The power industry loves paradoxes.

The largest devices in the power system very often depend on the smallest details. A transformer can weigh several tons, have a power rating of several megavolt-amperes, and operate continuously for 30 years. Yet the part that often decides its reliability is only a few centimetres in size.

It is the transformer terminal.

More precisely, the component that connects the medium voltage cable to the transformer bushing.

To someone outside the industry, it looks like an ordinary piece of metal with a few bolts. A detail that few people pay attention to, as long as everything works.

For a power engineer, it is a completely different story. It is one of the most critical points in the entire installation. Right here, high currents meet, mechanical forces from heavy cables act, temperature changes occur, and the very practical question arises: will this connection safely withstand years of operation in real conditions?

Transformer terminals are connection components mounted on the bushings of a medium voltage transformer. They enable safe connection of MV cables, increase the contact surface area of the conductors, and improve the mechanical stability of the connection.

This brings very concrete benefits.

• Lower contact resistance.

• Lower risk of connection overheating.

• Greater predictability of transformer operation over a long service life.

That is why TOGA-type transformer clamps are often used in medium voltage transformers. They are not an aesthetic detail or a marketing add-on. They are a solution born from a very practical need. The need to better manage current, temperature, and connection mechanics in a place that looks unremarkable but in practice is of enormous importance.

And this article is about those issues.

We will show what TOGA-type transformer clamps are and how they are built.

We will look at why conventional cable connections at transformer bushings can be problematic.

We will explain how the clamp construction affects current, temperature, and contact resistance.

We will also examine why grid operators increasingly require stable connection solutions.

We will show, through examples, in which installations transformer clamps become fundamental to the reliability of the entire station.

Reading time: ~11 minutes

TOGA-type transformer clamps – the small component that keeps hundreds of amperes in check

Anyone who has ever stood next an open medium voltage transformer knows that moment.

You look at the massive machine. Several tonnes of steel, a magnetic core, oil, windings. Everything looks calm, heavy, almost majestic.

Then your eyes stop on something the size of a hand.

The clamp.

And this is where real engineering begins.

Because this is not an ordinary piece of metal.

It is a component that must flawlessly carry hundreds of amperes, withstand temperature changes, vibrations, and mechanical forces from cables, while maintaining very low contact resistance for years.

A TOGA-type transformer clamp acts as an adapter between two worlds.

On one side we have the transformer and its bushing – the point where energy exits the tank.

On the other side we have the medium voltage cable, often thick, heavy, and not very flexible.

The clamp introduces an additional conducting element between them, most often made of copper or its alloys. This element increases the contact surface, stabilises the conductor, and distributes mechanical forces over a larger area.

From the point of view of physics, three important things happen:

• The current has a larger surface area through which to flow.

• The metal-to-metal contact pressure is more even.

• The connection is less susceptible to movement and stress.

The effect is simple: less heat, fewer problems, more operational peace.

The photo shows a set of medium voltage transformer clamps mounted on the porcelain bushings of an oil‑immersed transformer. Each clamp serves as the connection point for the MV cables, enabling safe and stable connection of the conductors to the transformer winding. The massive construction of the metal connection blocks increases the contact surface area and allows even current flow, which limits local heating and reduces the risk of energy losses. At the same time, the clamps take up the mechanical loads from the heavy cables, protecting the bushings from stress.

It is in this unremarkable place that all the physics of the transformer’s operation comes together – current, temperature and connection durability – which must remain stable for decades of service.

Photo CC: ENERGEKS 2026

Why conventional cable connections at transformer bushings can be problematic

Cable lug, bolt, tighten – done.

On paper, it works perfectly.

In reality, three very concrete problems appear.

The first is the weight and stiffness of the cable.

Medium voltage cables with large cross-sections are not delicate. They are heavy, springy constructions that very often do not want to go exactly where the design intended. If the cable comes in at an angle or is under tension, it starts acting like a lever and loads the bushing terminal.

The second problem is the contact surface area.

Metal does not make ideal contact with metal. Current flows through microscopic contact points. If there are few such points, current density increases, and along with it, temperature.

And suddenly, a small resistance starts turning into a local heat source.

The third problem is time.

A transformer does not operate in a perfect vacuum. There are vibrations, temperature changes, material expansion and contraction, short-term overloads. If the connection relies on only a single pressure point, micro‑movements can occur over time.

And micro‑movements in power engineering have a bad reputation.

Because they always end with degraded contact.

And this is precisely where the need for better solutions begins.

But even then, the story is not over.

Because once we have improved the mechanics and the electrical connection, another level of challenges appears. One that does not arise solely from current, bolts and cable geometry, but from the fact that the transformer works in the real world, not in a sterile laboratory. In an open station, in an environment full of moisture, dust, temperature variations and all that unwanted biological activity that power engineering knows all too well.

