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 rarely arrives with a bang.

It more often creeps in quietly.

First, a few chilly mornings.

Then dampness that doesn't disappear even at noon.

And finally, small, easy-to-ignore signals. The transformer is operating. Parameters are still within spec. Nothing is whining. Nothing is sparking. And that's precisely when the problem begins.

Water vapor condensation inside a transformer tank doesn't produce spectacular symptoms.

It doesn't shut down the grid in one day. It doesn't send an SMS alarm. It works like a slow corrosion of trust. Accumulating on the tank walls, in the paper insulation, and in the oil, it systematically reduces the electrical withstand strength of the system.

This is a topic that returns every winter. And almost always when it's already too late.

For years, we have worked with medium-voltage transformers in real operating conditions.

We have seen transformers that were correctly sized electrically, met EcoDesign Tier 2 requirements, had complete documentation, and new oil.

And yet, after two or three winter seasons, they started causing problems.

The common denominator was very often moisture.

Water vapor condensation is not a manufacturing defect. It's a physical phenomenon.

This text is for everyone who wants to understand what really happens inside a transformer tank in winter and how to prevent it before the quiet killer starts counting the losses.

After reading, you will know where the water in a transformer comes from, why the problem intensifies in winter, what the real consequences are for the insulation, and how to mitigate the risk through both design and operation.

Reading time: 12 minutes

Where does water vapor in a transformer tank come from

Air always contains water.

Even when it seems dry.

Relative humidity is not an abstract parameter from a weather forecast. It is the actual amount of water vapor that can condense when the temperature drops.

A transformer tank is a closed space, but it is rarely perfectly sealed in the physical sense. Even hermetic constructions have micro-phenomena of diffusion.

Add to this moments of opening, transportation, installation, oil filling, and maintenance work.

If air with a specific humidity enters the tank interior, and then the temperature of the tank walls drops, water vapor begins to condense.

The dew point is often reached faster than we expect.

In winter, this mechanism works mercilessly.

During the day, the transformer operates, the oil heats up, and the air inside increases its capacity to carry moisture.

At night, everything cools down.

The water vapor seeks the coldest surface.

Most often, these are the upper parts of the tank and structural components

Why winter acts as a catalyst for the problem

Winter is a season of large temperature amplitudes. A difference of several dozen degrees between day and night is not unusual. For a transformer, this means the cyclic breathing of the oil and air volume.

The key concept here is the dew point. This is the temperature at which air with a given relative humidity can no longer keep water vapor in a gaseous state.

For example, air with a relative humidity of 60% at a temperature of 20°C reaches its dew point at around 12 degrees.

This means that any surface colder than this threshold becomes a site for condensation.

The walls of a transformer tank in winter very often have a temperature significantly lower than the air inside. Especially the upper parts of the tank, the covers, and structural components protruding above the oil level. That is where water vapor condenses first.

In breathing transformers, every cooling cycle means drawing in air from the outside. If the air dryer is worn out, incorrectly sized, or simply forgotten, moisture enters the interior. At temperatures near zero, the air's capacity to store water vapor drops sharply, so condensation occurs almost immediately.

In hermetically sealed transformers, the phenomenon is subtler but still exists. Oil changes volume with temperature.

With a temperature drop of 20°C, the oil volume can decrease by about 1%.

In a tank with a capacity of several thousand liters, this means real changes in pressure and the performance of seals.

Moisture doesn't enter through the door, but it enters through the window of physics. The diffusion of water vapor through sealing materials is slow but non-zero. Winter gives it time and favorable conditions.

Additionally, in winter, the transformer often operates under a higher load. Heat pumps, electric heating, electric vehicle charging infrastructure. More heat during the day, more cold at night.

Ideal conditions for condensation.

What happens to water after it condenses

Water inside a transformer tank does not behave like a puddle on concrete. Its fate depends on many factors.

Some of the condensed water flows down the tank walls and enters the oil.

Transformer oil has a limited capacity to dissolve water.

At a temperature of around 20°C, this is in the range of several dozen ppm*.

*ppm = parts per million - equivalent to 1 milligram per liter of substance (mg/l) or 1 milligram per kilogram (mg/kg) of water.

Excess water migrates into the paper insulation. And electrical insulation paper acts like a sponge. Once absorbed, moisture is very difficult to remove from it.

Each percentage point increase in water content within the paper dramatically lowers its electrical withstand strength and accelerates aging. This is not a linear process. It's a curve that suddenly begins to spike.

Olej i wilgoć. Toksyczny duet

Olej transformatorowy pełni dwie kluczowe funkcje. Izoluje i chłodzi. Wilgoć uderza w obie naraz.

Rozpuszczalność wody w oleju transformatorowym silnie zależy od temperatury.

W temperaturze 20° C typowy olej mineralny jest w stanie rozpuścić około 30 do 50 ppm*

Przy 60° C ta wartość może wzrosnąć nawet trzykrotnie.

To oznacza, że w ciągu dnia olej wchłania wilgoć, a w nocy, gdy temperatura spada, nadmiar wody zaczyna się wytrącać.

Już niewielki wzrost zawartości wody w oleju powoduje spadek napięcia przebicia.

Przy poziomie 20 ppm napięcie przebicia może wynosić ponad 60 kV.

Przy 40 ppm spada często poniżej 40 kV.

To różnica, która w warunkach zwarciowych decyduje o przeżyciu lub porażce izolacji.

Zimą zdradliwy jest efekt pozornej poprawy.

Pobierając próbkę oleju w niskiej temperaturze, można uzyskać wynik wskazujący niższą zawartość wody rozpuszczonej. Część wilgoci znajduje się wtedy już w papierze lub w postaci mikrokropelek, których standardowe badania nie zawsze wychwytują.

Do tego dochodzi przyspieszone starzenie oleju.

W obecności wody i podwyższonej temperatury rośnie tempo reakcji chemicznych.

Tworzą się kwasy. Zwiększa się liczba kwasowa.

Olej traci swoje właściwości szybciej, niż przewiduje IEEE.

Oil testing in winter - 3 key methods

In winter, interpreting oil test results requires particular caution.

Three tools become crucial.

The first is determining water content using the Karl Fischer method.

The result must always be referenced to the oil temperature at the time of sampling and the transformer's operational history. A low ppm result from a cold sample does not mean moisture is absent. It may mean it has already left the oil.

The second tool is the analysis of Dissolved Gases (DGA).

Elevated concentrations of hydrogen and carbon monoxide in the absence of classic fault gases can be the first signal of insulation paper degradation caused by moisture.

The third element is observing trends, not single data points.

In winter, comparing results from different seasons is especially important.

Spikes in water content between summer and winter tell more than the absolute value.

Analysis of transformer oil allows for detecting the effects of water vapor condensation before it leads to degradation. This type of analysis helps identify insulation threats before winter failures occur. Photo CC: Freepik/13628

A transformer doesn't fail on the day it's tested. It tells a story that one must know how to read.

Paper insulation. The weakest link

At first glance, paper insulation seems like a secondary element.

It's not visible from the outside, it doesn't have parameters easily sold in a table, it doesn't impress like power or efficiency. And yet, it is very often what determines the real end of a transformer's life.

Electrical insulation paper ages by definition.

The process of cellulose depolymerization always occurs, even under ideal conditions.

The problem begins when moisture enters the game. Even a small increase in the water content of the paper acts as an aging catalyst. It is accepted that each doubling of the paper's moisture content significantly accelerates the degradation of cellulose chains.

What does this mean in engineering practice?

A drop in the mechanical strength of the windings. The paper ceases to serve as a stable spacer, and the windings lose their resistance to the electromechanical forces that appear during faults.

A transformer can operate correctly for years, until the first major grid test. Then, weak insulation doesn't fail spectacularly. It simply doesn't hold up.

Moisture is not a failure. It's a process.

A quiet killer that doesn't destroy immediately but systematically erodes the transformer's safety margin. And that's precisely why paper insulation is often the weakest link in the entire system.

Not because it is bad, but because it is merciless towards neglect.

Hermetic transformer or one with a conservator? Differences in moisture risk

In winter, a transformer quickly reveals which school of construction it comes from.

A hermetic transformer, by definition, limits contact with external air. The oil, gas space, and tank form a closed system. For moisture, this is a difficult situation. There are no revolving doors, no daily invitations for water vapor to enter. This is a huge advantage during the heating season.

But a hermetic transformer is not a magical vacuum capsule.

