to the main tank, or a damaged level indicator.

Once a year, it is advisable to conduct an oil test in accordance with the PN-EN 60422 standard. The key parameters are:

• Dielectric strength

• Water content

• Acid number

• Dissolved gas content (DGA)

If analysis indicates degradation, the oil can be processed through filtration or regeneration.

In cases of deep oxidation—a complete oil change will be necessary.

Regular testing not only extends the system's lifespan but also provides valuable diagnostic data for predictive maintenance.

For practical operational guidance on oil quality and replacement, an excellent resource is

IEEE Std C57.106-2015 – Guide for Acceptance and Maintenance of Insulating Oil in Equipment

4.3 Selecting a conservator for the environment and load

Not all conservators are the same.

In photovoltaic and electric mobility projects, the transformer load changes dynamically—in PV systems with sunlight intensity, and in EV charging stations with daily and nightly rhythms. Such variations cause frequent thermal cycles, which require a conservator with an appropriately selected capacity and air exchange efficiency.

In environments exposed to dust, salinity, or high humidity, breathers with a higher IP protection rating and replaceable filter cartridges should be used.

An alternative is conservators with an internal membrane or a nitrogen cushion system, which eliminate direct contact between the oil and air while retaining the ability to compensate for pressure.

Such solutions are increasingly used in infrastructure projects with heightened environmental requirements.

4.4 Good operational practices

The foundation of the system's longevity is routine observation—what one might call engineering common sense.

In practice, this means:

• Checking the breather and the oil level indicator at least twice a year.

• Inspecting the cleanliness of the conservator's housing and connections.

• Measuring the top-oil temperature and comparing it with historical trends.

• Documenting all inspections, even the most minor ones, in an operational log.

This is not bureaucracy—it is the life history of the equipment. This record allows for the prediction of component wear and the planning of replacements before a failure occurs.

4.5 Grid stability and smart maintenance

A transformer with a conservator does not require daily attention, but it thrives on rhythm and systematic care. Just a few minutes of observation and an annual review are enough to keep the system stable for decades. A well-maintained conservator is not a cost—it is an investment in peace of mind.

After all, its role is simple: to cushion thermal stress, maintain balance, and allow the entire installation to breathe.

Is a conservator a luxury or a necessity for grid stability? It's a question each medium-voltage substation answers for itself—usually at the moment when the network truly begins to breathe at full capacity.

5. Maintenance comparison: sealed oil transformer versus transformer with a conservator

At first glance, both devices look identical: a tank, bushings, radiators, and a thermometer.

Yet, their day-to-day operation represents two different worlds.

A sealed oil transformer is a closed, modern construction with corrugated walls that compensate for the thermal expansion of the oil. Everything happens inside—without air access, without gas exchange, and without a conservator. It is a solution designed with simplicity and operational cleanliness in mind.

The user does not need to check the machine's 'breathing'; they only monitor pressure, temperature, and the condition indicators for the oil.

The version with a conservator operates on a completely different rhythm.

This transformer breathes. The oil travels between the main tank and the expansion tank, and the air that enters the system passes through a breather filter filled with silica gel.

This seemingly minor detail acts as the transformer's lungs—it dries the air and prevents water vapor from condensing inside. However, it requires regular inspection, typically every 6 to 12 months, because moist gel loses its properties and can end up introducing contaminants into the system instead of protecting it.

A sealed oil transformer is, in essence, a self-sufficient system.

Temperature, pressure, and oil condition are all monitored by sensors like RIS2 or DGPT2.

The system signals anomalies but does not require "manual" oversight.

One could call it a minimalist transformer—designed for environments with stable operating conditions where cleanliness, a small service footprint, and the absence of air exchange are valued.

In contrast, a transformer with a conservator is a design for the engineer who likes to have everything under control.

The oil level indicator, the ability to take oil samples for DGA, the visible Buchholz relay float that reacts to the smallest amounts of gas—these are all features that allow for intervention before a fault fully develops.

In exchange for regular review, the conservator offers full transparency: the user sees how the oil behaves, knows its color, and can tell when something deviates from the norm.

The differences in maintaining these transformers are significant

A sealed transformer requires just one annual review, limited to reading key parameters and checking for leaks.

A transformer with a conservator needs a semi-annual ritual: assessing the color of the silica gel in the breather, checking the oil level, cleaning the housing, and potentially topping up the fluid.

But in return, it offers diagnostic depth—the ability to "read" the condition of the equipment almost like an EKG reading.

In summary, a sealed oil transformer is like a quartz watch: precise, sealed, and maintenance-free.

A transformer with a conservator, on the other hand, is like a mechanical chronograph: it requires care and attention, but it provides complete insight into its inner workings and rewards that care with longer, more predictable, and transparent operation.

Both solutions are excellent, each within its intended environment.

You choose the first when you prioritize peace of mind and minimalism.

You choose the second when you value a connection to the equipment, deep knowledge, and hands-on control.

After all, in power engineering—as in life—the goal isn't always to have less to do, but to know exactly what is happening beneath the surface.

Conclusions

After this journey through temperatures, humidity, and diagnostics, the conclusion is simple.

There is no inherently better or worse design in an absolute sense. It's all about selecting the right solution for the specific context.

A sealed transformer offers cleanliness and minimal maintenance for a stable environment.

A transformer with a conservator provides thermal flexibility, diagnostic insight, and classic gas protection where the elements can be unpredictable. The true advantage lies in a decision supported by data, lifecycle analysis, and an honest conversation about risks.

If you are facing this choice today, ask yourself three questions:

1. What are the temperature swings and humidity levels at the operating location?

2. How quickly and how often does the load change?

3. What diagnostic and protection strategy do you want to have for the years to come?

The answers will point you in the right direction more accurately than any marketing slogan.

Finally, a thought for the mind that appreciates concrete details:

What more reliably secures an investor's peace of mind?

Flawless installation of a sealed transformer where the climate is predictable?

Or a conservator with a well-executed maintenance plan where the weather and load profile dictate the rhythm?

This question will lead you to the right decision more often than a long list of arguments.

Collaborate with us!

For years, we have helped designers, contractors, and operators select solutions tailored to real-world operating conditions.

If you need support in the selection process, we will prepare a recommendation with technical justification and a risk calculation over the entire lifecycle.

Explore our offerings and check availability:

• Oil immersed transformers Tier2, parameters and selection for environment and load profile
  Energeks Oil Transformer Offer

• Dry transformers, compliant with Ecodesign Tier 2, for facilities with high environmental requirements
  Energeks Cast resin Transformers Tier 2 Ecodesign

• Off-the-shelf delivery and an extended five-year warranty for selected models
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If you wish, we can refine this material for your specific investment or prepare an acceptance checklist for your chosen variant. We are here for you

References:

• https://webstore.iec.ch/publication/2230 – IEC 60076-7: Loading guide for oil-immersed power transformers

• https://www.e-cigre.org/publications/detail/642-transformer-reliability-survey.html – CIGRE Technical Brochure 445: Transformer Reliability Survey

• https://ieeexplore.ieee.org/document/7442048 – IEEE Std C57.106-2015: Guide for Acceptance and Maintenance of Insulating Oil

Imagine this: You bought a beautiful plot for your future home. There is calm, greenery, birdsong...

...And then you notice a primary substation or a medium voltage pole sitting practically next door.

Is this the end of the dream, or a challenge you can handle?

In this article we will show how close you can live to a substation, what the rules and realities look like across the EU, and what safety really means in the context of a residential investment.

We write from the perspective of specialists in transformers, switchgear and power infrastructure, because at Energeks we believe technology and people can coexist, and that building systems that truly work is not only about parameters but also about values such as transparency, responsibility and everyday comfort.

If you are an investor, developer, designer or someone planning your own home, this article is for you.

After reading you will know what distances are recommended or required from substations and power lines, what standards say about electromagnetic fields, how to separate real risks from myths, and which tools to use to check your plot of land, for example a map of primary substations and a transformer map.

Agenda:

• What is a substation or primary substation and why its location matters

• How close can you live to a substation? Rules, codes and realities

• Electromagnetic fields, radiation and whether a transformer is harmful to health. Facts vs myths

• Planning a residential investment near power infrastructure. Tools, tips, case study

• How to talk with an investor or neighbor who is afraid of the transformer next door. Education, dialogue, values

• Balancing the need for energy with the comfort of living

Reading time: ~ 12 minutes

1. What is a transformer station or primary substation and why its location matters

At first glance, a transformer station might look like a mysterious concrete box surrounded by a fence, humming softly on hot days.

But behind that unassuming façade hides one of the most important pieces of modern civilization. Every flick of a light switch, every coffee brewed, every data server and tram ride depends on these quiet guardians of voltage.

Understanding what a transformer station or primary substation does is like learning how the heart pumps blood through the human body — only instead of blood, it’s electricity that keeps everything alive.

1.1. What exactly is a transformer station

A transformer station is a point in the grid where voltage changes its “personality.”

Electricity leaves power plants at high voltage to travel efficiently over long distances.

When it reaches a city or industrial area, it must be tamed — stepped down to safer levels for local distribution. That’s what the transformer station does: it translates high voltage into a form that your coffee machine and laptop can understand.

Depending on its function, a station can:

• Step down electricity from medium to low voltage (for homes and offices),

• Step up voltage (for long-distance transmission),

• Or simply distribute energy across various network sections.

Think of it as a postal hub for electrons: it sorts, redirects and delivers energy where it’s needed, without letting any of it get “lost in transit.”

1.2. What is a primary substation

A primary substation is the big sibling in the electrical family — larger, more complex, often connecting transmission lines (110 kV and above) with medium voltage networks (10–30 kV).

It is the bridge between the national grid and the local distribution system.

Inside, you’ll find:

• Power transformers, each the size of a truck and weighing tens of tons,

• High and medium voltage switchgear,

• Busbars that carry thousands of amps of current,

• And control systems that monitor everything down to a single circuit breaker.

It’s an orchestra of copper, steel and silicon — where a fraction of a second matters.

1.3. Why location matters more than most people think

The location of a substation isn’t chosen randomly or aesthetically.

It’s an engineering balance between safety, reliability, and practicality.

A few key factors explain why its position is so carefully chosen:

• Voltage and power levels: The higher the voltage, the larger the safety perimeter needed.

• Cooling and ventilation: Transformers get warm when they work hard. Stations need space for air circulation or oil cooling systems.

• Maintenance access: Engineers need to reach the equipment safely with cranes, vehicles or testing gear.

• Environmental impact: Noise levels, electromagnetic fields, and fire safety requirements define minimum distances from residential zones.