MV bushing covers – what they are and what they really protect against

At first glance, they look a bit like little black hoods.

And that is why they are easy to dismiss. Someone looks at the transformer, sees the bushings, clamps, porcelain, metal, and treats these covers as an extra. A technical trifle that just happens to be there.

Yet in power engineering, such trifles very often do the dirty work that allows everything else to operate calmly.

MV bushing covers are installed to protect the most sensitive area of the transformer connection point. This is where we have live parts, metal components, and relatively small insulation clearances. Exactly the kind of combination we do not want to expose to chance, weather and the creativity of nature.

Most often they are referred to as bird guards. And this is no exaggeration or industry legend. Birds really can cause trouble in a transformer station. All it takes is for one to perch in an unfortunate spot, brush a wing, come close to two points at different potentials, and physics immediately takes over. An arc appears, protection trips, and suddenly we have an outage that nobody planned.

It sounds unremarkable, but this is exactly what some of the most irritating operational problems look like. Not a major failure from a movie. Just a small incident that stops the equipment.

And this is where bushing covers come in.

All black, without any unnecessary fanfare. 😎

Their role is very simple. They make accidental contact with live parts more difficult and reduce the risk that something or someone creates a bridge between potentials.

A bird, a small animal, a branch, a metal object, and sometimes even a tool during service work – all of this can become a problem if it gets too close to where theory ends and medium voltage begins.

A cover does not, of course, make the transformer armoured and indifferent to the whole world. But it very effectively reduces the risk of the simplest, most absurd and, unfortunately, entirely real events. The kind after which one looks at the report and thinks: really? because of that?

Well, yes.

That is why MV bushing covers are no gimmick. They are a practical safeguard that supports the reliability of the transformer from its most mundane side. They do not improve the catalogue glamour of the device. They improve its chances of calm, long-term operation in the real world.

And the real world, as we know, does not always cooperate.

The photo shows medium voltage bushing covers installed on an oil‑immersed transformer. These unassuming black covers protect the critical connection points against accidental contact with live parts and reduce the risk of flashovers caused by birds, small animals and other external factors. They are a simple but very important protective element that supports the safety and operational reliability of the transformer in daily service.

Photo CC: ENERGEKS 2026

From a project perspective, the most sensible approach is when the entire connection system can be selected as a coherent solution, rather than assembled later from random components. Depending on the needs of the investment, these can be transformers equipped with terminal clamps, clamps for a specific type of connection, or MV bushing covers that increase operational safety. Such solutions are available in the Energeks offer; therefore, for a specific project, it is best to simply discuss the configuration and match it to the real operating conditions of the station – and the easiest way to do this is to contact us directly.

How the clamp construction affects current, temperature and contact resistance

Here begins that part of power engineering that looks unremarkable from the outside but is pure physics on the inside.

And as is the case with physics, you can disagree with it, but it will do its job anyway.

At first glance, a transformer clamp is simply a metal component that connects the cable to the transformer. Except that current does not behave as politely as we would like to imagine. It does not flow ideally through the entire contact surface like a beautifully spread sheet of water.

In reality, it flows through those places where metal truly touches metal. And there are far fewer of those contact points than intuition suggests.

That is exactly why the construction of the clamp matters so much.

If the contact surface is larger and the pressure is more evenly distributed, more actual contact points appear. This in turn lowers contact resistance. And lower contact resistance means one thing: less heat where we least want to see it.

Because resistance and temperature are a pair that very quickly show their claws. Joule’s law clearly states: the power dissipated in the connection increases with the square of the current. This means that even a small resistance, under a high operating current, can turn into a local source of heating. First, a few extra degrees appear. Then the material starts to operate hotter, ages faster, and the connection gradually loses its original parameters.

A transformer clamp does three very important things at once.

First, it increases the contact surface area, so the current has more space to flow calmly.

Second, it distributes the contact pressure better, so the connection does not rely on only one small fragment of metal.

Third, it stabilises the whole assembly over time, reducing the risk of micro‑movements that, over the years, can degrade the quality of the contact.

The effect is simple, though extremely valuable from an operational point of view. The current does not concentrate in one tight spot but spreads over a larger area. The temperature of the connection remains lower. And a lower temperature means calmer, more predictable transformer operation.

It can be compared to traffic. The same number of cars squeezed onto a single narrow street quickly creates chaos. When they are given a wide road, everything flows much more calmly. Current behaves similarly. It also likes to have space.

That is why a well‑designed clamp is not a technical detail for the sake of principle. It is a component that helps keep three things in check at once: current, temperature and connection durability. And for a transformer operating for decades, that is truly no small matter.

Why grid operators increasingly require stable connection solutions

Grid operators have one big advantage over the rest of the market.

They do not see a single transformer; they see a whole repeated picture of operation.