It's still steel, seals, and people doing the assembly. One poorly tightened connection, one gasket installed on a humid day, and moisture has a subscription for years. No dryer, no vent, no evacuation route. Silence, calm, and very long-term consequences.

Constructions with an oil conservator work differently.

Here, the oil volume is compensated by contact with atmospheric air.

This is a known, proven, and still common solution. However, in winter, it requires character.

An air dryer is not a decoration. It's the security guard at the gate. If it's asleep, moisture walks in without asking. And in winter, a dryer tires out faster than in summer. The gel loses effectiveness, indicator colors can lie, and every night's cooling cycle is another dose of moisture sucked inside.

In short, it looks like this. In a hermetic transformer, the design and installation are responsible. In a transformer with a conservator, operation is responsible. Physics is impartial, but very meticulous.

Therefore, the choice shouldn't start with the question which is better, but rather who will take care of it during winter.

We've already covered this topic in more detail here:

Transformer oil conservator – what it is, how it works, and when it is needed

Because water vapor doesn't have a favorite technology.

It simply checks where it can enter without knocking.

Common installation mistakes

Moisture is rarely the fault of the equipment itself.

More often, it's the result of small oversights:

✖ Opening the tank in humid conditions without protective measures.
✖ Leaving the transformer without oil for extended periods.
✖ Transport and open-air storage without protective covers.
✖ Lack of preheating before startup in winter.

Each of these elements seems harmless on its own. Together, they build the perfect environment for condensation.

Symptoms that are easy to ignore

The first signals of moisture presence are subtle:

✖ Slight changes in oil parameters.
✖ A gentle increase in the dissipation factor (tan delta).
✖ A minimal reduction in breakdown voltage.

They often end up in a periodic test report and remain there for years. Without any action (✖!) because, after all, the transformer is operating. The problem is that physics doesn't read reports.

How to reduce the risk of condensation

It's impossible to completely eliminate moisture.

But it is possible to manage it.

From a design perspective, it's worth opting for hermetic constructions.
Ensure appropriate oil volume reserves and solutions that minimize temperature fluctuations.

From an operational perspective, discipline is key.
Inspections, oil testing, responding to deviations.

In winter, the startup procedure becomes particularly important.
Gradual loading.
Avoiding sudden heating and cooling cycles.

A modern approach to MV transformers

Modern transformers are designed with such scenarios in mind.

Winter will always come.
Water vapor condensation doesn't make noise.
It doesn't flash red.
But it leaves a mark every season.

Conscious design, correct installation, and attentive operation allow you to erase that mark before it turns into a costly failure.

That's why the choice of a transformer is increasingly not just a decision about power and voltage.
It's becoming a decision about resistance to real operating conditions.

If you are considering purchasing or replacing a transformer, our current range of oil-immersed transformers has been designed precisely for scenarios where moisture, temperature variability, and seasonal load changes are the norm, not the exception.

They are complemented by dry-type transformers for where environmental conditions or the nature of the installation require a different approach.

We also invite you to the Energeks community on LinkedIn, where we regularly share knowledge from the power engineering industry.

SOURCES:

IEEE Power and Energy Society. Moisture effects in oil filled transformers.

CIGRE Technical Brochures on transformer insulation ageing.

IEC publications on insulating liquids and moisture management.

Cover Photo: Freepik/2148635097

There is a moment like that.

The transformer is already on its foundation, the oil is filled, everything looks solid, and someone half-jokingly says, "Well, that's one thing off our plate."

The unit is in place, voltage is present, the network is operational. At first glance, the matter is closed.

Except an oil transformer doesn't know the concept of "off our plate."

It is only just beginning its work.

And it remembers very well how it was installed, the conditions it operates in, how it was treated in the first months of service, and whether anyone even glanced at its documentation after commissioning.

When writing about the installation and maintenance requirements of oil transformers, we are not revisiting theory for theory's sake.

We are revisiting experiences from project implementations, whose origins almost always lie much earlier than it seems. Often in decisions that, at the moment of installation, seemed minor, obvious, or "done this way for years."

This article is for designers, contractors, investors, and maintenance personnel who want to have calmer heating seasons and fewer phone calls that start with the words, "something's up with the transformer."

To start, we'll talk about why installing a transformer is more than just correctly placing it on a foundation.

Next, we'll look at daily operation and what the transformer "tells" us through its behavior long before a failure occurs.

Finally, we'll return to maintenance, understood not as a checklist of tests, but as a way of thinking about a device that is meant to operate stably for decades.

reading time ~10 min

Installation of an oil transformer, or the moment you create your future or problems in installments

Installing an oil transformer is not just a "logistical operation."

It is not just unloading, placing, and signing a handover protocol. It is the moment when this device gets its character. Like a person at the start of their career. You either set them up for success, or later you'll be hauling them to workshops. Except this involves costly, time-consuming hassle.

A transformer pays you back for everything in failures.

A shoddily made foundation is a classic.
Concrete, sure. Rebar, sure. There was a design, sure.
The level was checked once because they were in a hurry. "It's almost level."

And here, the first red light goes on. An oil transformer is patient, but it's not naive. It remembers every millimeter of tilt, every makeshift solution, and every solemn "we'll fix it later." "Later" usually never comes.

At first, everything looks proper. Oil is filled, the tank stands, cooling works.
Except with even a slight tilt, the oil inside starts working differently than the manufacturer intended. Cooling becomes uneven, windings experience conditions no one predicted, and the transformer begins to age faster than it needs to. This isn't visible immediately. It shows up over time. Always over time.

Ventilation is another topic that often loses to reality.

An oil transformer doesn't like standing in a stuffy corner, even if it looks like a chunk of solid iron. A too-tight enclosure of a prefabricated transformer substation, a lack of sensible airflow, poorly chosen clearances. A classic. The first season is quiet. The second one too.

And then questions start about why temperatures don't match the theory.

If anyone wants to see how much operating conditions can change the rules of the game, it's worth revisiting the topic of transformer substations operating in heavy industrial conditions:

Otoczenie, montaż i projekt to jeden organizm, a nie trzy osobne tematy:

How not to burn a million? Principles for building a transformer substation for heavy industry

The environment, installation, and design are one organism, not three separate topics.

Grounding is a separate story

"It's connected, the resistance tested out, the protocol is done."

Everyone has heard that.

Except that grounding doesn't exist for paper. It's there to protect the transformer, the installation, and people. A poorly executed one will take its revenge during the first disturbances, overvoltages, or lightning strikes. And again, not always immediately. Most often, when nobody has time for it.

Installation is not a cost. It is an investment. An investment in whether you'll sleep soundly in five years or be nervously sifting through documentation wondering who signed off on the foundation back then.

Operation of an oil transformer, or: it's talking all the time, you just have to stop pretending not to hear it

An oil transformer in operation is not a "grey box."

It is not a device that either works or it doesn't. It talks non-stop.

Just not via email or alarms, until it absolutely has to. It talks through sound, temperature, smell, and behavior. The problem is that many people consider this background noise.

At first, everything is by the book.

It runs, voltages match, load is normal. And then the most dangerous phrase in power engineering appears: "It works, don't touch it." Hearing that phrase, an oil transformer starts planning its revenge, only spread out over time.

The first signal is often sound.

A soft hum is normal, everyone knows that. But a change in the sound's character is not normal. A deeper tone, a metallic resonance, irregularity. This isn't "the charm of an old network." It is information. Ignored information.

Then come the temperatures. Someone glances at the readings and waves it off.
"Summer, it's warm, higher load." Sure, it happens.
But if the transformer regularly runs warmer than before, it's not a whim of the weather. It's a signal that something in the operating conditions has changed. Cooling, oil, ventilation, surroundings. Something is off.

The smell of oil near the transformer is something many people only notice when it's already really strong.
A pity. Transformer oil can tell you a lot much earlier. A change in smell, color, clarity. These are trivialities only for someone who doesn't want to see them. For the transformer, it's a full-fledged language of communication.

Oil leaks are one of those signals that everyone sees, but many pretend it's "nothing serious." A drop here, slight dampness near a gasket, a trace on the oil sump.
At this moment, the oil transformer isn't screaming. It's just raising its hand and calmly saying that something is no longer sealed. Ignoring such small things is a straight path to accelerated insulation aging, cooling problems, and costs that always appear at the least opportune moment.

That's why if someone wants to understand why oil leaks are not a cosmetic issue but a real warning signal, it's worth checking out the separate article dedicated to this topic:

Oil leaks in transformers – do not ignore these signals

There you can see in black and white that oil doesn't escape without reason, and every leak is information about the state of the transformer, not just the state of a gasket.