• Grid efficiency: The closer the substation is to demand centers, the lower the energy losses in transmission.

In other words: it’s not about hiding the substation, but about placing it where it can quietly do its job without disturbing anyone — a good neighbor, not a noisy one.

1.4. Why technology and land choice are about more than concrete and cables

Electricity is invisible, but the infrastructure behind it shapes our daily lives in ways we barely notice. When choosing a plot, most people look at the view, the sun exposure, or the nearest café.

But few check where the nearest primary substation sits.

And yet, that small box on the horizon might determine whether you’ll have reliable power during a summer heatwave.

Here’s a secret known mostly to grid engineers: the most valuable land is not always the most remote.

A plot that’s “too close” to a substation often has a faster and cheaper connection point, lower connection costs, and fewer voltage drops.

Ironically, the quiet hum behind the fence could mean your house will always have stable voltage while others experience flickering lights.

So the question isn’t just “how far” you are from a substation, but “how well” that system has been designed, shielded and maintained.

1.5. When infrastructure and daily life learn to coexist

Across Europe, urban planners are increasingly designing integrated substations — compact, aesthetic and almost invisible.

In Germany and the Netherlands, substations are often built into housing blocks, wrapped in green façades, or hidden beneath parks.

In Denmark, you might walk over one without realizing it’s there.

The modern substation is no longer an eyesore but an architectural challenge: how to make the beating heart of a city’s power supply blend naturally into its rhythm.

The goal is coexistence, not separation. Technology doesn’t have to dominate the landscape; it can live within it.

A primary substation in a semi-desert landscape, showcasing modern energy infrastructure designed for reliable power distribution, safety and resilience under extreme conditions. Such installations demonstrate how advanced grid engineering ensures stable, secure electricity supply even in remote regions.
Photo © Hector Espinoza via Unsplash

The next section will explore how close you can actually live to a substation, what European regulations recommend, and why — when it comes to electricity — common sense and good engineering often go hand in hand better than fear and rumor

2. How close can you live to a substation? Rules, codes and realities

Here’s where physics meets planning permission and the internet meets anxiety.

Ask ten people how close you can live to a transformer station and you’ll get ten different answers — from “five meters is fine” to “never less than 300.”

The truth, as always, hides in the details, buried somewhere between electrical codes, geometry and good engineering practice.

Let’s unpack what those details mean in real life.

2.1. There is no magic number

There isn’t a single European law that says:

“Thou shalt live exactly X meters away from a substation.”

What exists are engineering standards, fire safety codes, and environmental noise and EMF guidelines — all of which depend on the type of installation, its voltage, and the local context.

For example:

• A small low voltage distribution kiosk (0.4 kV) that feeds a few homes can sit just 3–5 meters from a building wall, as long as it is properly enclosed and ventilated.

• A medium voltage substation (10–20 kV) usually keeps 10–20 meters of clearance from dwellings, depending on the insulation fluid (dry or oil-filled) and noise level.

• Large primary substations that handle 110 kV or more often need 20–50 meters of open space, both for cooling and for safety in case of internal arc faults.

If you see someone quoting a universal “safe distance,” they’re probably oversimplifying.

Electricity doesn’t read blogs; it follows magnetic flux lines and thermal gradients.

2.2. What the standards really say

Across the EU, safety around electrical installations is defined by a patchwork of technical norms.

You’ll find relevant guidance in:

• EN 61936-1 (Power installations exceeding 1 kV AC) – specifies minimum clearances and access zones.

• EN 50522 – defines grounding and step voltage limits for substations.

• EN 60076 series – covers transformer design and insulation coordination.

• IEC 62271 – for switchgear and controlgear safety.

These documents read like poetry to electrical engineers: line after line of distances, radii and resistances, all meant to ensure that even in a worst-case scenario, nobody outside the fence gets hurt.

Typical requirements include:

• 2.8 m minimum separation between a substation room and living spaces in a shared building.

• Fire-rated walls between transformers and adjacent areas.

• 10–15 m spacing for outdoor oil-filled transformers from any structure that could catch fire.

So while local planning offices might not list “minimum transformer distance” in plain words, these numbers quietly shape every blueprint.

2.3. The role of electromagnetic fields (and why you shouldn’t panic)

Much of the public concern around substations isn’t about fire or noise, but electromagnetic fields (EMF).

Let’s set the record straight: EMF from a substation decreases rapidly with distance.

It’s like the warmth from a campfire — strong when you stand close, barely noticeable a few meters away.

Typical magnetic field values around a medium voltage substation:

• 0.5 to 5 microtesla at the fence line,

• falling below 0.2 microtesla within 10–20 meters.

For context:

• A hair dryer produces 30–70 microtesla.

• An induction hob: 50–100.

• A commuter train: up to 300.

EU reference levels (ICNIRP 2020) allow up to 100 microtesla for the general public.
In short: your kitchen appliances expose you to more magnetic field than your local substation.

That soft hum you hear on summer evenings? It’s not radiation — it’s magnetostriction, tiny vibrations in the steel core of the transformer as it expands and contracts 100 times per second.

The sound is harmless, and to many engineers, oddly comforting — the pulse of a healthy grid.

2.4. Practical safety distances across Europe

Even without one universal law, patterns have emerged in design practice:

• United Kingdom: Guidelines suggest keeping substations about 25–50 meters from sensitive buildings like schools or hospitals, though smaller pad-mounted units can be much closer.

• Germany: The DIN VDE 0101 standard relies on risk-based spacing, often 10–15 meters for 20 kV installations.

• France: EDF specifies at least 7 meters clearance for MV substations, increasing to 15 meters for oil-cooled types.

• Spain and Italy: Typically 10–30 meters depending on terrain and access routes.

• Nordic countries: Compact urban substations may even share walls with residential structures, provided they use dry-type transformers and acoustic isolation.

In other words, Europe’s experience shows that context beats distance.
What matters is not how far, but how well the installation is designed, shielded and maintained.

2.5. The hidden benefit of proximity

Here’s a paradox: living too far from a substation can also be a problem.
The longer the low-voltage lines, the higher the energy losses and the more unstable your voltage becomes.

A nearby substation means fewer flickering lights, faster fault response, and better grid reliability.

So when someone complains: “There’s a transformer near my house,” the right reply might be:

“Lucky you — your power quality is probably excellent.”

2.6. The common-sense conclusion

If you live within 10–30 meters of a small or medium substation, and it’s modern, enclosed and maintained by your Distribution System Operator (DSO), there’s no reason for fear.

Measurements across thousands of European sites show exposure levels far below safety thresholds.

When in doubt, ask for documentation: acoustic tests, EMF readings, or the operation and maintenance documentation (O&M manual).
Data beats speculation every time.

A safe distance, then, is not just a number — it’s a relationship built on good engineering and good communication.

Next, we’ll dig deeper into the science of electromagnetic fields — what they really are, what they are not, and why physics is often kinder than online forums suggest.

3. Electromagnetic fields, radiation and whether a transformer is harmful to health. Facts vs myths

This is where engineering meets human imagination.

The phrase “electromagnetic radiation” tends to trigger alarm bells — it sounds like something out of a sci-fi movie.

In reality, the fields around transformers are some of the most predictable and well-studied phenomena in modern physics.

They’re also a perfect example of how something invisible can be misunderstood simply because it’s invisible.

3.1. What kind of field are we talking about?

Every transformer generates an electromagnetic field (EMF).

It’s not dangerous, mysterious or radioactive. It’s simply the natural by-product of alternating current.

Electric fields come from voltage. Magnetic fields come from current. Together they form an EMF that oscillates at 50 hertz — the same gentle frequency that powers your kettle.

The field weakens extremely quickly with distance. At one meter from a medium-voltage transformer, it drops by about 90 percent. At five meters, it’s barely measurable. The curve falls off faster than the smell of freshly brewed coffee when the window is open.

3.2. What the measurements actually show

Across Europe, countless studies and monitoring programs have measured EMF near substations. The numbers are boringly consistent:

• Typical magnetic field at the fence: 0.5 to 5 microtesla.

• At ten meters distance: below 0.3 microtesla.

• At twenty meters: often indistinguishable from background levels.

Compare that to ordinary household devices:

• Hair dryer: 30–70 microtesla.

• Vacuum cleaner: 20–200 microtesla.

• Induction cooktop: up to 100 microtesla.

• Electric train ride: several hundred microtesla.

The European reference limit for public exposure is 100 microtesla. In other words, the invisible halo around your blender is stronger than the one around your neighborhood transformer.

3.3. Why we still worry

The human brain is wired to fear what it cannot see.

The gentle hum of a transformer, the fenced enclosure, the warning sign — all the visual cues suggest danger.

Yet the hum is nothing more than magnetostriction, the vibration of steel sheets expanding and contracting as magnetic flux changes direction 100 times per second.

Engineers know this sound well. It’s the heartbeat of the grid — a steady, 100-hertz reassurance that power is flowing.

Still, people hear “radiation” and imagine X-rays.

Let’s be clear: the EMF around substations is non-ionizing. It cannot break chemical bonds, damage DNA or make anything glow in the dark. It’s more like the rhythmic sway of a pendulum than the sharp beam of a laser.

3.4. What science actually says

The World Health Organization (WHO), the International Commission on Non-Ionizing Radiation Protection (ICNIRP), and dozens of national health agencies have reviewed hundreds of studies.

Their conclusion is as consistent as Ohm’s law:

At exposure levels found near power lines and substations, there is no confirmed evidence of health effects.

There have been isolated epidemiological correlations — for instance, small statistical links between long-term exposure above 0.3 microtesla and certain childhood conditions — but correlation is not causation.

The effect vanishes when confounding factors such as urban density or socioeconomic status are included.

That’s why every major health authority in Europe keeps the same guidance: observe ICNIRP limits, monitor installations, and design infrastructure conservatively.

3.5. The quiet truth about noise

If there is any discomfort associated with substations, it’s usually acoustic, not electromagnetic.

The hum, typically between 35 and 45 decibels, is equivalent to the sound of a quiet refrigerator.

At night, when everything else falls silent, it can feel louder simply because contrast makes perception sharper.

Modern designs include acoustic insulation, vibration damping and dry-type transformers that use epoxy resin instead of oil.

In many new European housing projects, residents don’t even realize that a substation sits beneath their courtyard.

3.6. Humor, context and human scale

Engineers sometimes joke that standing next to a transformer exposes you to fewer magnetic fields than standing next to your cat — assuming the cat is lying on a heated electric blanket.

It’s a joke, but it points to something true: context matters.

Fear thrives in abstraction.