For the designer, a transformer is a device selected to meet technical parameters. For the investor, it is an element of a larger puzzle. For the grid operator, it is part of a system that must operate calmly not for one or two years, but for 30, sometimes 40 years.

And it is this perspective that changes everything.

Because when you look at thousands of devices operating in different locations, under different weather conditions and different loads, you very quickly see which solutions age well and which only look good on the day of acceptance.

Every failure, every thermal imaging report, every overheated connection and every case of degraded contact goes into the analysis. At first, it is a single event. Then a second. A third. A tenth. And suddenly it becomes clear that this is no longer a coincidence, but a recurring pattern.

And power engineering does not like recurring problems.

That is why operators are increasingly looking not only at the transformer’s power, loss levels or insulation parameters, but also at how the cable connections are designed. Whether the connection is mechanically stable. Whether the contact surface is sufficient. Whether the arrangement can withstand the stresses from heavy cables, vibrations, temperature changes and years of operation.

Because practice shows something very interesting.

In many cases, the transformer itself, as a machine, works flawlessly. The windings are in good condition, the oil maintains its parameters, the core operates stably. The problem does not begin in the heart of the device.

The problem begins at its interface with the outside world.

Exactly where the cable connects to the transformer.

And that is the moment when a detail ceases to be a detail.

It becomes an element of the entire station’s reliability.

It is from this logic that the operators’ technical requirements arise. The more operational experience, the more attention is directed to the construction of bushings, the method of making cable connections, the stability of clamps and the resistance of the whole connection system to real operating conditions.

Because ultimately, the operator does not buy just the transformer.

The operator buys operational peace.

The photo shows a set of medium voltage transformer connection components: a transformer clamp, a porcelain bushing and a bushing cover that protects the critical point from environmental influences. It is here that current, mechanics and operating conditions meet, which is why each of these components must be consciously selected and work as a coherent system. In practice, this means one thing: reliability begins with a detail, and a well‑designed connection is not an accident but the result of properly selecting all the components that together create a safe and durable connection.

Photo CC: ENERGEKS 2026

Where transformer clamps show whether the project was truly well thought out

There are installations where the transformer has a rather comfortable life. It runs steadily, the cable arrives without too much acrobatics, the load does not do a rollercoaster every day, and everything looks as neat as in the nice drawing from the project.

But there are also places where reality quickly verifies whether the connection at the transformer was designed with intelligence or simply so that it could be bolted together and the matter closed.

And there, transformer clamps cease to be a technical curiosity.

They become a very practical test of the quality of the whole solution.

Take photovoltaic farms.

Everything seems simple.

There is energy production, there is a transformer, there is a power output to the grid. End of story. Except that the transformer in a PV farm operates under conditions that like to test the patience of materials. In the morning the system wakes up, then power rises, then full sun comes, a cloud passes, sun again, ambient temperature does its thing, and along with it the operating conditions of the connections change. This is not the calm, uniform life of an old distribution transformer that does roughly the same thing for half a day. Here current and temperature can change dynamically, and each such cycle means work for the material, the contact pressure and the contact interface.

Add to this the cables. Thick, heavy, serious, with character. Cables that have no intention of lying down gently just because someone drew a nice route on the plan. If the connection at the bushing is weak or too sensitive to stress, the PV farm will show it quickly. And it will do so without sentiment.

Very similar is the case in industrial installations.

Here the emotional stakes rise even higher, because on the other side of the cable there is often a process that really does not like downtime.

Steelworks, foundries, chemical plants, large logistics centres, data centres, plants with production lines operating in continuous mode. In such places, the transformer does not supply an abstract power from a table. It supplies concrete work, concrete machines, concrete money that either flows or stops flowing. If the connection at the transformer starts to heat up, age or lose stability, it is no longer a minor technical defect. It is the beginning of a problem that can affect the entire facility.

That is why, in industry, no sensible person wants the critical point of the system to behave like a moody paving stone after the first winter. The connection has to be stable, predictable and boring in the best possible sense. It simply has to work.

There are also container stations.

The place where theory very quickly meets tight reality.

Here every centimetre matters. Cables enter from below, the switchgear stands close, the transformer has its dimensions, and the person responsible for installation suddenly discovers that the planned geometry was beautiful until the real cable appeared. Not the one from the brochure, but the real one – stiff, heavy and moderately interested in cooperating.

Under such conditions, even a good connection can get out of breath if it does not have adequate stabilisation. The cable rarely comes in perfectly straight, the manoeuvring space is limited, and every unnecessary stress‑inducing twist later affects the terminal and the quality of the contact. This is where a well‑designed clamp shows its true value. Not in a folder, but when you have to manage physics, space and cable weight all at once.

There are also installations that are more environmentally demanding.