Operation is also about loading.

An oil transformer can handle overloads because it was designed for that.
But it handles them short-term. Permanently operating at the power limit is not proof that "we managed with a reserve." It is a very consistent and very predictable way of shortening the device's life.

An oil transformer doesn't spring surprises. It is predictable to a fault.
You just have to want to listen, not assume that if the light is green, the issue doesn't exist.

Maintenance of an oil transformer, or why revisiting the beginning saves the future

Maintenance has terrible PR.

It's associated with paperwork, costs, and an obligation that can always be pushed to later. Preferably to the next quarter. Or the next year.

Meanwhile, for an oil transformer, maintenance is the purest form of ensuring longevity. Without it, even the best-designed device starts showing signs of fatigue sooner.

And here it's worth going back to basics for a moment.

To the moment when the transformer was installed and commissioned. Because very often, what we call an operational problem today is not a new failure or some malicious fault of the equipment. It is a consequence of how the installation was done at the start.

An oil transformer doesn't change the rules mid-game. It simply delivers on what it was given at the beginning.

If something was rushed during installation, if something was done by eye, if the handover was quick because the deadline was looming, then maintenance will show it sooner or later. Temperature changes, unusual sounds, faster oil aging, cooling problems. These aren't new phenomena.

They are the effects of earlier decisions, just stretched over time.

Oil testing is the best example here.

It's not a manufacturer's whim or a standard's invention. It is the simplest and cheapest way to look inside a transformer without taking it apart. Physicochemical parameters, dissolved gas content, oil moisture level say more than many a visual inspection.

And yet, in practice, tests are done irregularly or only "for handover," as if the oil stopped working after the protocol was signed.

Seals, accessories, electrical connections, and grounding also age.

A transformer doesn't stand in a sterile lab. It operates under variable temperature, humidity, vibration, and pollution. Every season adds its share. A lack of regular inspection means small problems have time to grow. And then everyone is surprised that something that seemed cosmetic suddenly becomes an emergency issue.

That's why returning to the installation stage when operational and maintenance questions arise is one of the best things you can do.

Checking whether the foundation truly met the assumptions, whether ventilation works as intended, whether grounding was executed according to the craft, not just according to the protocol. This often explains more than hours of analyzing current parameters.

The specific stages that have a real impact on how the transformer behaves later in daily operation, and why some units work quietly for years while others start acting up much sooner, are described here:

Power transformer installation – a comprehensive checklist

The most important thing is the approach

Maintenance is not a checklist to tick off or an obligation imposed by standards.

It is a way of thinking about a transformer as a device that should operate stably for twenty, thirty years. Every test, every note, and every review shorten the list of surprises.

An oil transformer does not spring surprises.

It is predictable to a fault. If something starts happening, it is very rarely a coincidence. Usually, it's a response to the conditions it has been given. Except the response comes with a delay, at a time when everyone is already convinced the matter was closed long ago.

If you want smooth operation, you need to honestly look at the beginning and regularly check in along the way.

An oil transformer doesn't require flattery or gifts. It requires attention.

And attention pays back with interest, most often when others are busy putting out fires.

Don't stop at the start

An oil transformer is not a matter to "tick off." It is a piece of infrastructure that either works quietly for years or regularly reminds you of itself at the least opportune moments.

Transformer installation, operation, and maintenance are not three separate worlds.

It's one story, written from the day the transformer was placed on its foundation. Every decision at the beginning works in the background later. Either for you or against you. An oil transformer doesn't create drama. It simply adds up the facts.

That's why if you're planning an investment, a modernization, or simply want peace of mind in operation, it's worth looking broader than just the moment of purchase.

At Energeks, we have been working with oil transformers in real grid, industrial, and infrastructure conditions for years. Our offering includes both oil-filled and dry-type (resin-insulated) units, selected for specific operating conditions.

Everything is in the EcoDesign Tier 2 class, with full documentation and certificates:

You can find the current transformer offering here.

Thank you for taking the time to read this text.

If even one thought stayed with you, it means it was worth it. And if you want to stay updated, I invite you to Energeks on LinkedIn.

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/

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

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We are grateful for your trust and the opportunity to be your partner in projects where safety, reliability, and sound judgment go hand in hand.

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

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.

You may also be interested in the topic:

Transformer K-factor: the key to protection against harmonics

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.

Check out our recent article:

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.

Also, join our community on LinkedIn.

Sources:

Networking modelling for harmonic studies” – Technical Brochure CIGRÉ

Renewables 2024 – Analysis – IEA

Global Energy Storage Market Records Biggest Jump Yet – BloombergNEF

Spark gap in a medium voltage transformer – a guardian that sometimes looks guilty

Imagine walking into a prefabricated transformer substation on a foggy, humid morning. The air is dense, and in the background you hear the soft hum of a fan. You open the door to the medium voltage compartment, and your eyes are immediately drawn to one component – the spark gap.

It has dark streaks, burn marks, and uneven electrode coloration. If you have only seen new equipment before, you might instantly think: “We have a failure.”

However, the reality might be the complete opposite.

These marks do not necessarily indicate damage – very often they are proof that the spark gap has operated and protected the transformer from a dangerous overvoltage.

Just as a seat belt after a collision bears the marks of the strain it has absorbed, a spark gap after operation shows traces of the electric arc that saved the winding insulation.

Why are we writing about this?

At Energeks we work with medium voltage transformers in a variety of environments, from industrial plants to municipal facilities.

Many operators and investors come to us asking: “Is it normal for the spark gap to look burnt?” The answer is often yes – it is normal and even desirable, provided that the marks remain within the limits allowed by the manufacturer.

Our goal is simple:

To explain what a spark gap is, how it works, when it requires intervention, and how to service it so that the installation is protected at the highest level.

In this material you will find:

• What exactly a spark gap is and the functions it performs

• How the operation process works, from the occurrence of overvoltage to the dissipation of energy

• Why marks appear on the spark gap and what they mean

• The differences between a spark gap and a surge arrester

• Criteria for distinguishing normal operating marks from actual damage

• Inspection and maintenance procedures

• The impact of environmental conditions on the spark gap’s condition

• When replacement is necessary

• The importance of operator education

• The outlook for the future of overvoltage protection

Reading time: approx. 15 minutes

1. What is a spark gap in a medium voltage transformer

A spark gap in a medium voltage transformer is an overvoltage protection element that works like a safety valve for the power system.

Its construction is based on two or more electrodes separated by an air gap or a gas-filled gap.

Principle of operation:

• Under normal operating conditions, the working voltage is lower than the breakdown voltage of the air in the gap, so the spark gap does not conduct.

• When a sudden voltage surge occurs in the network (for example, as a result of lightning, switching operations, or line faults), the voltage between the electrodes exceeds the critical value – the so-called ignition voltage.

• An electric arc forms, conducting the energy to the grounding system and protecting the transformer windings.

Standards: According to PN-EN 60099 and IEC 60099, the parameters of the spark gap must be selected so that the ignition voltage is sufficiently higher than the network’s operating voltage but lower than the insulation withstand level of the transformer.

Laboratory spark gap with flat electrodes/CC: Wikimedia Commons

2. How the spark gap operates – from the occurrence of overvoltage to energy dissipation

The operation of a spark gap in a medium voltage transformer is an extremely dynamic phenomenon that unfolds within microseconds, yet it determines the safety of the device and often the entire substation.

It is worth following the process step by step to understand what actually happens in that small gap between the electrodes.

2.1. Occurrence of overvoltage

Under normal conditions, the network’s operating voltage is stable and remains well below the ignition voltage of the spark gap. Overvoltage occurs during a sudden rise in voltage, which may be caused by:

• Lightning discharge (a lightning impulse can have a steep front of around 1.2 µs and an amplitude of hundreds of kV)

• Switching operations in the network (switching large loads on or off, changing sections)

• Short circuits in other parts of the network (back surge voltage spikes)

• Ferroresonance in systems containing capacitances and inductances

When the voltage between the spark gap terminals increases and approaches the critical value, the initiation process begins.

2.2. Discharge initiation – ionisation of the medium

The medium between the electrodes (most often air or an inert gas in enclosed versions) acts as an insulator. However, after exceeding the so-called breakdown voltage, according to Paschen’s law, the gas molecules begin to ionise. Electrons accelerate in the electric field and, colliding with atoms, knock out additional electrons, creating an electron avalanche.