Once numbers, comparisons and real measurements appear, it becomes clear that the “mystery box behind the fence” is one of the safest industrial installations in modern infrastructure.

3.7. The takeaway

Electromagnetic fields around transformers are not a health threat; they are a measurable, regulated and deeply understood part of the electrical ecosystem.

Instead of asking “Is it dangerous?”, the more useful question is “Is it designed and maintained correctly?”

And that’s where standards, responsible operators and transparent documentation — the operation and maintenance documentation (O&M manual) — come into play.

Next we’ll move from theory to practice: how to plan a home or housing development near existing power infrastructure, what tools to use, and how to turn awareness into peace of mind.

On this topic, you may also be interested in our article:
A strange experience under transmission towers: Childhood mystery explained

4. Planning a residential investment near power infrastructure. Tools, insights and case examples

Building a home or housing complex near a transformer station isn’t an automatic red flag — it’s a matter of awareness, due diligence and good dialogue with the grid. In fact, some of the best-designed neighborhoods in Europe coexist peacefully with substations a stone’s throw away.

The trick lies in planning, not panic.

4.1. The first rule of site selection: know your network

Before buying a plot, you check soil, zoning and access to water.

The same logic applies to electricity. The invisible network beneath your feet is the nervous system of modern life, and it pays to know where its nodes are.

Fortunately, you no longer need to wander with a hard hat and a voltmeter to find them.

Most countries provide open-data GIS maps showing the locations of primary substations, medium-voltage lines, and distribution transformers.

In Poland, for instance, these appear in land reports like the Environment Report. Elsewhere in Europe, similar services are offered by local planning portals or directly by the Distribution System Operator (DSO).

With a few clicks, you can learn:

• The distance from your plot to the nearest substation or overhead line,

• The voltage level of the nearby network,

• Whether your plot already has access to low-voltage distribution,

• And if additional permits or easements will be needed for connection.

This is where data replaces guesswork — and where many costly mistakes can be avoided.

4.2. Distance as a design parameter, not a fear metric

The question “How far from the transformer should I build?”

should really be “What should I build considering the transformer?”

If you treat the substation as part of your design environment rather than an obstacle, you can shape layout, landscaping and architecture to reduce both visual and acoustic impact.

Examples from European developments include:

• Acoustic shielding: earth berms, decorative walls, or green noise barriers.

• Smart orientation: placing garages or service zones on the side facing the substation.

• Distance optimization: even 10–15 meters of space, with proper fencing, can make a psychological and acoustic difference.

• Shared infrastructure: in some industrial estates, the substation sits on common ground, feeding multiple users efficiently.

In other words, distance is not a wall but a variable — one of many in a balanced design equation.

4.3. Ask for the right documents

A professional investor never relies on assumptions. Before you commit to a site or finalize a plan, request from the DSO or the property owner:

• Operation and maintenance documentation (O&M manual) – outlines maintenance schedules, safety zones and equipment specifications.

• Acoustic and EMF measurement reports – real data, not speculation.

• Fire and zoning permits – show whether the installation meets building code.

• Connection capacity confirmation – to ensure that the nearby substation can actually feed your development.

Good documentation is like good wiring:

it keeps everything connected and avoids unnecessary sparks.

4.4. Dialogue with the operator

The DSO is not your adversary. Their mission is reliability, not mystery.

Most operators welcome early contact with investors because it allows them to coordinate expansions and upgrades.

A short conversation can answer big questions:

• Is there planned modernization of the nearby substation?

• Could the transformer be replaced with a quieter or dry-type unit?

• Would a joint access road or fenced corridor make sense?

Sometimes, small adjustments — changing the orientation of doors, adding greenery, or shifting a fence line — can make the difference between unease and harmony.

4.5. When architecture meets energy

One of the most inspiring trends in Europe is architectural integration of substations.

Cities like Copenhagen, Berlin and Vienna have turned these technical facilities into design statements:

green façades, murals, even public seating areas on top of transformer roofs.

These projects demonstrate that infrastructure doesn’t have to hide — it can coexist and even add character to the neighborhood.

Modern substations are quieter, cleaner and more compact than ever before.

With Ecodesign Tier 2-compliant transformers and low-noise ventilation systems, their presence can be almost imperceptible.

4.6. A practical mini check-list for homeowners

If you already live near a substation, or plan to, here’s a simple sanity checklist:

1. Check the official map – locate the substation and note its type (low, medium, or high voltage).

2. Inspect visually – modern units are enclosed, grounded, and properly fenced; rust and open doors are a red flag.

3. Request measurements – ask for EMF or noise readings if you are unsure.

4. Landscaping – trees and shrubs absorb noise and visually soften the site.

5. Communication – know who your local DSO representative is; they’re your first call if something changes.

6. Perspective – remember: proximity often means stronger, more stable power supply.

4.7. A tale of two plots

To illustrate the point, imagine two investors:

Plot A: The buyer rejects a site because a small substation sits 30 meters away.

Plot B: Another buyer checks the same data, finds that the EMF is negligible and connection capacity is excellent, and negotiates lower land cost thanks to the “perceived risk.”

A year later, Plot B has reliable power, fast EV charging and a thriving solar installation.

Plot A is still waiting for grid approval.

Knowledge, as ever, is the best insulation.

A primary substation located near residential buildings, demonstrating how modern electrical infrastructure safely integrates into urban areas. Equipped with noise insulation, fire protection and electromagnetic shielding, these substations ensure reliable energy distribution while maintaining neighborhood comfort and environmental balance.
Photo © Maxim Tolchinskiy via Unsplash

Next, we’ll explore the social dimension — how to talk to investors, neighbors or communities who fear “the transformer behind the fence,” and how education and empathy can turn suspicion into trust.

5. How to talk to an investor or a neighbor who fears the transformer next door. Education, empathy and the art of explanation

No one ever fell in love with a transformer at first sight.

It hums, it has warning signs, and it sits behind a fence with serious-looking equipment.

The fear is understandable — humans are instinctively cautious about things they don’t understand.

But here’s the beautiful paradox: once you explain how a transformer really works, most people move from fear to fascination. Education is the best form of grounding — for minds as much as for circuits.

5.1. Fear has a frequency too

In psychology, fear of the unknown operates a lot like a standing wave.

Without information, it amplifies itself — until resonance occurs. The antidote is to introduce a new frequency: facts.

When a neighbor says, “That transformer gives me headaches,” it’s rarely about voltage.

It’s about uncertainty.

They don’t see the difference between a power transformer and a mobile phone mast, or between electromagnetic fields and radiation.

So start where people are, not where you wish they were.

Translate technical reality into human terms:

• Voltage isn’t radiation. It’s like water pressure — it pushes current through the system but doesn’t leak through the air.

• Magnetic fields aren’t poison. They’re just invisible loops that fade with distance, no different from the field around a fridge magnet.

• The hum means it’s working properly. Silence would actually be a bad sign — like a heart that suddenly stops beating.

When you speak in metaphors instead of megavolts, anxiety often melts faster than ice on a hot transformer tank.

5.2. The empathy protocol

Empathy doesn’t mean agreeing with misinformation.

It means listening first, then recalibrating perception.

Here’s a simple protocol used by experienced engineers and energy consultants:

1. Acknowledge the concern. “I understand why that sound worries you.”

2. Share verified data. “Here’s what the actual EMF measurements show — less than your hair dryer.”

3. Offer transparency. “Would you like to see the maintenance report? It’s public.”

4. Show the benefits. “Because the substation is nearby, you’re less likely to lose power during storms.”

5. Stay calm. Energy flows where attention goes — panic feeds panic, but confidence stabilizes.

This method works far better than dismissive “don’t worry about it” responses.

It’s the difference between flipping a switch and connecting a circuit.

5.3. Why engineers make great storytellers

Most engineers don’t think of themselves as communicators.

Yet every time they explain why a system works, they’re telling a story — a story about reliability, invisible effort, and the quiet brilliance of design.

Transformers, for example, are unsung heroes of civilization.

They allow Europe’s grid to operate with breathtaking efficiency — 99.5 percent of generated electricity reaches consumers.

Without them, no EV charging, no refrigeration, no Wi-Fi, no MRI scans.

A well-told story reminds people that the hum behind the fence is not a threat, but a sign that the lights of the city will stay on.

When engineers speak with warmth instead of jargon, they become ambassadors of trust — and that trust is the most renewable energy source of all.

5.4. Case study: the fence that disappeared

In a small German town, residents once protested a new 20 kV substation planned beside their community garden.

The complaints were classic: noise, radiation, property value.

The engineers didn’t dismiss them.

They invited the community to a site visit, explained the function of each component, showed live measurements of magnetic fields, and promised landscaping with native trees.

Six months later, the same residents asked for the fence to be lowered so the wildflowers around the station could grow freely.

Education had transformed fear into stewardship.

5.5. Turning “Not in my backyard” into “Our backyard”

Modern urban planning moves away from hiding infrastructure. Instead, it integrates it.
Transparent design, community engagement and visual harmony make technical sites part of civic life.

When people understand how something works, they stop fighting it — and sometimes even start protecting it.

It’s no longer a transformer “behind my house”; it’s our local power hub.

Empowerment — in the literal sense — begins with knowledge shared openly.

Next, we’ll close this exploration by returning to the big picture:

what balance looks like between human comfort and the needs of an evolving power grid, and how the future of living with energy infrastructure might be quieter, greener and smarter than we ever imagined.

6. The balance between the need for energy and the comfort of living

Every civilization faces the same question: how do we power our lives without overpowering our surroundings?

The answer isn’t to hide transformers further away, but to design systems - and relationships - that work in harmony.

In the twenty-first century, electricity is not just a utility; it’s a cultural infrastructure.

It shapes how we live, build, travel and even think.

And the quiet substation at the edge of the neighborhood is where all those currents - literal and metaphorical - converge.

6.1. Living with infrastructure, not against it

The world used to treat technical facilities as something to be concealed: out of sight, out of mind.

But as grids modernize, cities are learning a new kind of coexistence.

In Paris, medium-voltage substations hide beneath community gardens.

In Amsterdam, transformer housings double as urban art.

In Stockholm, energy storage units share rooftops with solar panels and playgrounds.

These examples reflect a shift in mindset — from isolation to integration.

We no longer need to see the grid as an intruder; it can become part of the living fabric of our environment.

Well-designed energy systems make neighborhoods more resilient, not less beautiful.

The hum of a transformer is a whisper of stability, not a threat.

6.2. When comfort meets conscience

We often speak of “comfort of living” as silence, space and safety. But there’s another dimension — comfort of conscience.

Knowing that your electricity flows efficiently, that your local substation prevents energy loss, and that your lights stay on thanks to renewable integration — that’s a comfort too.