For example facilities with large temperature variations, outdoor infrastructure, or locations where the transformer has to operate in an environment of dust, moisture and constant changes of conditions. There, every detail of the connection matters even more, because the connection does not work in a comfortable laboratory but in a world that regularly checks whether everything was done properly.

That is precisely why solutions that increase the contact surface and mechanical stability are not a luxury for hardware aesthetes. They are simply a sensible response to operating conditions.

Because the truth is rather amusing, though for operation it is less amusing.

The transformer can be excellent.

The core solid, the windings well‑made, the oil within spec, everything looks as it should.

And then all that majesty of several tonnes of equipment can be put to the test by a few centimetres of metal at the connection point.

A related topic worth knowing:

Why an MV transformer bushing terminal has one or two holes?

f you want to better understand why even such a small detail as the cable attachment method matters, take a look at our article about the construction of MV bushing terminals. We show there where the difference between one and two mounting holes comes from and how it affects the stability of the connection and its durability over time.

Where to get such a transformer, clamps and those hoods?

And here we come to a very practical question.

Because theory is theory, physics is physics, and temperature curves look beautiful in an article, but in the end someone has to close the topic.

You need to select the transformer.

You need to select the clamps.

You need to plan the bushing covers. You need to make sure that everything fits together not only in the catalogue but also later on the real station, with the real cable, real installation and real operator requirements.

And this is where the difference begins between assembling a system from random components and designing a solution that makes sense as a whole.

You can look at the transformer as a separate product, the clamps as separate hardware, and the covers as yet another add‑on to order. But in power engineering practice, these things do not work separately. They meet at the same place, on the same connection, under the same current, temperature and the same pressure of reality.

That is why the most sensible approach is to think about them together.

In the Energeks offer you can find both low‑loss medium voltage oil‑immersed transformers and cast‑resin dry‑type transformers. You can contact us about selecting transformer clamps and medium voltage bushing covers.

In this way, the entire system can be selected coherently, for a specific project, for the cable routing method, for the installation conditions and for the requirements of a given installation. Without guessing, without improvisation at the end of the investment and without nervously wondering whether all the components will really work together as they should.

And that really matters in power engineering.

Because sometimes the reliability of a transformer is not only decided by what is inside the tank.

What happens on the outside can be just as important. On the bushings, on the clamps, at the interface between the cable and the device. In all those places that do not make a great impression in a long‑distance photo, but which can make a great difference after several years of operation.

If you like technical stories from the power industry told without pomposity but with respect for detail, we also invite you to our LinkedIn.

Referencje:

IEEE Power Transformer Handbook

Pfisterer – Technical documentation (MV connection technology)

Sometimes the most interesting things in the power industry are surprisingly small.

You're standing by a medium voltage transformer, looking at a porcelain bushing, and you see a metal terminal.

On one phase, one hole.

On another, two. Someone asks: is this a mistake? Is something missing?

No. It's a conscious design decision.

In the world of MV transformers, such small details aren't just cosmetic.

They are elements that affect the installation's durability for the next 30 years of operation.

In the place where the cable meets the transformer, enormous currents, electromagnetic forces, and temperature also meet.

And right there, one additional hole can make a huge difference.

Today, we'll take a look at one of the most underestimated elements of an MV transformer.

The bushing terminal and why it sometimes has one hole and sometimes two.

If you design transformer stations, work with MV transformer installation, set up PV farms, or simply want to understand the power industry more deeply, this article will show you something important.

You'll understand why the construction of the bushing terminal isn't an accident.

You'll learn how the number of holes affects currents, temperature, and connection durability.

And why, in power engineering practice, one extra hole can save a transformer from overheating.

In this text, we'll discuss:

• how an MV transformer bushing works and is constructed

• why terminals have one or two mounting holes

• how the number of bolts affects current, temperature, and contact resistance

• what distribution grid operators require

• which installation errors most often lead to connection overheating

It's worth reading, because the only thing truly worth accumulating in life is knowledge!

Reading time: ~12 minutes

How an MV transformer bushing works and is constructed

Before we move on to the mounting holes themselves, it's worth understanding the role of the bushing.

A medium voltage transformer typically operates in the range from about 6 kV to 36 kV. The windings are inside a tank filled with transformer oil. This oil serves two functions. It cools the windings and provides electrical insulation.

The problem appears where the conductor has to exit the tank.

The current must pass from inside the transformer to the outside, to the cable or busbar. At the same time, electrical breakdown through the housing cannot be allowed. The potential difference is enormous.

That's why bushings are used.

A transformer bushing is an insulated element, usually made of porcelain or composite, that conducts the conductor through the transformer tank wall. Inside it, there is a conductive pin connected to the transformer winding.

On the outside of the bushing, there is a terminal.

The metal fitting to which the cable or busbar is connected.

And it's in this fitting that the topic of one or two holes appears.

The bushing terminal, a small element with great responsibility

The bushing terminal is the meeting point of two worlds.