This is the moment when the resistance of the gap starts to drop rapidly. In practice, from the moment the ignition voltage is exceeded to full breakdown, only a few nanoseconds to several microseconds pass.

2.3. Breakdown and formation of the electric arc

Once the avalanche of ions and electrons forms a conductive path, breakdown occurs – an electric arc appears between the electrodes. The temperature in the arc channel rapidly reaches values of around 5000–6000°C.

In this state, the overvoltage current finds a path of minimal impedance toward the grounding system. Typical current values are:

• For lightning impulses – tens of kiloamperes (e.g. 8/20 µs according to standards)

• For switching surges – from several hundred amperes to several kiloamperes

2.4. Energy dissipation to grounding

The electric arc in the spark gap acts as a transport channel that carries the overvoltage energy from the medium voltage circuit to the grounding system. The quality and resistance of the grounding are crucial – high grounding resistance can cause dangerous step and touch voltages around the substation.

In professional installations, grounding with a resistance not exceeding 2–4 Ω is used for medium voltage substations, in accordance with PN-HD 60364 and PN-EN 50522 requirements.

2.5. Arc extinction and return to the idle state

After the excess energy has been discharged, the circuit voltage drops below the arc sustaining voltage. The plasma channel begins to deionise – ions and electrons recombine, temperature falls, and the gap between electrodes returns to its insulating state. The extinction time depends on factors such as:

• Spark gap design (open, enclosed, tubular)

• Pressure and composition of the medium

• Cooling rate

2.6. Marks after operation – the “scars” of protection

After the entire process, the electrode surfaces bear the effects of the arc:

• Localised burn marks at the initiation point

• Microscopic material losses

• Deposits of metal oxides and carbon

These are the very marks so often mistaken for signs of failure. In reality, in most cases they are evidence of effective protection.

3. Why marks appear on a spark gap and what they mean

Marks on a spark gap are a topic that often stirs discussion during transformer substation inspections. To the untrained eye, they may look like a sign of wear or damage. In reality, in many cases they are not only normal but even desirable – they indicate that the device has fulfilled its function and protected the transformer against overvoltage.

Where the marks come from

To understand why a spark gap bears “scars,” it is worth looking at the physical process that takes place during its operation. At the moment of overvoltage, the dielectric between the spark gap electrodes – most often air or a gas filling the housing – undergoes breakdown. An electric arc forms, and in its channel the temperature can reach 5000–6000°C.

Such high temperatures cause:

• Microscopic evaporation of electrode material – metal atoms transition to a gaseous state and, after cooling, condense on nearby surfaces as a dark deposit

• Metal oxidation – in the presence of oxygen and high temperature, dark-coloured metal oxides form

• Pyrolysis of organic particles (if insulating materials are nearby), resulting in carbon deposits

Types of marks

Marks on a spark gap can take different forms – and their appearance provides valuable information about the device’s operating history.

a) Localised burn marks
These are small, dark spots where the electric arc was initiated. They can occur after just a single operation.

b) Extensive discolouration
Appears when the spark gap has operated several times in a short period. The electrode surfaces change colour due to repeated heating and cooling cycles.

c) Carbon or metallic deposits
Formed from particles torn from electrodes or contaminants present in the air. In substations located near industrial facilities or in coastal areas, such deposits may be more intense due to the presence of salt or dust.

d) Surface dullness
The effect of long-term operation, where many micro-damages alter the metal’s texture.

What the marks mean – interpretation

Not every mark is an alarm signal. In assessing the condition of a spark gap, it is important to distinguish between signs of normal operation and signs of actual wear.

• Operational marks – proof that the spark gap has operated and fulfilled its function. These may include minor burn marks, discolouration, or a thin layer of deposit that can be easily removed.

• Critical wear marks – cracks in the ceramic or polymer housing, deep electrode material losses, permanent conductive deposits that reduce the insulating gap and may cause uncontrolled flashovers at operating voltages.

Everyday comparison

A spark gap can be compared to brake pads in a car. Friction marks do not mean the pads need replacing – on the contrary, they prove the brake is working. Replacement is only necessary when pad thickness falls below the limit or structural damage occurs. Similarly, in a spark gap, discolouration and light burn marks are a normal “trace of action,” not a failure.

Impact of the environment on the appearance of marks

Marks may look different depending on the conditions in which the substation operates:

• High humidity – promotes deposits with a more uniform, dark colour

• Air salinity – in coastal areas, deposits may be thicker and more conductive

• Industrial dust – causes grey or brown deposits, sometimes harder to remove

Why understanding mark interpretation is crucial

Misinterpretation can lead to two unfavourable scenarios:

• Unnecessary replacement – generating costs and downtime even though the component still works correctly

• Failure to replace – leaving a worn or damaged spark gap, which exposes the transformer to damage during the next overvoltage

We recommend documenting the spark gap’s condition during each inspection (photos, measurements).

4. Differences between a spark gap and a surge arrester

In the power engineering sector, these two terms are sometimes used interchangeably, which often leads to misunderstandings during inspections, spare part orders, or discussions with investors.

Although a spark gap and a surge arrester are functionally related – both are intended to protect equipment from the effects of overvoltage – their role, design, and operating scope are different.

Spark gap – a component, not a complete device

A spark gap is a single overvoltage protection component. It consists of two or more electrodes separated by an air gap or enclosed in gas. Its operation is simple and based on dielectric breakdown:

• Under normal conditions, it does not conduct current.

• When the ignition voltage is exceeded, a sparkover occurs and energy is diverted to the grounding system.

On its own, a spark gap cannot provide comprehensive protection against all types of overvoltage because it operates only when the ignition voltage threshold is exceeded. In medium-voltage transformers, it is most often used as an auxiliary element or in older designs.

Surge arrester – a complete overvoltage protection device

A surge arrester is a complete device that may include a spark gap as one of its components, but can also operate using other technologies – most commonly metal oxide varistors (MOV).

Types of surge arresters:

• Spark gap type surge arresters – older designs where the spark gap is the main trigger element. Additional components (e.g. resistors) control current after operation and extinguish the arc.

• Gapless surge arresters – modern designs based on zinc oxide varistors with a highly nonlinear characteristic: at operating voltage they conduct minimal leakage current, while during an overvoltage their resistance drops sharply, diverting energy.

• Why spark gaps are still found in MV substations

Although new projects increasingly use gapless surge arresters, spark gaps are still present in:

• Prefabricated transformer substations from the 1980s and 1990s

• Systems undergoing phased modernisation (where the transformer has been replaced but not the entire MV equipment)

• Installations with a limited budget, where simple protection is better than none

Cooperation between spark gaps and surge arresters

In some systems, spark gaps and surge arresters work together:

• The surge arrester (e.g. MOV) responds to smaller, more frequent switching overvoltages

• The spark gap acts as a “last resort” safeguard against very high overvoltages, for example from a nearby lightning strike

This tandem is particularly effective in environments with a high risk of lightning overvoltages.

Put simply – the spark gap is like a trigger, and the surge arrester is the entire protection system.

One is a component, the other is an integrated solution.

Understanding this distinction is essential for correctly interpreting equipment condition in a substation and making service decisions.

Spark gap and surge arrester, the difference explained in three sentences

A spark gap consists of two electrodes with an air or gas gap between them, which conduct only after a voltage breakdown and extinguish after the overvoltage ceases.

In the power industry, a surge arrester is most often a sparkless zinc oxide arrester in a polymer housing. It acts as a non-linear surge clamping element and returns to high resistance after a surge.

These terms should not be confused with “lightning rod.”

A lightning arrester protects equipment and lines, not the building itself.

5. Criteria for distinguishing normal operational marks from actual damage

During an inspection of a prefabricated transformer substation, many people, when seeing dark streaks, burn marks, or deposits on a spark gap, automatically assume the component is damaged. In reality, proper assessment requires looking not only at colour and appearance but also at geometric parameters, material condition, and operating history. In the power industry, several precise criteria are used to distinguish a “trace of operation” from a “sign of failure.”

Visual inspection – the first assessment filter

The basic step is to inspect the spark gap in good lighting, preferably using an inspection torch.

Normal operational marks:

• Small, localised burn marks at arc initiation points

• Slight discolouration of electrode surfaces

• A thin deposit layer, easy to remove during cleaning

Damage indicators:

• Cracks in ceramic or polymer housing components

• Mechanical deformation of electrodes

• Melting with visible depth to the naked eye

Electrode gap measurement

Each spark gap has a manufacturer-specified nominal distance between electrodes, which is critical for the ignition voltage.