A nearby primary substation doesn’t just serve your house; it connects you to a collective ecosystem that keeps hospitals, schools and charging stations alive.

The very convenience of modern life — from charging your car to heating your home — depends on these hidden, reliable allies. The challenge is not their presence, but our perception.

6.3. Future-proof energy, future-proof neighborhoods

Europe’s energy landscape is changing faster than ever.

Photovoltaic farms, wind parks, EV chargers and battery storage systems all rely on one thing: modern, flexible transformers that can handle bi-directional flows and variable loads.

Tomorrow’s substations will be quieter, smarter and more connected.

They’ll communicate with the grid in real time, automatically balancing energy between homes, batteries and solar rooftops.

Some will even become architectural landmarks — designed to educate the public about the invisible systems that sustain our lives.

This isn’t utopia; it’s already happening.

New transformers that meet Ecodesign Tier 2 standards can cut energy losses by up to 30 percent.

Modular stations reduce land use, and hybrid designs combine storage and control within a single compact unit.

The evolution of infrastructure mirrors our own evolution as societies — towards efficiency, transparency and shared responsibility.

6.4. From fear to gratitude

In the end, the story of the transformer next door is a story of perspective.

It begins with uneas: “Why is this thing here?”

and ends with appreciation: “Thank goodness it is.”

Every hum carries the echo of human effort: engineers who calculated clearances, electricians who tested grounding, designers who shaped enclosures, operators who keep the lights on through storms.

Behind the fence stands not a threat, but a promise, a commitment to safety, reliability and progress.

6.5. The closing current

Technology, when built with care, doesn’t oppose human comfort; it enables it.

A well-placed, well-designed substation doesn’t diminish the value of a home; it protects it — from blackouts, from inefficiency, from the fragility of dependence.

So when you see that silent structure humming in the distance, remember: it is not a stranger.

It’s part of the same system that powers your mornings, your work, your dreams.

And perhaps the real transformation we need isn’t electrical, but perceptual — learning to see energy not as noise, but as connection.

Relationships Energy

Logic, precision and the poetry of engineering — that’s what keeps the world alight. Each transformer is a translator between scales, a bridge between physics and daily life.

Energy is not just a current in wires; it’s a current of trust, collaboration and gratitude.

At Energeks, we specialize in medium-voltage transformers, Tier 2 oil-transformers as well as Tier 2 cast resin transformers, primary substations, switchgear and energy storage systems, all designed to meet the latest European standards and the realities of modern networks.

Our goal is simple: create systems that truly work — for people, for cities, for the planet.

If you’re planning an investment, designing infrastructure or simply want to understand the grid better, explore our portfolio of medium-voltage transformers, check also units available immediately or connect with us on LinkedIn Energeks.

There we share insights, case experiences and a look into the future of energy — built not on fear, but on partnership.

Because technology is only as strong as the people who understand it.
And understanding, after all, is the purest form of energy.

Sources:

https://electrical-engineering-portal.com

https://ieeexplore.ieee.org

https://www.sciencedirect.com/topics/engineering/transformer

At one of the photovoltaic farms an investor asked with a slight smile:

“Why does this transformer say 15.75/0.42 kV when our grid is 15 kV? Is that a design error?”

This question comes up surprisingly often. And while it sounds simple, it goes straight to the heart of what designers and contractors in the medium-voltage world grapple with every day: the transformer voltage ratio.

Because the ratio is not just about “what goes in and what comes out.”

It is a mathematical promise that voltage and current will behave exactly as required by the grid, the inverter, and the Distribution System Operator.

In this article, we will explain what a transformer voltage ratio is, where common ratios come from, how to interpret them, and what they really mean for the efficiency and safety of your installation.

You will also learn why those “odd numbers” on the transformer nameplate are sometimes exactly what saves your investment from overvoltage issues and grid non-compliance.

Estimated reading time: approx. 8 minutes.

What is a transformer voltage ratio and how does it work in a real grid?

The voltage ratio of a transformer is one of those terms that sounds harmless—almost like the proportion of ingredients in a pancake recipe. And yet, in practice, it is a key parameter that determines whether the transformer will function properly or simply become an expensive piece of decoration in the substation.

By definition: what exactly is it?

The transformer voltage ratio defines the relationship between the voltage on the primary (input) side and the voltage on the secondary (output) side.

If we have a voltage ratio of 15,000 V / 400 V, it means the transformer steps the voltage down from 15 kV to a safe level of 400 V—suitable for end-use devices such as inverters, servers, machines, pumps, or even a humble electric kettle in a production hall.

According to the law of conservation of power (neglecting losses), the transformer must "balance" voltage and current. If voltage goes down, current goes up—and vice versa.

How does it work in a real grid—not just in the textbooks?

In theory, it’s simple: the grid supplies 15 kV, the transformer steps it down to 0.4 kV, and that’s it. But in reality, things look a bit different. The grid doesn’t hold the voltage steady.

On a hot day, with a million air conditioners running, voltage drops. At night, when barely anything is drawing power, voltage rises. Add solar panels pushing excess energy back into the grid on sunny days, and… you get a rollercoaster.

This is why transformer designers have to account for these fluctuations.

A 15/0.4 kV ratio might work in theory—but what if the grid voltage rises to 15.4 kV? On the low-voltage side, that becomes 411 V instead of 400 V—and that could exceed the tolerance of the inverters.

This is where the magic of engineering comes in: tap changers.

The transformer is equipped with the ability to adjust its voltage ratio by ±2×2.5%—meaning it can raise or lower the input voltage without physically changing the windings.

It works like a thermostat: the transformer adapts to real operating conditions.

A good voltage ratio is one that:

• fits the actual voltage at the point of connection (not just on paper),

• provides the proper voltage for inverters and loads,

• includes a margin for regulation,

• allows appropriate selection of protection and switching devices without oversizing.

And that is exactly why transformer nameplates often show values like 15.75/0.42 kV instead of the “neat” 15/0.4 kV.

Because the world isn’t uniform, and the transformer needs to understand that.

Where do typical voltage ratios come from — a story of compromise, grid maps, and engineering flexibility

Imagine an electrical map of Europe, but not with mountains and rivers, but with voltage levels:

10 kV, 15 kV, 20 kV, 30 kV, 13.2 kV…

Each country has built its own system, its own habits, and its own standards—often due to historical, technological, and logistical reasons.

On this map, the transformer is like a multilingual translator who must speak the dialect of a given country, not just in words (voltage), but in tone (current, regulation, tolerances).

Typical voltage ratios—such as 10 kV / 0.69 kV, 15.75 kV / 0.42 kV, 20 kV / 0.4 kV are the result of three forces that every transformer manufacturer must balance:

• Local medium voltage (MV) grid levels.
  In Poland, the most common voltages are 15 kV and 20 kV.
  In Germany, you will find 10 kV, 15 kV, and 30 kV.
  In Spain, 13.2 kV and 21 kV are often used.
  The transformer must “fit into” this local grid reality, which is why part of the voltage ratio comes directly from the region’s MV level.

• Output voltage—what the equipment needs.
  These are typically around 0.4 kV, 0.42 kV, or 0.69 kV—depending on the installation design, device requirements, and local low-voltage standards.
  The output voltage must match what PV inverters or energy storage systems need to operate efficiently.

• Voltage buffer, tap changer range, and network tolerances.
  The grid rarely delivers exactly 15,000 V—it’s often 15,200 V, 15,400 V, or even 14,900 V.
  The transformer must include a margin for tap changer adjustments (± a few percent).
  That’s why you’ll often see numbers like 15.75 kV—slightly above nominal—to allow room for adjustment without losing synchronization with the inverter.

Those fractions (like 0.75 kV) are not a mistakes, they are a result of engineering precision.

Examples of typical voltage ratios and when to use them

In the world of medium-voltage transformers, there are certain classics—ratios that show up on construction sites as reliably as coffee at 6 a.m. in a design office. Each one has its own logic and technical rationale, shaped by decades of practice, grid conditions, and real-world experience.

Let’s break them down—not just by the numbers, but by their personalities.

The first evergreen: 10 kV / 0.69 kV

This one is a favorite in environments where high power meets smart electronics—think large-scale energy storage systems or EV charging stations.

Why? Because many industrial inverters operate at a nominal voltage of 690 V AC, which aligns perfectly with this ratio.

What makes this setup so effective is its low voltage ratio, which keeps secondary current at manageable levels without overloading the windings. Less stress on copper means better performance and a longer lifespan.

In simple terms: if your project includes power electronics with big appetites, this ratio offers pure stability on a silver platter.

The engineers’ favorite: 15.75 kV / 0.42 kV

Call this one the sweet spot for solar farms in Poland and Germany.

It’s a smart compromise between:

• MV grids typically running at 15 kV, and

• inverters working best around 400–420 V.

The extra 0.75 kV on the primary side gives headroom for voltage regulation, especially when tap changers come into play. This makes it easier to hit that Goldilocks zone on the LV side—not too high, not too low, just right.

It’s like finding perfect tire pressure for your electric car: quiet, efficient, and ready for any terrain.

This ratio is often chosen when engineers need grid synchronisation and inverter compatibility without the drama of last-minute design changes.

The all-time classic: 20 kV / 0.4 kV

This duo has been powering European infrastructure for decades.

You’ll find it across public distribution systems, municipal buildings, industrial parks—anywhere where compatibility, reliability, and simplicity are king.

It’s a straightforward setup:
20 kV primary, straight into the grid, and 0.4 kV secondary, ready for standard low-voltage panels.

There’s nothing fancy about it—but that’s exactly the point. It’s the transformer equivalent of a solid handshake: dependable, familiar, and trusted by generations of engineers.

Each of these voltage ratios is like a language dialect—speaking the same physics, just with a different accent.

• One speaks fluent inverter.

• Another chats easily with distribution grids.

• The third bridges both worlds with confident ease.

And that’s why the world of transformers is never boring. Behind those neat numbers on the rating plate lies a dance of engineering pragmatism, grid diplomacy, and yes—just a touch of poetry.

How transformer voltage ratio works – in a nutshell

Put simply, a transformer’s voltage ratio defines the relationship between the primary (input) voltage and the secondary (output) voltage.

If a transformer is rated at 15,000 V / 400 V, it means that for every 15,000 volts on the medium-voltage side, there will be 400 volts available on the low-voltage side.

From a user’s perspective, this means the transformer:

• steps down the voltage from the MV grid to a safe level for downstream equipment, and

• increases the current on the LV side inversely proportional to the voltage ratio.