On one side, we have the transformer. A device that can have a power rating from several hundred kilovolt-amperes to several megavolt-amperes.

On the other side, the medium voltage cable or busbar leading the energy further into the grid.

At this single point, currents in the order of hundreds of amperes, and sometimes over a thousand amperes, flow. At the same time, the metallic contacts must maintain very low resistance.

If the contact resistance increases even minimally, the Joule effect appears.

Electrical energy starts turning into heat.

And heat in the power industry is enemy number one.

Why an MV transformer bushing terminal has one mounting hole

The simplest and at the same time very common construction of a medium voltage transformer bushing terminal has one mounting hole.

At first glance, this may seem like a minimalist solution, but in reality, it is a conscious compromise between electrical requirements, mechanical needs, and installation practice.

In such an arrangement, the cable lug is bolted to the terminal with one bolt.

The bolt presses the lug eye against the flat metal surface of the bushing terminal. This creates an electrical connection through which energy from the transformer can flow further to the medium voltage cable.

For many installations, this solution is fully sufficient and has been used in distribution power engineering for decades.

To understand why, it's worth looking at the scale of currents on the medium voltage side.

In distribution transformers with a power of several hundred kilovolt-amperes, the currents on the MV side are relatively small. This follows directly from the relationship between power, voltage, and current.

For example, a 1000 kVA transformer operating in a 15 kV network generates a current of about 38 amperes on the medium voltage side. Even with a 2500 kVA transformer, this value increases to about 96 amperes.

These are values that, from the perspective of electrical connection construction, are relatively small.

A properly made bolted connection with one bolt and an adequate contact surface carries such currents without any problem for many years of operation.

That's precisely why, in transformers with lower power ratings, using a terminal with one mounting hole is a completely rational solution.

One bolt ensures adequate pressure on the contact surfaces.

If the surfaces are clean and the bolt tightening torque is correct, the contact resistance remains very low. This means that no significant energy losses or excessive heating appear at the connection point.

The connection is also simple to install. The installer needs to fit one cable lug and tighten one bolt with the appropriate torque. In the conditions of constructing or modernizing a transformer station, this has practical significance because it shortens installation time and reduces the risk of errors.

A terminal with one hole also has construction advantages.

First of all, it is more compact. In container stations, where space between transformers, switchgear, and cables can be very limited, every centimeter of space matters. A smaller terminal makes it easier to route cables and maintain the required insulation clearances.

The second advantage is the lower weight of the entire bushing assembly.

In distribution transformers, which are often installed in large quantities in the grid, every structural element is optimized for cost and simplicity of production. A simpler terminal means less material and fewer technological operations during manufacturing.

There is also the aspect of compatibility with typical cable lugs used in medium voltage networks. In many cable systems, standard lug eyes are designed specifically for single-bolt connections.

Thanks to this, installation is quick and requires no special intermediate elements.

In power engineering practice, a terminal with one hole is therefore a good solution in several typical situations.

The first is a transformer with relatively low power, where the currents on the medium voltage side are not large. Under such conditions, a single bolted connection provides sufficient contact surface and mechanical stability.

The second situation is cable installations where the transformer is connected directly to an MV cable terminated with a standard cable lug. The cable is flexible and does not generate large mechanical loads on the terminal, so one attachment point is sufficient.

The third situation is transformer stations with limited installation space. A compact terminal makes it easier to route cables and maintain safe distances between phases.

However, physics and operational practice remind us that every solution has its limits.

One bolt means one pressure point.

It also means that the entire contact surface is pressed in one place. If the connection is made imprecisely, the contact surface may be smaller than assumed.

As transformer power increases, currents increase, and with them, the requirements for the quality of the electrical connection increase.

MV transformer bushing terminal with one mounting hole used in standard cable connections in MV transformer stations. The single-bolt construction enables quick and compact connection of the cable lug to the transformer bushing, ensuring adequate contact surface for typical operating currents in distribution transformers. This solution is often used in transformers with lower and medium power ratings, in cable installations, and in container stations where simplicity of assembly and limited connection space are important.

© ENERGEKS 2026

At a certain point, one bolt ceases to be the optimal solution.

That's when the construction with two mounting holes appears, which allows for increased mechanical stability and improved pressure distribution on the contact surface.

And it is this solution we will look at in the next step.

Why an MV transformer bushing has two mounting holes and when it is necessary

A terminal with two holes is a construction used where the electrical and mechanical requirements of the entire system increase. In transformers with higher power ratings and in industrial installations, a simple single-bolt connection ceases to be the optimal solution.

In such an arrangement, the cable lug or copper busbar is bolted to the bushing terminal with two bolts. At first glance, the difference seems small. In reality, it changes a great deal in the behavior of the entire connection during the transformer's many years of operation.

The first benefit concerns mechanical stability.