• Permissible tolerance is usually ±0.1–0.3 mm depending on the model

• If the gap has decreased due to erosion or deposits, ignition voltage may drop below operating value, risking uncontrolled operation

• If the gap has increased (e.g. due to mechanical damage), the spark gap may fail to operate in time, exposing the transformer to insulation breakdown

Condition of insulating surfaces

In open spark gaps, the insulation is air, but ceramic or polymer housing parts act as supports and spacers.

Normal condition:

• Light surface deposit, removable

• No visible losses or cracks

Failure condition:

• Cracks running through the full thickness of the insulator

• Traces of surface flashover (characteristic dark “tracking” marks along the insulator)

Type and structure of deposits

Deposit forms from condensed electrode material and airborne particles.

• Safe deposit – thin, dry layer, non-conductive, easily removed with a dry cloth or antistatic brush

• Risky deposit – thick, compact layer that may have conductive properties (especially in high humidity), potentially causing leakage currents and premature operation

Operating history and number of operations

Some spark gap models (especially in integrated arresters) are equipped with an operation counter. A value close to the maximum allowed indicates that the component is nearing end-of-life, even if it looks fine. In spark gaps without a counter, photographic documentation from previous inspections is essential to track deterioration over time.

Leakage resistance measurement

Advanced inspections may include measuring insulation resistance between electrodes at a DC test voltage (e.g. 500 V DC).

• Values in the hundreds of megaohms are typical for a healthy component

• A drop below several dozen megaohms may indicate conductive deposits or microcracks

Normative criteria – when to declare a failure

Standards such as PN-EN 60099 and IEC 60099 state that an overvoltage protection element should be considered defective when:

• It fails to meet the declared ignition voltage in a control test

• It has mechanical damage that may affect operational safety

• It shows a permanent drop in insulation parameters

A practical rule often applied at Energeks:

If the mark can be removed and the component retains its geometric and insulation parameters – it is a normal operational effect.
If the mark is permanent and parameters deviate from standard – it is a sign for replacement.

6. Procedures for inspection and maintenance of a spark gap in an MV transformer

Regular inspection and proper maintenance of spark gaps in medium voltage substations is one of the simplest yet most effective ways to extend transformer lifespan and ensure continuity of power supply. Neglect in this area can result not only in costly failures but also in safety hazards for the operating personnel.

We recommend implementing a structured inspection procedure.

1. Preparation for inspection – safety first

Before performing any work on the spark gap, you must:

• Disconnect the substation from the power supply in accordance with facility procedures.

• Confirm de-energized status using a certified voltage detector.

• Ground and short the MV circuits if required by DSO procedures.

• Ensure the worker has personal protective equipment (electrical insulating gloves, safety glasses, helmet, flame-resistant clothing).

2. Visual inspection – the first stage of diagnostics

• Check the condition of the electrodes for discoloration, burn marks and deformations.

• Assess the insulator surface (ceramic, polymer) looking for cracks, scratches, or signs of surface tracking.

• Analyse deposits to determine whether they are dry and easy to remove or compact and potentially conductive.

Energeks tip: use an inspection flashlight with a narrow beam to better spot microcracks and surface irregularities.

3. Measuring the electrode gap

• Use a caliper or feeler gauge.

• Compare the measurement with the value specified in the technical and operational documentation (DTR).

• If the gap is smaller than the nominal value by more than 0.3 mm, cleaning or replacement is necessary.

• An excessively large gap (for example after mechanical displacement) may prevent timely operation.

4. Cleaning

• Perform cleaning only when the spark gap is dry and de-energized.

• Use a dry, soft antistatic brush or a microfiber cloth to remove deposits.

• For stubborn deposits, use isopropyl alcohol (IPA) applied to the cloth, never directly on the spark gap.

• After cleaning, the element must be completely dry before re-energizing.

5. Photographic documentation

• Take photos from three perspectives: front, side, and electrode detail.

• Mark the date, substation number, and field number.

• Compare with previous photos to determine the rate of degradation.

Why this matters: a visual history of the component allows predicting the replacement time before a failure occurs.

6. Measuring electrical parameters (optional)

For spark gaps sensitive to deposits, insulation resistance can be measured:

• Set the meter to a test voltage of 500 V DC.

• Above 100 MΩ – very good condition.

• Below 50 MΩ – additional cleaning or replacement is required.

7. Replacement criteria

The spark gap must be replaced if:

• it has cracks or mechanical damage,

• the electrode gap deviates from the nominal value and cannot be corrected,

• conductive deposits remain after cleaning,

• insulation parameters have dropped below acceptable limits.

8. Inspection schedule

• Substations in normal environments – inspection every 12 months.

• Environments with high dust or salinity – inspection every 6 months.

• Critical substations for power continuity – additional inspections after each storm or network failure.

9. Best practices

• Maintain an inspection log with notes on condition, service actions, and measurements.

• Use original spare parts in accordance with DTR.

• Train personnel to interpret operational marks to distinguish them from faults.

  ---

7. Impact of environmental conditions on the condition of the spark gap

The effectiveness of a spark gap depends not only on manufacturing quality and correct installation but also on the environment in which it operates. A prefabricated transformer substation can be located in very different conditions – in the city center, next to an industrial plant, at a seaport, or near an open-pit mine. Each location presents different challenges for the spark gap.

Humidity and condensation

Mechanism of influence: High air humidity, especially combined with low temperature, leads to condensation of water on insulator and electrode surfaces. Water conducts electricity (especially with dissolved salts and contaminants), so a thin moisture layer can reduce the sparkover voltage.

Effects:

• premature spark gap operation under normal working conditions,

• formation of mineral deposits after water evaporation,

• accelerated electrode corrosion.

Service recommendations:

• regular inspections during periods of large temperature fluctuations,

• checking substation ventilation,

• use of hydrophobic coated elements in high humidity environments.

Saline air (coastal zones)

Mechanism of influence: Microscopic salt particles carried by sea wind settle on insulator and electrode surfaces. Salt is highly hygroscopic, attracting moisture from the air and forming a thin conductive layer.

Effects:

• reduction in sparkover voltage by up to several dozen percent,

• increase in leakage currents,

• formation of persistent deposits that are difficult to remove.

Service recommendations:

• clean spark gaps at least twice as often as in inland substations,

• use enclosed or shielded designs,

• periodically rinse components with demineralized water combined with drying.

Industrial dust

Mechanism of influence: Dust from industrial processes (cement plants, metallurgy, coal-fired power plants) settles on substation components, including spark gaps. Many of these particles have conductive or semiconductive properties.

Effects:

• increased frequency of operation under moderate switching surges,

• higher risk of surface tracking,

• accelerated electrode wear from microscopic abrasive particles.

Service recommendations:

• use air filters in substation ventilation,

• clean spark gaps every 6 months or more frequently during intensive production periods,

• inspect insulator surfaces for microdamage.

Agricultural environments and organic dust

Mechanism of influence: Near agricultural processing plants, grain dryers, or farms, the air contains organic particles. These may include fats or sugars that, once deposited on insulators, form a sticky layer attracting dust.

Effects:

• formation of high-viscosity layers that are difficult to remove,

• localized conductivity under high humidity conditions,

• accelerated contamination of insulating surfaces.

Service recommendations:

• perform chemical cleaning with mild degreasing agents (with caution),

• carry out regular inspections during periods of intensive agricultural work.

Extreme temperatures

Mechanism of influence:

• High temperatures may cause thermal expansion of components, slightly changing the electrode gap.

• Low temperatures increase the risk of condensation and slow down moisture evaporation.

Effects:

• in hot climates – potential accelerated aging of protective coatings,

• in cold climates – higher risk of temporary drops in sparkover voltage.

Service recommendations:

• adjust inspection schedules to seasonal weather conditions,

• use materials resistant to UV and temperature fluctuations.

Why the environment must be considered in the service schedule

There is no single universal inspection interval for all substations – local conditions can shorten the required interval by as much as half.

We recommend the following approach:

Set the maintenance schedule after analysing location, history of spark gap operations, and grounding resistance measurements.

8. When to Replace a Spark Gap

A medium-voltage transformer spark gap can operate reliably for many years if it is correctly selected, installed, and maintained. However, like any electrical component, it undergoes aging and wear, and eventually its parameters will fall outside the manufacturer’s specified range. At that point, continued operation becomes a safety risk for the entire installation.

Most common reasons for replacement:

• Mechanical damage – cracks in the ceramic or polymer housing, broken or deformed electrodes, or loosened mounting hardware. Such defects can lead to uncontrolled arc discharges or loss of mechanical stability.