In other words:
The higher the voltage ratio, the higher the current on the low-voltage side—and vice versa.

This is why we calculate transformer power using the formula:

S = U₁ × I₁ = U₂ × I₂

Where:

S – apparent power (in kVA)
U – voltage (in V)
I – current (in A)

Let’s look at a real-world example:

A transformer rated at 1000 kVA, with a 15/0.4 kV voltage ratio:

• Primary current (MV side):
  I₁ = S / (√3 × U₁) ≈ 1000 / (1.732 × 15,000) ≈ 38.5 A

• Secondary current (LV side):
  I₂ = S / (√3 × U₂) ≈ 1000 / (1.732 × 400) ≈ 1443 A

As you can see, the same transformer delivers dramatically different currents depending on the voltage.

That’s why selecting a voltage ratio without understanding the load characteristics, protection devices, and grid conditions is a fast track to problems—like tripping breakers, overheated windings, or inverter synchronization failures.

In transformer design, math is not optional—it’s your first line of defense.Phase configurations and their impact on voltage ratio

Sometimes, the winding connection scheme (such as Y-Δ, Δ-Y, Δ-Δ, Y-Y, etc.) affects the effective voltage ratio in a way that differs slightly from the nominal nameplate values.

For example, in Dyn11 configurations (a star-delta transformer with a 30° phase shift), the actual voltage ratio may require correction compared to what’s printed on the rating plate—especially when you're considering line-to-line versus phase voltages.

And if the configuration includes a neutral point (like Dyn11 with "n"), things get even more interesting. The presence of the neutral introduces new considerations for grounding, fault behavior, and voltage balancing. It’s one of those "small details" that turns out to be not so small when your system doesn't behave as expected.

Taps and voltage regulation

Most modern transformers offer tap changers on the primary winding, typically allowing ±2 × 2.5% adjustment range. This enables tuning of the input voltage to match real-world conditions.

So, when you see a transformer rated at 15.75 kV, don’t assume that’s a rigid number. It’s actually the center point of an adjustable range, giving engineers room to fine-tune voltage levels to ensure compatibility with both the grid and downstream inverters.

Think of it like a tone control knob on an amplifier—just enough to correct the pitch without needing to redesign the whole orchestra.

Losses, efficiency and standards

Every transformer design aims to minimize losses—both no-load (core) and load (copper) losses.

European regulations like Ecodesign 548/2014 require new transformers within specified power ranges to meet strict efficiency standards (e.g. Energy Efficiency Level 2 – EEF2).

And here's where the voltage ratio plays a surprisingly indirect role:

• A poorly chosen ratio can lead to higher conductor losses,

• reduced efficiency in voltage regulation,

• and increased heat generation within the windings.

It’s a domino effect. One decimal point off in your voltage ratio, and suddenly your whole installation is dealing with hotter cables, louder hum, and unhappy electronics.

Bottom line?
The voltage ratio is more than a number on a plate—it’s a fine-tuned parameter that balances thermal performance, energy costs, and compliance with regulations.

Why voltage ratio is key to synchronizing with the DSO grid

Distribution System Operators (DSOs) have very precise requirements when it comes to nominal voltage levels at connection points. That’s why a transformer’s voltage ratio must reflect the actual voltage present in the local grid, which often isn’t exactly 15,000 V but rather values like 15,750 V or 15,400 V.

This is crucial to ensure:

• Stable operation of PV inverters, which require a supply voltage strictly within the 400–420 V AC range,

• Maintaining medium voltage (MV) levels within the ±5% tolerance,

• Compliance with standard PN-EN 50160 on voltage quality parameters.

This is precisely why designers often select a 15.75/0.42 kV voltage ratio. It offers enough headroom for safe tap changer regulation (±2 × 2.5%), without risking loss of synchronization or breaching inverter specifications.

Differences between grids in Poland, Germany and Spain

Europe is a mosaic of medium voltage levels.

In Poland and the Czech Republic, the most common voltages are 15 kV and 20 kV.

In Germany, you often find 10 kV, 15 kV, and 30 kV networks.

In Spain, the typical values are 13.2 kV, 15 kV, and 21 kV.

As a result, a substation designer must not only know the nominal parameters of the grid, but also understand the “philosophy” and legacy of local distribution system operators.

For example:

• In Germany, there are still 10/0.4 kV networks in operation, where transformers with a 10.5/0.4 kV ratio are commonly used. This allows for proper tap regulation and coordination with old and new infrastructure.

• In Spain, 21/0.42 kV transformers are often used because the nominal voltage of 21 kV stems from historical 3×12 kV networks that were later modernized to a 21 kV standard. It’s a legacy system with modern adaptation.

• In Poland, the 15/0.4 kV ratio remains the standard in most cases. However, for industrial energy storage systems and high-power inverters, the 20/0.69 kV configuration is gaining popularity due to improved current distribution and lower cable losses.

These variations help explain why the same transformer might be labeled differently depending on the country of delivery.od kraju dostawy.

We design our units in standard voltage ratios like 10/0.4 kV, 15.75/0.42 kV, and 20/0.69 kV, with voltage regulation options of ±3×2.5% or ±2×2.5%, to meet the technical requirements of DSOs in Poland, Germany, and Spain.
Ask us about a configuration tailored to your project.

Once upon a time: the voltage ratio that saved the project

During the commissioning of a PV farm in Lower Silesia (Poland), the team discovered that the actual voltage at the point of connection was 15.6 kV, not the expected 15 kV.

If the transformer had a 15/0.4 kV ratio, the low-voltage side would have supplied 416–418 V to the inverters – exceeding their acceptable input range.

As a result, the system would have shut down every time the grid slightly boosted the voltage.

The use of a transformer with a 15.75/0.42 kV voltage ratio completely solved the issue. That seemingly small 0.75 kV margin on the MV winding turned out to be critical for stable operation and DSO compliance.

For the investor, this made the difference between a running PV farm and one that was non-operational.

Voltage ratio and protection equipment selection

The voltage ratio also determines the rated currents, which affects the selection of cables, current transformers (CTs), circuit breakers, and protection relays.

In real-world practice, an incorrect voltage ratio assumption can flip the entire logic of the project:

• Too small a ratio = too high current on the LV side = cable overheating, higher I²R losses, and accelerated aging of insulation.

• Too large a ratio = too low LV voltage = inverter undervoltage errors, disconnections, or decreased energy yield.

That’s why standards such as PN-EN 60076-1 and EN 50588-1 recommend that designers always consider the actual voltage at the point of connection, including ±5% tolerance, and the load characteristics (resistive, inductive, capacitive).

In PV and EV systems, an additional factor comes into play: dynamic voltage ratio performance. This refers to the transformer’s ability to compensate for fast changes in voltage, caused by inverter activity or rapid load variations from DC chargers.

It is no longer just about steady-state values – modern transformers must adapt to dynamic grid behavior in real time.

How to select a transformer voltage ratio – a practical example

Let’s assume you are designing a 2 MW substation for a PV farm connected to a 15 kV network, using inverters operating at 420 V AC.

You are choosing between two transformer voltage ratios: 15/0.4 kV or 15.75/0.42 kV.

For an apparent power of 2000 kVA:

15/0.4 kV configuration:

• I₁ = S / (√3 × 15 000) = 77 A

• I₂ = S / (√3 × 400) = 2887 A

15.75/0.42 kV configuration:

• I₁ = S / (√3 × 15 750) = 73 A

• I₂ = S / (√3 × 420) = 2747 A

The differences may seem small, but in practice they result in lower LV current, reduced power losses, and lower operating temperatures for the windings.

Over time, this translates into improved system performance and extended equipment lifespan.

Smart and adaptive transformers

A transformer is no longer a passive component in the power network – it has become an active player in maintaining system balance.

Integrated voltage regulators continuously analyze real-time values on both MV and LV sides and adjust the voltage ratio within a ±5% range.

This allows the substation to maintain optimal output voltage, even when loads fluctuate due to inverter operation or DC charging cycles.

This functionality is crucial in next-generation projects, where energy flows both to and from the grid.

In PV farms, battery storage systems, or e-mobility hubs, where the direction of power flow shifts constantly, a transformer with an adaptive voltage ratio becomes the system’s stabilizing core.

Moreover, an increasing number of distribution system operators (DSOs) across Europe are incorporating such features into their grid connection requirements.

It makes perfect sense. As networks become more distributed and less predictable, they require equipment that can think and react.

From an investor’s standpoint, this is not just about performance – it is about pure economics:

• Lower energy losses

• Reduced O&M costs

• Longer inverter lifespan

• No need for manual corrections – the substation begins to learn its own load profile.

In a world heading toward smart grids, the voltage ratio becomes a strategic parameter, not just an electrical one.

It defines your system’s energy efficiency, grid compliance, and resilience.

You could say that the transformer of the future is made not only of steel and copper, but also of logic and algorithms.

The future

Just a decade ago, voltage ratios were considered set in stone.

Once selected, a transformer would operate for 30 years unchanged, regardless of network variations or load shifts.

Today, that is no longer the case.

Modern designs – such as Energeks MarkoEco2 – offer automatic voltage regulation based on real-time load conditions.

This means the voltage ratio is no longer fixed – it can adapt within a ±5% range, keeping the LV side voltage stable even when the MV grid fluctuates.

Such solutions are now often required by DSOs in large-scale PV plants, energy storage systems, and EV charging stations.

As a result, the voltage ratio is evolving from an electrical specification into a strategic asset for ensuring system efficiency and long-term reliability.

If you are planning to invest in a transformer that understands the new logic of the grid, take a look at our offer:

→ Medium voltage transformers – full Energeks portfolio

You are also welcome to join our Energeks LinkedIn community, where we share knowledge, real-world experiences, and insights into the future of energy – always with gratitude for every partnership.

Because while technology builds the hardware, it is people and relationships that create a system that truly works.

Źródła:

European Commission – Regulation (EU) 2019/1783 supplementing Regulation (EU) 548/2014: Ecodesign requirements for power transformers

Forbot: Transformator – budowa, zasada działania i zastosowanie

A transformer without the right winding connection works a bit like a football team without formation. Everyone runs, but instead of a match you get chaos.

You can have the best players (meaning top quality copper and steel), but if you place them in the wrong setup, instead of victory you end up with exhaustion and frustration.

It is the connection choice that decides whether voltage will distribute evenly, whether the installation can handle unbalanced loads, how the grid will cope with persistent harmonics, and whether the neutral point will stay stable or float around like a cork on water.

In practice, this is the difference between an installation that ticks like a Swiss watch and one that buzzes and irritates like a bargain alarm clock.