With one hole, the cable lug is pressed at a single point and can rotate minimally around the bolt axis. This movement isn't large, often fractions of a millimeter, but in power engineering, even such small changes matter. A transformer during operation is not a completely static element. There are magnetic core vibrations, temperature changes causing material expansion, and electromagnetic forces generated by fault currents.

If the connection has only one attachment point, the lug may shift slightly over time. Two mounting holes eliminate this problem. The cable lug becomes locked at two points, which practically prevents rotation and stabilizes the entire connection.

The second benefit is related to contact surface area.

Power connections work best when the contact surface area between metals is as large as possible. In practice, this means the conducting elements must be pressed together with adequate force over as large an area as possible.

Two bolts result in a more even distribution of pressure over the surface of the cable lug or copper busbar. Thanks to this, a larger part of the metal surface participates in conducting current. As a result, local current density decreases and energy losses at the connection point are limited.

The third benefit concerns one of the most important parameters of any electrical connection:

CONTACT RESISTANCE

Contact resistance always arises where two conductors are mechanically joined. Even very smooth metal surfaces actually only touch each other at many microscopic points. The better the pressure and the larger the contact surface, the lower the connection resistance.

If contact resistance increases, the phenomenon of heat generation appears according to Joule's law. Electrical energy starts being converted into heat at the connection point.

To illustrate the scale, it's worth looking at a simple example:

If the connection resistance increases by just 100 microohms, and a current of 600 amperes flows through the joint, the power loss will be about 36 watts at a single point.

On paper, this seems like a small value. However, in reality, this energy is released on a very small metal surface.

This means local heating of the joint to temperatures significantly higher than the ambient temperature. Over time, this can lead to surface oxidation, a further increase in resistance, and accelerated degradation of the connection.

Two bolts help keep contact resistance at a minimum level because they provide stable pressure and a larger effective contact area between metals.

In practice, terminals with two holes appear most often in several situations.

The first is a transformer with higher power.

As power increases, operating currents and requirements for the quality of electrical connections also increase.

The second situation is connections made using copper busbars instead of cables.

Busbars are rigid and heavy, therefore requiring more stable attachment.

The third situation is industrial installations or transformer stations operating in difficult operating conditions.

Vibrations, temperature changes, and high fault currents mean that the mechanical stability of the connection becomes critical.

In such cases, using two mounting holes in the bushing terminal is not a construction luxury.

It is a design element that significantly increases the reliability of the entire transformer over a long operating period.

MV transformer bushing terminal with two mounting holes intended for connections with higher current loads. The double-bolt construction enables stable connection of the cable lug or copper busbar, increases the contact surface area, and limits contact resistance. This solution is most often used in transformers with higher power ratings, in transformer stations with busbar connections, and in installations meeting distribution system operator requirements, where long-term connection stability and minimization of joint heating are crucial.

© ENERGEKS 2026

At Energeks, we take such details seriously. Our MV transformers can be equipped with various bushing termination configurations, tailored to the station design, cable connection method, and grid operator requirements. This applies to both single-hole and double-hole terminals, as well as various types of connection clamps used in power engineering, such as TOGA-type solutions, selected depending on the connection configuration and design standards. If you want to see more examples of such solutions, check out our Energeks transformer offer,

or contact our advisors directly to match the solution precisely to your needs.

How the number of bolts in an MV transformer terminal affects current, temperature, and contact resistance

In power engineering, there is something beautiful in the details.

From the outside, a transformer seems like a massive, calm machine. Several tons of steel, a magnetic core, an oil tank. Meanwhile, its longevity is often determined by elements you can hold in your hand. One of them is the bolted connection at the end of the bushing.

At first glance, the difference between one and two bolts seems like a trivial detail.

In reality, it is a decision that affects three very important physical phenomena.

The flow of current, the temperature of the connection, and contact resistance.

And it is these three parameters that decide whether the connection will work calmly for 30 years or start showing signs of fatigue after a few seasons.

#1 Let's start with current.

The greater the transformer's power, the larger the currents appearing in the system. In distribution transformers with a power of several megavolt-amperes, currents on the medium voltage side can reach hundreds of amperes. Under such conditions, even a small imperfection at the contact point begins to matter.

Current does not flow uniformly through the entire metal surface. In reality, it flows through many microscopic contact points where the metal surfaces actually touch. Each of these points carries part of the total current.

If the contact surface is small, the current density at these points increases.

And when current density increases, temperature also increases.

#2 This leads us to the second phenomenon: Temperature.

In every electrical connection, contact resistance appears. Even in the best-made connections, there is a slight electrical resistance resulting from the microstructure of the metal surface.

Joule's law states that the power dissipated as heat equals the product of resistance and the square of the current. The formula is simple, but its consequences are enormous.