• Loss of geometric parameters – a change in the electrode gap beyond the tolerance specified in the technical documentation (typically ±0.3 mm) alters the ignition voltage. A smaller gap can cause premature operation, while a larger gap may prevent timely response to overvoltage.

• Excessive electrode wear – repeated operation causes erosion and material loss, leading to pitting and rounding of sharp edges.

• Permanent conductive deposits – industrial dust, salt, or corrosion products that continue to reduce resistance between electrodes even after cleaning. In humid environments, they can create conductive paths even at operating voltage.

• Loss of insulating properties – insulation resistance dropping below the recommended value (e.g. <50 MΩ), often caused by microcracks or permanent contamination in the material structure.

Replacement criteria according to PN-EN 60099 and manufacturer documentation:

• ignition voltage deviation greater than ±10% from nominal value during testing,

• exceeding the maximum number of operations specified in the documentation,

• mechanical damage affecting operational safety,

• insulation parameters below acceptable limits.

Why service history matters
Two spark gaps may look identical but be in completely different technical condition. Keeping a maintenance log – including inspection dates, number of operations, measurement results, and photos – allows accurate prediction of the replacement point and avoids both premature and overdue replacement.

The economic rule is simple: the cost of replacing a spark gap is negligible compared to the potential cost of repairing or replacing a transformer damaged due to lack of surge protection.

Recommended replacement timing:

• Immediately – in case of mechanical damage, visible cracks, or permanent conductive deposits.

• During the next scheduled outage – if the electrode gap or insulation resistance is close to its limit values.

• Proactively every few years – in environments with high overvoltage risk and heavy contamination, even if the spark gap appears to be in good condition.

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9. The Importance of Operator Training – An Investment That Pays Off

Anyone who has been inside a prefabricated transformer substation during maintenance knows that the work of an operator or service technician is far from a desk job. Sometimes it means stepping into a cramped space in heat, frost, or after a storm, flashlight in hand, fully focused on details invisible to the untrained eye.

That’s why at Energeks we see operator training not as a “training expense,” but as a strategic investment in the safety and reliability of the installation.

Why knowledge is crucial

• It helps distinguish normal spark gap wear marks from signs of failure.

• It enables cleaning or replacement decisions without unnecessary downtime.

• It supports accurate documentation of equipment condition.

The chain effect of good training
A trained maintenance team detects real threats faster, avoids costly “just in case” replacements, and takes care of equipment so that it stays fully operational for many years. It’s like a good car workshop – an experienced mechanic knows when a noise is part of normal operation and when it signals trouble, avoiding unnecessary repairs and costs.

Respect for people in the field
The best design and the most expensive transformer won’t stay safe if the operating team doesn’t have the skills, time, and tools to look after it. People are the first line of defense. The spark gap is the second.

Benefits for the investor
Training the team means lower failure and downtime risk, reduced long-term operating costs, and greater confidence that the infrastructure operates in compliance with standards and manufacturer guidelines.

Our approach
We combine theory with practice, show components in various conditions, explain phenomena in plain language, and answer every question – no matter how simple it may seem.

For us, education is not a lecture but a conversation, an exchange of experience, and the building of competencies that translate directly into real value in daily operations.

10. The future of surge protection – technology and people on the same team

Surge protection, with the spark gap as one of its elements, is a technology that combines engineering precision with human vigilance. It evolves alongside power networks, responding to the challenges of new renewable sources, operation in increasingly variable environments, and the need to ensure uninterrupted power supply in a world that doesn’t tolerate downtime.

In modern medium-voltage substations, spark gaps will increasingly operate in hybrid systems with MOV arresters, integrated into monitoring systems that record the number and parameters of operations, and housed in enclosures resistant to salt, moisture, and industrial dust.

If you are designing a new transformer substation, planning a network upgrade, or preparing for a compliance audit – we are here to help.

Visit our contact section if you need support in selecting, servicing, or documenting your surge protection systems.

We help you select, test, inspect, and prepare documentation so that your equipment operates without disruption – today, five years from now, and under conditions we cannot yet foresee.

Check our range of medium-voltage transformers – models compliant with PN-EN 60076, available off the shelf, with a full set of routine tests and optional special testing.

Join the Energeks community on LinkedIn. We share knowledge not to be in the spotlight, but to keep the grid running reliably.

Thank you for reading this text to the end.

We hope it has not only been a source of knowledge, but also an inspiration to ask more precise questions – because those questions are the fuel for every innovation.

SOURCES:

IEEE Xplore – “Spark Gap Devices for Surge Protection”

CIGRÉ Technical Brochure No. 549 – “Surge Arresters and Spark Gap Technologies”

IEC 60099-4: Surge arresters – Part 4: Metal-oxide surge arresters without gaps for a.c. systems –

July 2025 goes down in history as a weather rollercoaster: record-breaking heat alternating with torrential rain and local flooding.

It takes just one afternoon with a once-in-a-century storm for a prefabricated transformer substation to turn into a puddle and its heart – a medium voltage transformer – into a drowning victim.

And then? Silence. And tension. Both literally and figuratively.

In such moments, there is no room for panic or improvisation. What counts is procedure, competence and a quick assessment: can the unit be saved or is it better to disconnect it and say goodbye.

Why are we the ones writing about this?

Because we have rescued more than one “drowning victim”. Energeks specializes in MV transformers, prefabricated transformer substations and energy storage systems. We know the pain: hectares of flooded infrastructure, a million-euro transformer under water and an investor asking if it can be saved. Sometimes it can – but only if you know what you are doing. We are glad you are here.

Who is this article for and what will you gain?

This article should be read by anyone who:

• manages power infrastructure

• designs or operates MV substations

• is responsible for the energy security of a manufacturing plant, PV farm or warehouse hall

By reading this you will:

• learn the critical signs of damage after flooding

• discover how to properly dry a transformer

• understand when repairs are a waste of time

• learn the current standards and manufacturer recommendations

Here is what lies ahead:

• Heavy rain in an MV substation: what happens when the transformer is knee-deep in water

• Damage assessment: which components suffer the most

• Moisture, insulation and standards: how water affects safety

• Drying or replacement: making the technical and financial decision

• How to carry out an intervention step by step

• Manufacturer recommendations, O&M manuals and what to look for in service records

Reading time: approx. 12 minutes

Heavy rain in an MV substation: what happens when the transformer is knee-deep in water

This is not a textbook scenario. It is something that actually happens – especially in July when asphalt temperature reaches 52°C and after 6 p.m. the city is hit by a wall of rain mixed with walnut-sized hail. Water floods the lowest points of the terrain, including prefabricated transformer substations.

Although engineers anticipate a lot, nature can always outpace the design. So what happens to a medium voltage transformer when the water level reaches its base or even the main tank.

Voltage in water: literally and figuratively

A transformer is not a hermetically sealed device. Even so-called hermetic units have components through which moisture can enter. Rainwater – often contaminated with dust, salts and petroleum residues from roads – is conductive. This means one thing: increased risk of short circuits, corrosion, insulation damage and uncontrolled current leakage.

If water enters the transformer, it affects key components:

• bushings

• low and medium voltage windings

• magnetic core

• cooling systems and conservator

It is particularly dangerous when the MV connection compartment is flooded. This compartment is often located at ground level and is not fully protected against rainwater ingress.

Prefabricated substation and water retention

A prefabricated transformer substation, whether concrete, container-type or metal, is installed according to best practices. However, if it is not equipped with an effective drainage system, technical ducts, sumps and drains, it becomes a rainwater trap. Water collects around the foundation and during prolonged rainfall can enter through leaky doors, cable openings or an unsealed roof.

In practice, after just one hour of intense rain, the transformer can be standing in several centimeters of water. If the level reaches 25–30 cm, the lower connections, switchgear panels and low voltage winding ends are submerged. And that is enough to trigger a chain reaction of damage.

The sponge effect: moisture in the dielectric and paper structure

One of the least visible but most damaging consequences of water contact is moisture penetrating the insulation systems. Both the insulation paper used in windings and the transformer oil (mineral or synthetic, e.g. MIDEL) have specific moisture absorption classes. Even a small presence of water can lead to:

• reduced breakdown voltage

• partial discharge activity

• accelerated aging of insulation materials

In the worst case, this leads to internal breakdown, marking the end of the transformer's life.