And the consequences? Very real. A poorly selected connection can cause the distribution system operator to reject your grid connection, protections to trip at the slightest disturbance, and energy losses to quietly drain your budget.

No wonder questions about the difference between star and delta, or why delta-star transformers are so common, come up in designers’ conversations as often as coffee on a construction site.

This article is for EPC contractors, industrial engineers, grid designers, renewable energy developers, and anyone who has ever wondered:

“Which transformer connection is used at 100 kVA?”

If you are looking for answers about the difference between star and delta in transformers, the purpose of a delta-star transformer, or what codes like Dyn11 or Yzn5 really mean, you will find clear and practical explanations here.

Article agenda:

• How to read nameplate symbols: Y, D, Z, n and clock numbers

• Examples and practice: Dyn11 vs Dyn5 — compatibility, parallel operation, European realities

• Yzn for 25–250 kVA: why “small giants” prefer zigzag on LV

• Zigzag as a hidden pillar of the grid: creating neutral, damping triplen harmonics, operational data

• 100 kVA in rural and urban settings: connection choices and numbers that truly matter

• Myths and half-truths: grounding delta, pitfalls of Yy, Dyn11 ≠ the only EU standard

• 2025/2026 — RES and EV: inverters, charging hubs, and the hybrid transformer trend

• What we can do for you: offer, Tier 2 Ecodesign standard, contact and community

Reading time: ~14 minutes

How to read symbols on a nameplate

The first encounter with a transformer nameplate feels like stepping into a foreign world: a few letters, a few numbers, all looking like a cryptographer’s code.

You see “Dyn11”, “Yzn5” or “Dyn5” and wonder: is it a safe combination, or maybe a spare part catalogue number?

In fact, behind these three characters lies the entire story of how the transformer will cooperate with your network.

Every letter plays a role in the theatre of energy.

“Y” – star — means that the windings are connected in a common neutral point. Thanks to this, each winding “sees” only the phase voltage, which reduces insulation requirements and costs.

“D” – delta — works the other way: it is a closed loop whose greatest strength is resistance to unbalanced loads and the ability to “negotiate” between phases.

“Z” – zigzag — sounds exotic, but it is the master of cleaning up harmonics and stabilising the neutral, especially in times when electronics can throw quite a mess into the grid.

Small “n” — indicates that the neutral point is not locked inside the tank but brought outside, ready for connection.

And finally, the most interesting part of the puzzle:

The clock number, such as 0, 5 or 11. These are not meeting times but phase shifts, each of 30°.

Example Dyn11

This is not a random code but a precise instruction manual for how the transformer will behave in your network:

D – the winding on the high voltage (HV) side is connected in delta. This gives the medium voltage grid stability and protection against third-order harmonics.

y – the winding on the low voltage (LV) side is connected in star, which makes it possible to bring out the neutral* and supply both single-phase and three-phase loads.

n – the neutral* is actually available outside. It is not left locked in the tank but waits for the N or PEN conductor.

11 – the clock number. It means that the low voltage winding lags 30° behind the high voltage winding. This arrangement is considered the standard in Europe because it simplifies synchronization and allows multiple units to be paralleled without issues.

Dyn11 is a classic distribution transformer: delta on the medium voltage side (for stability and harmonic mitigation), star on the low voltage side (for an accessible neutral), and a phase shift that ensures compliance with grid requirements.

That is why a vast number of MV/LV transformers in Europe, especially in the 250 kVA and above range, carry this designation today.

*But what exactly does “neutral” mean?

When we say “it allows the neutral to be brought out,” we are talking about the neutral point of the transformer, which is the physical place where the ends of the windings meet in a star (Y) configuration.

In a star connection (Y), each of the three phase conductors (L1, L2, L3) has a winding. One end of each winding meets in a single common point – this is the neutral point.

This point can either be left “closed” inside the transformer (in which case no N conductor is available outside), or it can be brought out to a terminal on the transformer, giving us an accessible neutral (N) conductor for the low voltage network.

Why is this important?

Because the neutral (N conductor):

• allows single-phase loads to be supplied (for example, household 230 V installations),

• stabilises phase voltages with respect to earth,

• enables the creation of network systems such as TN-S, TN-C-S, or TT, according to DSO requirements.

In simpler words:

“Bringing out the neutral” = the transformer gives access to the common star point, which becomes the N conductor in the low voltage network.

Example Dyn5

This is also not a random string of letters and numbers but a precise piece of information about how the transformer will behave in your network.

We already know D, y and n well: delta on the medium voltage side provides resistance against load asymmetry and “locks in” third-order harmonics, star on the low voltage side makes it possible to bring out the neutral so that both single-phase and three-phase consumers can be supplied, and n means that this neutral is actually available outside, waiting for the N or PEN conductor.

The entire difference lies in the digit 5 – this is the clock number, the way the phases are shifted with respect to each other. In Dyn5 the low voltage winding is shifted by as much as 150° relative to the high voltage winding.

This is completely different from Dyn11, where the shift is only 30°.

In practice, this means that Dyn5 does not play in the same “orchestra” as Dyn11.

They cannot be paralleled, but in many countries of Central and Southern Europe this very 150° shift is the grid standard.

That is why Dyn5 is not an exotic choice or an exception to the rule, but a fully fledged distribution transformer used every day in hundreds of substations.

Delta, star and neutral plus phases shifted by 150° – this configuration has been proven in practice for decades, and operators and manufacturers know that in their grids it simply works best.

Dyn5 vs Dyn11 in European practice

In technical literature and European standards you will most often read that the distribution standard is Dyn11 – and indeed, you will encounter this arrangement in many Western European countries.

But if you look wider, you will see the full picture: in a vast part of Central and Southern Europe it is Dyn5 that serves as the ordering standard.

Why did this happen?

• Historical background: in the 1970s and 1980s many countries adopted Dyn5 as their base connection group. The transformer fleet in the grid was built for decades around this standard, so new units must remain compatible – otherwise parallel operation would be impossible.

• Reduction of short-circuit currents: the 150° phase shift in certain topologies allows short-circuit values to be reduced, which is crucial in dense industrial and urban networks.

• Local synchronization: Dyn5 fits the characteristics of certain national distribution grids where different criteria from those of Western Europe were adopted decades ago.

• Export and market demand: manufacturers in Europe know that customers in the south and center expect Dyn5 just as much as customers in Germany or France expect Dyn11.

It is not a matter of one being better or worse, but of compatibility with the local grid.

Dyn5 and Dyn11 – different rhythms, the same melody

Dyn11 – a 30° shift, the standard in Germany, France and the United Kingdom, allows easy parallel operation and is well documented in technical standards.

Dyn5 – a 150° shift, preferred in many Central and Southern European countries, equally common in practice, although less frequently described in textbooks.

The most important point: these two groups cannot be operated in parallel.

If the entire grid in a given region is based on Dyn5, the new transformer must also be Dyn5 – otherwise circulating currents and stability issues will appear.

The truth is that Europe is not one single standard but a mosaic.

In some countries Dyn11 dominates, in others Dyn5, and a competent transformer supplier must understand both groups and know when each is required.

Yzn connections – transformer for small giants

Yzn5 and Yzn11 connections are particularly popular in low and medium power transformers – from 25 kVA to 250 kVA, which means pole-mounted units and compact distribution substations.

These are solutions that distribution system operators often choose in rural and suburban areas. The core and copper work in the same way as in Dyn, but the way the windings are connected makes a huge difference to what happens at the far end of a long line in a village, on a farm, by a fire station or on the edge of an industrial park.

They combine insulation economy on the medium voltage side with high stability of the neutral on the low voltage side.

Main advantages of the Yzn connection

The star on the MV side limits insulation requirements, which, with hundreds of similar points in the network, has budgetary significance.

On the LV side the zigzag enters the stage, that is, a winding consisting of two halves on two columns, connected in such a way that the fundamental frequency components add up to the phase voltage, while the third harmonic components and other harmonics can cancel each other out.

The practical effect is very prosaic, yet invaluable.

The neutral point stops “floating”, and the phase voltages hold their level even when the load of each phase is different, and the electronics of consumers throw third and ninth harmonics into the network with the zeal of a night-time charger and LED lighting.

The star on the MV side (Y):

• insulation works only at phase-to-neutral voltage,

• reduction of insulation costs and simplification of construction,

• compatibility with typical 15–20 kV lines in Europe.

The zigzag on the LV side (Z):

• neutral point stable even with heavily unbalanced load,

• effective elimination of third harmonic currents (the so-called triplens),

• improved voltage quality for sensitive loads (LED, computers, inverters).

The neutral brought out (n):

• possibility of configuring TN-S, TN-C-S or TT systems,

• simple earthing solutions in accordance with local DSO requirements.

Clock number (5 or 11):

• Yzn5 – 150° phase shift, preferred in many Central European countries,

• Yzn11 – 30° phase shift, more commonly used in Western Europe.

Operational and practical data

Nonlinear loads are an everyday reality today. In a typical town some houses run on switch-mode power supplies, the workshop has a few inverters, and on a winter afternoon all the street and home lighting is LED.

In a star network without zigzag these “triplens” tend to add up in the neutral conductor, which sometimes causes flickering of lights and the characteristic complaint along the lines of the difference between star and delta connection is probably just a textbook theory.

In Yzn a significant part of these currents closes inside the zigzag windings, and at the phase terminals there is less nervousness and more order. For the engineer it means fewer surprises on the power quality recorder, for the user more stable operation of loads, and for the operator fewer phone calls in the evening.

Power range: most often 25–250 kVA (pole-mounted and small free-standing substations).

Typical voltages: 15/0.4 kV or 20/0.4 kV.

Unbalanced loads: Yzn keeps the phase voltages within limits even when the load difference reaches 30–40% between phases, which in pure star systems would be critical.

Harmonics: reduction of neutral current by as much as 50–70% in the case of dominant third harmonics from nonlinear loads.

Losses: the zigzag winding requires more material (more copper), which means higher load losses by 2–4% compared to the classic Dyn system, but this is an acceptable compromise for improved stability.

Let us assume that a 0.4 kV line is loaded mostly single-phase, and the third harmonic current in each phase accounts for about one-fifth of the fundamental current.

In a pure star system the neutral current can reach three times the third component from the phases, which in total gives a significant share in the cross-section and heating of the N conductor.

In Yzn part of this current closes within the winding system, which makes the effects of the same load chemistry less visible in the neutral conductor and at the load terminals. This is not a miracle, only the geometry of the connections, which acts like a passive filter embedded in copper.

Yzn5 versus Yzn11

This is not a duel for victory but a matter of compatibility with the environment.