If the current is 500 amperes and the contact resistance is only 50 microohms, about 12.5 watts of heat is dissipated at the connection point. That's not much, as long as the heat is distributed over a large metal surface.

The problem begins when the electrical contact is limited to only a small fragment of the surface. Then this energy concentrates in one place and the temperature starts to rise.

Two bolts act here as a very simple but extremely effective engineering tool. They increase pressure and distribute it over a larger surface. Thanks to this, the number of microscopic contact points between metals increases, and contact resistance decreases.

#3 The third phenomenon is equally interesting: Electrical stability over time.

A bolted connection is not a perfectly rigid structure. During transformer operation, temperature changes occur. Metal expands and contracts. The transformer core generates slight magnetostrictive vibrations. During grid faults, powerful electromagnetic forces appear.

If the connection is held by only one bolt, the cable lug may move minimally. These are very small movements, often on the order of tenths of a millimeter. However, over many years of operation, such micro-movements can gradually degrade contact quality.

Two attachment points stabilize the connection in a completely different way. The cable lug becomes immobilized in two places, and pressure is distributed more evenly. The connection is less susceptible to geometry changes during device operation.

That's why, in transformers with higher power ratings, manufacturers very often use double-bolt terminals as standard. This applies especially to units above several megavolt-amperes, where operating currents are already large enough that every construction detail matters.

A similar situation appears in the case of connections with busbars.

Copper busbars are much heavier and stiffer than power cables. They introduce additional mechanical loads into the system resulting from their own weight and from electromagnetic forces during faults. Two attachment points allow these forces to be distributed and protect the transformer bushing from excessive stress.

Do grid operators require terminals with two bolts in MV transformers?

In many projects, yes. Distribution system operators manage thousands of transformers working in very diverse environmental conditions. Every failure is analyzed, and conclusions later find their way into technical guidelines for new installations. Over the years, in many countries, this has led to the introduction of requirements for double-bolt bushing terminals in specific classes of MV transformers.

Power engineering is a field that learns from experience. Every overheated connection, every thermal imaging inspection report, and every grid event analysis becomes part of the knowledge that later influences design standards.

Therefore, when you look at a transformer bushing terminal and see two bolts instead of one, often behind it is not only the manufacturer's decision but also grid operator requirements and years of practical observation of equipment operation in real power systems.

Transformers such as MarkoEco2 are designed with real distribution grid operation in mind.

This means one thing: they must fit the operator's standards even before they reach the station.

That's why, already at the design stage, we consider the technical requirements of distribution system operators and investor specifications. This also applies to seemingly minor elements such as the configuration of MV bushings or the method of terminating cable connections.

In practice, this means the transformer arrives at the station prepared exactly for the conditions of a given project.

This approach is simple.

The transformer should not force the grid to adapt.

The transformer should be adapted to the grid.

That's why the bushing configurations, the arrangement of single-bolt or double-bolt terminals, and connection solutions in Energeks transformers are designed to seamlessly fit into operator requirements and the practice of working in real power stations.

Top 5 problems causing cable connections at MV transformers to overheat

In the operational practice of medium voltage transformers, very many problems do not start with the transformer itself. They start with the connection. The place where the cable or busbar meets the bushing terminal.

This is one of the most stressed points in the entire system. Large currents flow there, temperature changes occur, and at the same time, it is a mechanical connection dependent on installation quality. That's why minor installation errors can, after a few years, lead to overheating, metal oxidation, and in extreme cases, even failure.

Problem 1: Imprecise preparation of the contact surface.

Metal surfaces, in theory, should fit together perfectly. In practice, on their surface there are oxide layers, dirt, and sometimes even a thin layer of paint or residues from cable lug production. If such surfaces are bolted together without cleaning, electrical contact occurs only at a few microscopic points.

As a result, contact resistance increases, and the connection starts to heat up. That's why, in professional installation, contact surfaces are cleaned, and often also protected with a special contact paste that limits oxidation.

Problem 2: Incorrect bolt tightening torque.

Too little tightening causes insufficient pressure of the cable lug against the terminal. The metal surfaces then do not adhere properly, and contact resistance increases. After some time, connection heating appears.

On the other hand, too much tightening torque can deform the cable lug or damage the terminal thread. In extreme cases, it can also cause cracking of insulating elements in the bushing.

That's why transformer and cable lug manufacturers always specify the recommended bolt tightening torque. In professional installation, torque wrenches are used to achieve the proper pressure.

Problem 3: Using the wrong cable lug.

The lug must be matched both to the cable cross-section and to the construction of the bushing terminal. Too small an eye causes improper lug positioning, while too large an eye limits the contact surface. In both cases, connection resistance increases.

Sometimes a encountered problem is also a situation where the terminal has two mounting holes, but only one bolt is used during installation.

Superficially, the installation works correctly. Current flows, the transformer operates, and the installation passes technical acceptance. However, the connection lacks full mechanical stability. The lug may move minimally during temperature changes or transformer vibrations.