Electricity and water: a deadly mix

From the operator's perspective, water in the substation is a hazard not only for the equipment but primarily for people. Moisture in an energized substation poses a risk of electric shock or even explosion. This is why every flooded substation should be immediately switched off and cordoned off before anyone enters.

DSO guidelines are clear: in the event of flooding, insulation resistance, grounding resistance and breakdown voltage measurements must be performed before the substation is put back into service. Even if the transformer appears “dry” at first glance.

Water does not always leave with the rain

The biggest problem is not the rainwater itself but the moisture that remains. Even after pumping out the water, microscopic amounts can remain in the transformer structure and surroundings. It penetrates absorbent elements such as rubber gaskets, insulation paper and insulating varnishes. This moisture is invisible to the naked eye but can cause gradual damage for months.

That is why it is crucial to:

• test the transformer for insulation moisture content

• perform DGA (dissolved gas analysis)

• analyze operational history to check if past high temperatures or overloads have weakened internal protection

Flooding of an MV substation is not just a weather incident. It is a full-scale failure that requires a systemic response. It is necessary to assess not only what has been flooded but also to understand the long-term effects. A transformer that has been “knee-deep in water” may continue to operate for several months only to fail suddenly later – costly and hard to predict.

In the next section we will look closely at how to assess damage after flooding and what to focus on during visual and electrical inspection.

Damage assessment: which components suffer the most

The moment the water level recedes is not the end of the problem. It is only the beginning of the diagnosis. A medium voltage transformer that has been flooded may look intact. But from a service engineer’s perspective, it is like a car accident victim stubbornly claiming they are fine because they can still walk. The problem is that internal injuries are not visible to the naked eye. And in the case of transformers, such injuries can be fatal for the entire installation.

Post-flood diagnostics: from the floor to the bushing

The most common consequences of flooding affect five structural areas of the transformer:

Bushings and MV insulators
Contaminants from rainwater settle on the surface of porcelain or composite bushings, forming a thin conductive layer. The effect is increased leakage currents and a risk of surface discharges. In extreme cases this can lead to tracking and flashovers. Bushings must be thoroughly cleaned, dried and checked for insulation resistance values.

Connections and cable accessories
Moisture entering cable joints, terminations and technical ducts is a silent cause of later short circuits. This is especially true in older installations with non-hermetic MV cables. If water has entered the terminations, replacement or full refurbishment is required.

Enclosure and metallic components
Corrosion progresses rapidly if no anti-corrosion treatment is applied after water contact. Particularly sensitive are:

• grounding and bonding connections

• pins and busbars

• mounting frames

• conservator valves and breathers

Each of these components must be dismantled, cleaned, inspected and preserved.

Cooling system and oil tank
Depending on transformer design, water may enter the tank or cooling channels. Even if the oil looks clean, a microscopic amount of water can reduce the oil breakdown voltage from 60 kV to unacceptable values (below 30 kV). In such a case full filtration or oil replacement is required. According to PN-EN 60422, water content in oil should not exceed 20 mg/kg.

Windings and magnetic core
These are the hardest areas to assess. Moisture inside the winding insulation paper is difficult to remove. Even after surface drying, moisture can remain in the structure for many weeks. This means specialised testing is necessary:

• dielectric dissipation factor (tangent delta) measurements

• dissolved gas analysis (DGA)

• breakdown voltage and insulation resistance measurements

If the transformer was energised at the time of flooding, the windings should also be examined for mechanical displacement.

What tests should be performed after flooding?

After any flooding incident, an integrated technical assessment procedure should be applied. Depending on the level of moisture and exposure time, Energeks recommends the following steps:

• insulation resistance measurement using PI (polarisation index) and DAR (dielectric absorption ratio) methods

• DGA testing

• oil breakdown voltage measurement according to PN-EN 60156

• water content analysis using the Karl Fischer method (PN-EN 60814)

• if in doubt, remove the cover and carry out a visual inspection of the transformer interior

These results will clearly determine whether the transformer is fit for further operation or requires repair or replacement.

What about documentation and responsibility?

It is also important to immediately document the flooding incident. An incident report, photographic evidence and records from environmental condition monitoring systems may be crucial in case of a dispute with the manufacturer or insurer. In most transformer O&M manuals you will find a clear statement that the unit must not be operated in ambient relative humidity exceeding 95 percent or in the presence of standing water. Exceeding these conditions may void the warranty unless the flooding was due to force majeure, in which case it is worth checking the insurance policy.

Moisture, insulation and standards: how water affects MV transformer safety

Water and a transformer are a pair that should never meet. However, when they do, one phenomenon becomes critical that most operators only become aware of during a failure: moisture penetration into insulation systems. In this chapter we dive into the micro world where a drop of water can decide million-dollar losses and a seemingly dry winding can hide a ticking dielectric time bomb.

Water in the transformer: the invisible enemy of dielectrics

The insulation system of a transformer typically consists of a combination of electrical grade paper and oil. Both materials are hygroscopic, meaning they absorb moisture from the surrounding environment. It only takes the relative humidity level in the substation air to exceed 75 percent without being reduced through ventilation or dehumidifiers. If flooding occurs, this level can reach 100 percent.

In real operating conditions, it is enough for the water content in insulation paper to rise from 0.5 percent to 2 percent to:

• reduce winding breakdown voltage by 30 percent

• shorten the expected transformer lifespan by 50 percent

• increase the risk of partial discharges on winding surfaces

• accelerate cellulose aging (depolymerisation)

Why oil does not always protect

Many assume that transformer oil forms a protective barrier preventing moisture ingress. Unfortunately, this is only partially true. Even the best mineral or synthetic oil has a moisture saturation limit. For example, mineral oil reaches saturation at about 40 to 60 mg/kg at 25°C. Beyond that, moisture begins to precipitate as droplets that can settle directly on the windings.

At low temperatures this effect is even more dangerous because moisture condenses faster. In a flooded transformer left unheated for several days, a thin layer of condensed water can appear on winding surfaces. Nominal voltage alone is enough to trigger an arc discharge.

Tangent delta and breakdown voltage: how to measure moisture in insulation

Assessing moisture impact on transformer safety requires precise testing methods. The two most commonly used are:

Dielectric dissipation factor measurement (tangent delta)
This test shows how much the insulation system loses energy as heat, indicating the extent to which its dielectric properties have been degraded by moisture, contamination and aging. For MV transformers, typical tangent delta values for windings should be less than 0.5 percent under reference conditions. An increase above 1.5 percent is an alarm signal.

Oil breakdown voltage measurement
Performed according to PN-EN 60156, this involves placing an oil sample in a test vessel and gradually increasing the voltage until breakdown occurs. Reference values are:

• for mineral oil: minimum 30 kV

• for synthetic oil (e.g. MIDEL): often above 50 kV

Oil after a substation flood often contains micro-particles of water and contaminants that can reduce this value to a critical level within just a few hours of exposure.

What standards and manufacturers say

International standards clearly define acceptable parameter limits for transformers in humid conditions:

• PN-EN 60076-1: transformer should operate in an environment with relative humidity not exceeding 95 percent without condensation

• PN-EN 60422: water content in transformer oil should be between 10 and 30 mg/kg depending on oil type and equipment age

• IEC 60599: dissolved gas analysis (DGA) can indicate the presence of water through increased hydrogen (H2) and carbon monoxide (CO) content

MV transformer manufacturers such as Siemens Energy, Schneider Electric and Efacec state in their O&M manuals that:

• the presence of water in the equipment structure can lead to irreversible damage to the core and windings

• after flooding the transformer should be taken out of service until full diagnostics have been completed

• the warranty may be voided if the user fails to document appropriate action after a water incident

How long does insulation drying take

If the decision is made to save the transformer, drying must begin immediately. Depending on the moisture level and equipment design, this process may take:

• 3 to 7 days for surface-level moisture using mobile heating systems

• up to 21 days for deep moisture in insulation paper requiring vacuum drying chambers

Drying methods include:

• resistive heating with forced ventilation

• cyclic heating and vacuum steam removal

• vacuum drying at around 90 to 110°C

Not all service companies have the equipment for this type of work, so it is worth establishing cooperation in advance with an external diagnostics laboratory.

In the next section we will address the question every operator asks after flooding: is it worth drying the transformer or is it better to replace it?

Drying or replacement: how to make the technical and financial decision

This is one of those moments where rationality must go hand in hand with experience. After a medium voltage transformer substation is flooded, you have to answer a question of great importance for the entire investment: can the transformer be saved, or should it be replaced.