The clock number tells how the low-voltage phases are aligned with respect to the medium voltage. In many regions the operator requires Yzn5, in others Yzn11, and sometimes leaves the choice provided that the new transformer can operate in parallel with its neighbor without problems.

It is worth remembering a simple rule. For parallel operation the “clock” and the type of connections must match. Connecting Yzn with Dyn to balance power on one busbar is asking for circulating currents and an expensive lesson in vector basics. So if the surrounding grid is built on Yzn5, the new unit should also be Yzn5.

The same logic applies to Yzn11. This is not the stubbornness of a bureaucrat, but mathematics.

Why Yzn in rural networks?

Operators in rural areas like Yzn. Here resilience to real life counts. Low-voltage lines are long, cross-sections are chosen economically, loads are uneven. In such a topology the stability of the neutral and the suppression of triplens are invaluable.

Yzn closes the loops for zero-sequence currents inside the transformer, thanks to which at the ends of the line the voltage reacts more calmly to the connection and disconnection of large single-phase loads.

This matters for everything, from starting a pump on a farm, through a rectifier in a workshop, to sensitive IT equipment at home.

• Long LV lines (0.4 kV) – voltage drops are critical, so a stable neutral reduces the risk of light flicker and equipment failures.

• Single-phase consumers – households, workshops, shops – introduce strong unbalances. The zigzag mitigates the effects of these differences.

• Nonlinear loads – LED, consumer electronics, IT, chargers – introduce triplens, which Yzn effectively neutralizes.

• Operation – small transformers (25 kVA, 63 kVA, 100 kVA) in Yzn networks can be easily replaced, maintaining compliance with the “clock” and the operating philosophy of the rest of the grid.

Small units: 25 kVA

A small pole-mounted unit supplying a few houses, a shop, or perhaps a small pumping station lives in the rhythm of daily peaks and evening LED waves. The zigzag keeps the neutral under control, so light bulbs do not “float”, inverters do not complain, and protections do not get a nervous hiccup. On top of that comes operational convenience. Replacing a small unit in a network built on Yzn is simple.

You insert the new transformer, connect it, and you have the guarantee that its vector will align with the vector of the rest of the stations within a radius of several kilometers.

A 25 kVA transformer in a Yzn configuration is a typical choice for:

• supplying several single-family houses,

• small shops, workshops, fire stations,

• dispersed consumers at the end of a line.

Why Yzn at this rating?

Because even with a few single-phase loads connected randomly to the phases, the voltages hold their level and the neutral does not “float”. It is the simplest way to have a network that works properly without excessive intervention.

The final aspect: grounding

Yzn provides a neutral ready for configuration according to the local operator’s policy, from TN systems to variants with a grounding resistor.

This is important where the selection of the earth-fault current has an impact on the choice of protections and the coordination with network automation. The zigzag does not relieve you from thinking about selectivity, but it does provide a very stable reference point, thanks to which the designer can stick to their calculations without surprises.

In summary, Yzn is a tool for everyday tasks, not a gadget.

It works best where the network is long and capricious, single-phase consumers dominate, and nonlinear loads are the daily bread. That is why a Yzn5 or Yzn11 transformer in the 100–250 kVA class, or even in the modest 25 kVA version, is considered a sensible choice in a vast number of pole-mounted substations.

At this power rating, what matters is practice, and practice speaks clearly:

• stable neutral,

• reduced impact of triplen harmonics,

• predictable behavior under load,

• compliance with operator expectations.

The rest are execution details that a good manufacturer and a good contractor will take care of.

Zigzag – the unassuming hero of grounding

When you look at a zigzag diagram, the first thought is often: “who had the patience to complicate it like this?”. Windings split in half, arranged in a zigzag across two columns, instead of a simple star or delta. And yet, this “strange” geometry turns out to be one of the most practical solutions in power distribution. The zigzag is a system that does not play first violin, but without it the orchestra of the network quickly begins to play out of tune.

Let’s start with the basics. The zigzag has one main task: to keep the neutral in check.

Regardless of whether the phases are equally loaded or one village hangs on L1 and another on L2, the neutral point remains stable.

And in places where electronics throw the third, ninth, or fifteenth harmonic into the network with the enthusiasm of a cheap charger, the zigzag simply “closes” these currents within itself.

Main functions of the zigzag

Creates a neutral in a network without one
In networks where the HV side is in delta (for example Dd0), there is no natural neutral point. The zigzag makes it possible to artificially create a neutral and ground it, which opens the way to TN-S or TT configurations on the LV side.

Suppresses third-order harmonics (triplens)
Triplens have the tendency not to disappear but to add up in the neutral conductor. Thanks to its construction, the zigzag creates “escape paths” for these currents, which close within the windings. The result is that the neutral does not overheat and phase voltages remain more stable.

Stabilizes the network under unbalanced loads
Farms, workshops, small industries – everywhere the load on one phase may differ greatly from another. The zigzag “holds” the neutral at the center instead of letting it drift away.

Protects against large harmonic content
In steelworks, facilities with welding machines, arc furnaces, or a large number of drives, harmonics can turn the network upside down. The zigzag works as a passive filter – not a miracle, but an effective reducer of the mess.

Practical data and examples

Power range: the zigzag is used from several kVA in auxiliary substations up to several hundred kVA in industrial grounding systems.

Applications:

• grounding transformer,

• part of the Yzn configuration in distribution transformers,

• load balancing systems in data centers and EV charging hubs.

Operational effects:

• reduction of neutral current by up to 50–80% in the presence of triplens,

• mitigation of light flicker in LED and IT loads,

• stabilization of phase voltages with load differences of up to 40%.

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Zigzag in everyday operation

Imagine a small 25 kVA station at the end of a 0.4 kV line. One phase supplies a workshop with a frequency inverter, another feeds several households, and the third powers LED street lighting for the entire street.

In a pure star connection, the neutral “floats” and lamps can flicker like a strobe light. The zigzag does something that is hard to notice – it stabilizes the voltages and keeps the neutral under control. As a result, the workshop runs without disturbances and the neighbor does not call the operator in the evening asking, “why is my light flickering?”.

The zigzag does not draw attention.

It does not increase the transformer’s power or improve efficiency in the catalog. Its effect becomes visible only in operation: fewer failures, fewer customer complaints, fewer service interventions. It is the kind of device that does not play first violin, but without it the orchestra would quickly fall out of tune.

This is not an exotic curiosity but a foundation of stability in networks with a large number of single-phase and nonlinear loads. In a Yzn connection it provides an advantage in rural areas, and in industrial applications it is often indispensable.

It is an element whose importance will continue to grow: the more electronics, inverters, and EV chargers, the greater the demand for the zigzag.

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Which connection for a 100 kVA transformer?

The question “what transformer connection is used for 100 kVA?” comes back like a boomerang on construction sites, in projects, and in conversations with operators.

Why? Because 100 kVA is a borderline power – the transformer is still relatively small, but already significant enough to supply dozens of consumers, influence the stability of the local grid, and comply with the requirements of the distribution system operator (DSO).

In practice, the choice of connection is not a matter of the designer’s taste, but a consequence of the connection conditions and the specifics of the network in which the transformer will operate.

Operational data for 100 kVA

In real-world operation, a 100 kVA transformer sits exactly at the boundary between small pole-mounted units and more serious distribution substations.

On the low-voltage side, this gives about 144 A of rated current at 0.4 kV, which is enough to supply several households as well as a small service facility. The real challenge, however, lies in the nature of the loads.

In rural networks, strong imbalance is very common – one phase may be loaded 30–40% more than the others. Under such conditions, a classic star connection causes the neutral point to drift and results in sharp deviations of the phase voltage. The Yzn connection stabilizes this point, ensuring that even with significant asymmetry, the voltages remain within the acceptable range.

Harmonics are equally important.

In a pure star system, the neutral current can reach 50–70% of the phase current if nonlinear loads generate strong third-order components. These are the very harmonics that heat the neutral conductor and cause disturbances in equipment operation.

In Yzn transformers, a significant portion of these currents closes inside the zigzag windings, which typically reduces them on the neutral conductor to 20–30% of the phase current. This can be clearly seen in power quality recorder measurements – the neutral curve becomes much more stable.

Of course, this stability comes at a price: more copper and a more complex winding design. Load losses in Yzn transformers are on average 2–4% higher than in Dyn units. However, in operational balance this is an acceptable cost.

Fewer failures, more stable voltages, and a lower risk of customer complaints make Yzn often the more economical choice, especially for 100 kVA units operating in rural and suburban networks.

Summary

• Typical power: 100 kVA = 144 A on the LV side (0.4 kV).

• Single-phase loads: in rural networks, phase imbalance often reaches 30–40% – Yzn keeps the neutral stable in such conditions.

• Neutral current: in a pure star it can reach 50–70% of the phase current with a high share of triplens. In Yzn it drops to 20–30%.

• Losses: Yzn has load losses 2–4% higher than Dyn, but gains in stability and reduced failure rate.

  ---

Rural areas – the kingdom of Yzn

In rural and dispersed areas, you will most often encounter Yzn5 or Yzn11.

Why?

• Long 0.4 kV lines: aluminum conductors sized “just enough,” stretching for several kilometers. Here every flicker of light or phase imbalance becomes immediately visible.

• Single-phase consumers: farms, workshops, small shops – phases are often loaded unevenly, and on top of that there are nonlinear loads.

• The zigzag does the work: it stabilizes the neutral, damps triplens, and reduces voltage flicker.

• Ease of operation: Yzn can be safely connected into a network where the same units have been operating for years, without the risk of problems in parallel operation.

Example: a 100 kVA pole-mounted substation supplying a dozen houses and a small car workshop. In a classic star connection the neutral current would “go wild,” but in Yzn the neutral stays stable and phase voltages remain within the norm even with a 30–40% load difference between phases.

City and industry – the domain of Dyn5/Dyn11

In cities and industrial facilities, a 100 kVA transformer is often an auxiliary unit or one serving smaller buildings. Here Dyn5 or Dyn11 dominates.

• Short LV circuit: lines are short, conductor cross-sections large, so load imbalances are less of a problem than in rural networks.

• Uniformity of the network: operators in urban and industrial systems prefer a single standard across the entire transformer fleet.

• Synchronization: Dyn11 is common in Western Europe (30°), Dyn5 in Central and Southern Europe (150°). The choice depends on the local “standard.”

• Harmonic protection: delta on the HV side traps third harmonic currents so they do not flow into the medium-voltage network.

Example: a 100 kVA indoor substation in an urban area. Consumers are three-phase, loads are more balanced, and the operator requires compliance with the existing fleet. If everything in that region is Dyn5, the new unit must also be Dyn5.