Although emotions may push you to “try drying it”, service practice and diagnostic data often suggest something quite different. In this section we analyse when it is worth attempting to save the unit and when it is better to end its operation and plan for replacement.

When drying makes sense?

Drying can be considered only when:

• Flooding level has not reached critical working zones
  If the water has not reached the windings and only cable ends, external bushings and the housing have been submerged, there is a chance the transformer interior has remained dry.

• Transformer oil shows no signs of degradation
  Breakdown voltage, water content and DGA results are within acceptable limits. For example: breakdown voltage above 45 kV and water content under 20 mg/kg, with no increase in hydrogen or CO in gas analysis.

• The transformer has high technical value and relatively low wear
  If the unit has been in service for less than 10 years, has a confirmed service history and its energy efficiency exceeds Ecodesign Tier 2 requirements, the investor can consider regeneration as a cheaper and faster alternative.

• Technical conditions allow for effective drying
  It is possible to dismantle the transformer and transport it to a vacuum drying facility, and the operator has a spare unit or can provide temporary backup power during the operation.

When replacement is a better option

From the perspective of Energeks and service companies, transformer replacement is recommended when:

• There is internal moisture in the insulation paper
  Even advanced drying methods cannot completely remove moisture from deep layers of cellulose. The transformer may still appear to work correctly for months before suffering sudden insulation breakdown.

• DGA analysis reveals cellulose degradation products
  Increases in CO, CO₂ and furan (2-FAL) in the oil indicate degradation of insulation paper. After flooding, these values often exceed IEC 60599 alarm thresholds, suggesting irreversible damage.

• The unit does not meet current energy efficiency requirements
  A transformer older than 15 years, with efficiency below Ecodesign standards, is not cost-effective in long-term operation. Even if it can be dried, its no-load and load losses will be higher than those of a new unit within a few years.

• Logistical constraints make drying impractical
  For large transformers (e.g. 2.5 MVA and above), dismantling, transporting, drying and reinstalling may cost more than purchasing a new unit. This is especially true if the installation site is hard to access or cannot accommodate temporary disconnection.

• Time is working against the investment
  Drying can take from several days to over two weeks. If the transformer supplies a production line, cold store, PV farm or critical backup system, every hour of downtime generates significant losses. In such cases, purchasing and installing a transformer from the manufacturer’s stock may be more cost-effective than time-consuming regeneration.

Cost comparison: drying vs replacement

When comparing costs, it is important to look beyond the price of the drying service or the purchase of a new transformer. The final decision should take into account not only the service invoice but also the economic impact of downtime, the risk of future failures and the value of energy security.

Drying costs include:

• removal of the transformer from the prefabricated substation

• transport to a service facility with a vacuum drying chamber

• drying process (from 3 to 21 days depending on moisture level)

• oil filtration or replacement

• reinstallation, acceptance testing and commissioning

In practice in 2025, the full regeneration cost of an MV transformer (1–2.5 MVA) typically ranges from 30–50% of the price of a new unit. For hermetic transformers, the cost may be higher due to the more demanding process of accessing the interior.

Replacement costs include:

• purchase of a new transformer (depending on power and efficiency class, starting from several tens of thousands of euros)

• factory transport

• installation and acceptance testing

• possible adaptation of connections and foundations if the new unit differs in size

The advantage of replacement is that you get equipment fully compliant with current standards (e.g. Ecodesign Tier 2), with a full manufacturer’s warranty and virtually zero risk of damage related to previous flooding. The disadvantage is the higher upfront expense and delivery time, which for non-standard models can range from a few weeks to even 6–8 months.

Risk factor – drying a transformer after flooding always carries some uncertainty. Even the best diagnostic laboratory and the most experienced service team cannot guarantee that microscopic traces of moisture in the insulation will not cause problems in a year or two. A new transformer offers much greater predictability.

Downtime cost – this often determines the choice. If the transformer supplies a production line or facility where every hour of downtime costs hundreds of thousands of euros, quick replacement with a unit from stock is usually more profitable than drying that takes two or more weeks.

From experience, regeneration makes the most sense when:

• the transformer is relatively young

• its power and parameters are optimal for the facility

• access to the unit and logistics are straightforward

• downtime can be organised or minimised without major loss

Replacement is recommended when:

• the transformer is older

• it already shows signs of wear and efficiency loss

• it serves an installation critical for operational continuity

In the next section we will move on to practice – what the step-by-step intervention procedure looks like after flooding of a prefabricated transformer substation. This is the moment when engineers take charge and the clock starts ticking.

On this occasion, you may also be interested in our article:

Refurbish or replace? Last chance for your transformer!

How to carry out an intervention step by step

When a prefabricated transformer substation is drowning in water, speed matters, but even more important is the correct sequence of actions. This is not the time for improvisation. Every mistake can make the situation worse, put people at risk, or turn equipment that could have been saved into scrap.

Step 1 – Safety of people first
The first action is to disconnect the substation from the power supply and restrict access to unauthorized persons. Moisture and electricity are a deadly mix. No work can be carried out until there is absolute certainty that the equipment is de-energized.

Step 2 – Document the incident
Photos, video, report. Record the water level, the condition of the substation, traces of water ingress, and visible damage. This data will be needed for diagnostics, insurance claims, and any potential warranty disputes.

Step 3 – Remove the water
Pumps, wet vacuums, drainage. The key is to lower the water level to zero as quickly as possible. The longer it stands, the deeper it penetrates insulation materials and structural components.

Step 4 – Initial visual inspection
Without dismantling the transformer, check the condition of bushings, connections, enclosure, and cooling system. Look for signs of corrosion, flashovers, deposits, and any leaks.

Step 5 – Electrical and oil diagnostics
Measure insulation resistance, oil breakdown voltage, water content with the Karl Fischer method, and perform DGA. These results will help determine whether drying is feasible or replacement should be planned.

Step 6 – Technical decision
Based on measurements and inspections, decide whether to regenerate or replace. It is important to make this decision in consultation with the manufacturer’s service team and the distribution system operator.

Step 7 – Implement the actions
If regeneration is chosen, the transformer goes to a vacuum drying chamber while anti-corrosion work and oil filtration are carried out in parallel. If replacement is chosen, order a new unit and prepare the installation site.

Manufacturer recommendations, manuals and what to look for in service records

Medium voltage transformer manufacturers take a zero-tolerance approach to this issue: water in a transformer substation is a red alert. Not orange, not yellow, but the one that makes you drop everything and run to the switch. Even if your transformer hums like a cat and looks content, after flooding it must be treated like a patient who just took a dive in a muddy pool.

In technical manuals, the wording is as subtle as “do not stick a fork in the socket”:

• maximum allowable relative air humidity 95%, but without condensation because water vapor is also an enemy

• no work in the presence of standing water, even if it is “just” a puddle

• after any contact between transformer and water, full electrical and oil diagnostics without excuses

What to do with a transformer after flooding

• after flooding, disconnect from the grid and set the station keys aside until a qualified team handles it

• diagnostics is not a single multimeter reading — you need insulation resistance measurements, DGA, Karl Fischer oil analysis, and an internal inspection

• drying is only for laboratory conditions, preferably in vacuum chambers — a hair dryer will not do the job

• for hermetic transformers, any regeneration attempt must comply with manufacturer procedures — otherwise the warranty may vanish faster than steam from a kettle

This is where our favorite part comes in — reading the unit’s history like a detective novel.

Service records are your investigation log:

• has elevated moisture in oil been reported before

• has the substation “swum” during local heavy rains in the past

• when was the last oil filtration or tangent delta measurement done

• has anyone reported cooling system repairs or leaks

If the answers suggest your transformer and water have met before, it is a sign the problem is systemic.

It may be time to improve the substation drainage, install proper water diversion, or relocate the unit to a spot where the only water will be in the technician’s coffee cup.

A transformer with a past can still have a bright future

Water in a transformer substation is not a guest you want to see. It comes uninvited, causes damage, and leaves you with the question: what now. But believe us — it does not have to be the end of your MV unit.

Yes, sometimes replacement is the best solution. But often, before you write off the transformer, it is worth checking the facts. Proper post-flood diagnostics give you a clear picture of the situation and allow you to make a decision without unnecessary costs or risks.

At Energeks, we like these moments. Because we know that well-prepared infrastructure can withstand more than a summer storm. And sometimes such a crisis is the beginning of new, better solutions.

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• Contact us

Sources:

1. IEC 60076-1: Power Transformers – Part 1: General

2. CIGRÉ Technical Brochure 445: Guide for Transformer Maintenance

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