Yzn or Dyn? How to decide?

It comes down to compatibility and reliability.

The decision between Yzn and Dyn is about adapting to the environment in which the transformer will operate. For 100 kVA units, the choice of winding connection is always contextual, depending on location, load characteristics, and the standards set by the operator.

In rural areas, Yzn is most often chosen because it provides a stable neutral point and effectively damps harmonics generated by single-phase and nonlinear loads. In practice this translates into fewer problems with voltage flicker and lower risk of neutral conductor overload.

In cities and industry the situation is different – shorter lines, larger cross-sections, and more uniform loads mean that operators prefer Dyn. It is simpler in construction, cheaper in operation, and above all consistent with the standards used in many distribution systems.

Technical geopolitics

• Western Europe (Germany, France, UK): the standard is Dyn11 with a 30° shift, enabling easy synchronization and parallel operation.

• Central and Southern Europe (Poland, Czech Republic, Slovakia, Balkans): Dyn5 with a 150° shift has been historically entrenched and remains the backbone of transformer fleets.

• Rural areas across Europe: in the 25–250 kVA class, Yzn5 and Yzn11 dominate, because a stable neutral and harmonic reduction are more valuable than a few extra kilograms of copper.

The most important rule is that a transformer cannot be a foreign body in the network. It must fit into the logic adopted by the distribution system operator. Only then does it work as part of the bigger puzzle, rather than an element that disrupts the harmony of the whole.

Myths and half-truths about connections

The world of transformers has its own legends, beliefs passed down from generation to generation, which in practice often turn out to be half-truths or plain myths.

Debunking them is not only an intellectual satisfaction, but above all a real saving of time and money in projects.

First myth #1: “Delta cannot be grounded.”

Every young engineer has probably heard this sentence. Delta by itself indeed has no neutral, so it seems “useless for grounding.”

But once you add a zigzag grounding transformer, it suddenly turns out that delta can be a fully stable element of the system, with its neutral held firmly in place. In steel plants, facilities with arc furnaces, or large PV farms this solution is practically standard.

Delta by itself is excellent at damping third-order harmonics and balancing loads, and with the help of a zigzag it also gains a neutral. In other words: delta not only can be grounded, but in many applications it must be.

Second myth #2: “Every star–star transformer gives a good neutral.”

It sounds logical: if we have a common point, the neutral should be stable.

But electrical reality tends to be more capricious.

In Yy0 or Yyn0 systems, with a large number of nonlinear loads, harmonics appear that have no path to close.

As a result, the neutral starts “floating,” phase voltages drift outside tolerance, and users report flickering lights and strange device behavior. It is a bit like a bridge on three pillars – stable as long as the loads are even. But when one pillar takes more weight, the whole structure tilts.

That is why star–star is not by definition a bad solution, but it can be deceptively calm. Only adding a zigzag or another method of handling triplens makes the neutral truly reliable.

Third myth #3: “Dyn11 is the only European standard.”

Indeed, in textbooks and standards you will find Dyn11 as a reference system, easy to describe and unify. But just step down from the theoretical tower and look at the map of Europe to see the mosaic. In Germany, France, and the UK, Dyn11 dominates.

Meanwhile in Poland, the Czech Republic, Slovakia, and Southern Europe, Dyn5 has been the standard for decades. And not in a niche – a huge share of MV/LV transformers operating today in these countries have exactly this connection.

Why?

Because networks built in the 1970s and 1980s were planned from the start with Dyn5, and parallel operation requires consistency. As a result, Dyn5 is doing very well, still produced and delivered at hundreds of MVA every year.

Each of these myths shows something important:

In power engineering it is not enough to repeat formulas, you must understand the context.

Delta can be grounded and provides a stable system, star does not always guarantee a calm neutral, and Dyn11 has not displaced Dyn5. The choice of winding connection is not an academic dispute, but a practical decision on which the reliability of the entire network depends.

And that is what makes the letters and numbers on the nameplate more than just a code.

They are the story of standards, compromises, and local experiences.

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How to prepare a PV installation for integration with an energy storage system

Future 2025/2026: RES and electromobility change the rules of the game

Just a decade ago, the topic of winding connections seemed niche, something for designers and network engineers. Yet the years 2025 and 2026 show that those very letters and numbers on a transformer’s nameplate are becoming the foundation of energy stability.

The mix of energy sources and the nature of loads is changing faster than ever.

Development of photovoltaics

The development of photovoltaics has now entered a stage where numbers impress more than slogans.

In 2025 the total installed PV capacity in Europe exceeded 400 GW, which means a doubling compared to 2020.

Forecasts for 2026 point to another annual increase of several dozen gigawatts – as if every year we were adding to the grid the equivalent of a dozen large nuclear power plants. And while that sounds impressive, every additional PV inverter is not only a source of clean energy but also a potential source of problems with the quality of that energy.

Inverters operate in a nonlinear way.

In practice this means that apart from the desired 50 Hz frequency they inject harmonics into the grid – particularly the third and ninth, which tend to add up rather than cancel out. When there are hundreds of thousands of inverters, the low voltage network starts to live its own chaotic rhythm. At that point, the question of whether a transformer is Yzn or Dyn is no longer a curiosity.

It is precisely the type of winding connection that decides whether the grid remains stable or turns into a testing ground for active filters and reactive power compensators.

This is where the role of connection systems comes in.

• Zigzag, thanks to its geometry, “absorbs” triplen currents and stabilizes the neutral.

• Yzn ensures that rural feeder lines, with rooftop PV installations at their far ends, do not collapse under the weight of harmonics and uneven loads.

• Dyn, properly chosen, isolates the medium voltage network from problems generated by thousands of inverters on the low voltage side.

In 2025 and 2026, when system operators will be connecting hundreds of new PV farms and thousands of rooftop systems every week, it is the transformer nameplate and its “magic symbols” – Yzn5, Dyn11, or Yzn11 – that will decide whether solar power enters the grid smoothly or with disturbances that force costly upgrades.

One could say that a transformer with the right winding connection becomes not just the “gateway” for green energy, but also the filter that keeps the network in order before harmonics spill over the entire system.

Electromobility

By 2026 the European Union is expected to have as many as 7 million EV charging points in operation.

Behind this figure lies more than driver convenience. It represents a massive revolution in the load profile of distribution networks.

This is especially evident in fast-charging hubs, where a dozen or more vehicles may start charging almost simultaneously.

At such moments the grid sees not only a sudden surge in power demand, but above all a set of highly nonlinear loads that can distort voltage and push the neutral conductor to its limits.

Every fast-charging station is a power electronic converter operating in switching mode. A few in parallel can still be balanced, but when there are a dozen or more, the network begins to experience extreme asymmetries.

On one phase the load can be tens of percent higher than on another, while the neutral conductor, instead of carrying a steady current, suddenly sees a torrent of triplens – the third, ninth, or fifteenth harmonic.

The effects are immediate: heating of the neutral, voltage flicker, and sometimes even tripping of protections that disconnect the entire hub.

In such conditions the winding connection of the transformer feeding the charging station becomes crucial.

It is precisely this connection that decides whether the local network will take the load and remain stable, or collapse under the pressure of harmonics.

• Yzn, thanks to the zigzag on the LV side, keeps the neutral firmly in place and “absorbs” a significant portion of triplen currents. As a result, phase voltages stay within the permissible range even under strong load imbalance.

• Dyn isolates the medium voltage side from disturbances generated by chargers, trapping in its delta loop the harmonic currents that must not flow upward into the grid.

It can therefore be said that in the era of electromobility the transformer becomes the first and most important quality-of-energy filter. In 2026 the choice between Yzn and Dyn will no longer be a matter of local habits or investment costs. It will be a necessary condition for fast-charging stations to operate without interruptions and for network operators to avoid a wave of complaints and outages.

Ultimately, it is the stable neutral and the ability to suppress harmonics that will decide whether the growth of electromobility goes hand in hand with network stability, or becomes a constant struggle with power quality.

The future belongs to flexible solutions

Hybrid multi-winding transformers are already appearing on the market, combining delta, star, and zigzag in a single core.

Thanks to this, one transformer can simultaneously:

• provide a neutral point for consumers,

• trap third-order harmonics inside its windings,

• synchronize with the MV grid according to DSO requirements,

• stabilize the operation of PV inverters and EV charging stations.

Ask us about tailor-made solutions.

This is no longer theory. In 2025 the first PV farms in Germany and Spain are testing multi-winding units that enable better microgrid integration with the distribution network. Similar projects are underway in Poland and the Czech Republic, where DSOs are preparing for the growing number of EV chargers in smaller cities.

It is already clear that in 2026 the question of winding connections will no longer be an academic debate about standards. It will be a real factor determining the safety and quality of low voltage networks. A stable neutral and the suppression of harmonics are not optional extras but an absolute necessity in an era where every rooftop and backyard becomes a mini power plant and every shopping center a hub of electromobility.

What only a few years ago seemed like a theoretical subject from a transformer handbook is becoming the daily reality of engineers, designers, and operators in 2025–2026.

Transformers with “intelligent” winding connections – Yzn, Dyn with zigzag, or hybrid designs – will be the backbone of the green transition and the foundation of stable energy systems in the future.

What we can do for you

At Energeks we look at transformer winding connections as straightforwardly as we look at PV or storage integration. Our task is not only to deliver equipment but to ensure that the energy you generate and consume actually works for you in the most efficient way possible.

That is why we focus on oil-filled and cast resin transformers compliant with Tier 2 Ecodesign standards, practically lossless and optimized for harmonics. Every kilowatt matters today, and in your plant what counts are real results, not declarations on paper.

Check our store for units available off the shelf, and explore the full Energeks transformer portfolio.

If you are an investor, a designer, or an industrial facility manager and you want to:

• increase supply reliability in a grid dominated by PV and EV,

• mitigate the impact of harmonics and load asymmetries,

• implement Tier 2 technologies and solutions aligned with European standards,

we invite you to work with us. We believe the best results are achieved not alone but in partnership with clients, designers, operators, and suppliers. We offer comprehensive advisory services as well as tailor-made solutions, including the selection of the appropriate connection group.

Thank you for your time and attention in reading this article.

If the future of MV transformers and their integration with modern energy sources is a relevant topic for you, we encourage you to get in touch. Together we can build a system that not only works but operates without losses, without compromises, and in the spirit of forward-looking energy.

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Sources:

Networking modelling for harmonic studies” – Technical Brochure CIGRÉ

Renewables 2024 – Analysis – IEA

Global Energy Storage Market Records Biggest Jump Yet – BloombergNEF