After a few years of operation, oxidation of the contact surface appears and connection temperature rises.

Problem 4: Improper cable routing.

A medium voltage cable has significant mass and specific stiffness. If it is routed at the wrong angle or is under tension, it can exert a constant force on the bushing terminal. Over a long period, this causes micro-movements of the connection and gradual deterioration of electrical contact.

That's why, in professional installations, cable supports and appropriate cable bending radii are used to eliminate stresses acting on the transformer terminal.

Problem 5: Lack of periodic connection inspection.

A transformer is designed for decades of operation. However, bolted connections can change over time under the influence of temperature, vibrations, and material aging. That's why, in many industrial installations, periodic inspections are performed using thermal imaging cameras.

Thermal imaging allows very quick detection of a point where the temperature is higher than in the other phases. Often this is the first sign that contact resistance is starting to increase and the connection requires inspection.

In power engineering, very often it is the small details that determine installation reliability. The cable connection at the transformer bushing is one of those places where installation quality has a direct impact on the operational safety of the entire station.

Small detail, big physics

The story of one or two holes in a bushing terminal says more about power engineering than might seem.

Because this is not an industry of spectacular gestures. It's an industry of decisions that at first glance look like trivial details, but in practice work for decades.

An MV transformer doesn't get a second chance every few years. It stands and works. Day after day. In winter, in summer, under load, after faults, in silence and without attention. For 30, sometimes 40 years.

And that's precisely why details like the method of attaching a cable lug matter. Because they decide whether everything will work as it should, without unnecessary losses, without overheating, without surprises.

So when you look at a bushing terminal with one or two holes, you are looking at the result of an entire industry's experience. Physics, tests, errors, and conclusions that someone once had to draw.

At Energeks, we like this level of thinking.

Because we know that a well-designed transformer is not just parameters on paper, but a fit to the reality of operation.

That's why our MV transformers can be equipped with various bushing termination configurations, tailored to the station design, cable connection method, and grid operator requirements.

If you want to see how different solutions look in practice, check out our offer.

And if you appreciate a technical perspective on power engineering without unnecessary noise, we also invite you to our LinkedIn, where we regularly share knowledge from projects and work with transformers.

REFRENCES:

IEEE Power Transformer Handbook, IEEE Press
Electric Power Transformer Engineering, James H. Harlow, CRC Press

It can pretend for years that everything is under control.

And then, in a very short time, it reminds you that the hard sciences also have a hard memory 🫣

A medium voltage transformer is a master of patience.

It can endure more than the table suggests. Work longer than someone planned.

Survive decisions that were borderline but were supposed to work out.

And that's precisely why it can be treacherous.

It doesn't break when things are really bad.

It breaks when, for a long time, things were almost good.

When the power margin was slowly dwindling, and no one noticed the moment when physics started charging interest.

This text isn't about failures.

It's about how to maintain control before the last 20% of margin disappears faster than you expect.

We see it more and more often.

Grids are working more intensively.

Load profiles are sharper.

Renewable sources, energy storage, chargers, inverters introduce dynamics into the system that older design assumptions simply didn't foresee.

The trusty old transformer copes and keeps working.

Only it's operating in a different world than the one it was selected for.

And that's not an unsolvable problem; it's a phenomenon to be understood.

This article is for those who prefer to know sooner rather than replace later.

For people who treat a transformer not like a grey box, but as an element of an energy strategy.

If you read on, you'll see how to recognize the moment when overload stops being flexible, why short episodes have long consequences, and how to make decisions that genuinely extend a transformer's life instead of heroically shortening it.

We'll look at why transformer aging accelerates non-linearly.

We'll explain how much operating outside rated parameters really costs.

We'll debunk the myth of momentary overload and show why many failures are the logical consequence of earlier choices, not equipment malice.

It'll be interesting, so stay until the end, where a small bonus also awaits you🥰.

Reading time: about 9 minutes

When overload stops being flexible

Every medium voltage transformer has a certain tolerance.

The designer isn't naive.

They know life won't be a catalog table.

They know load will spike temporarily, that summer will be hotter than the standard average, that someone will add another charger or inverter.

And for a long time, everything indeed works.

The problem begins when overload stops being flexible and starts being structural. The difference is subtle.

Flexible overload is an episode.

A dozen or so minutes of higher current, after which the transformer returns to thermal equilibrium. Structural overload is a situation where the operating point permanently shifts closer to the thermal limit.

The key indicator isn't the power percentage itself, but the hot-spot temperature of the winding.

IEC 60076 and IEEE guidelines clearly show that the aging rate of cellulose insulation increases exponentially with temperature.

An increase of 6 to 8 °C can double the aging rate.

This isn't a linear relationship. It's a chemical reaction accelerated by temperature.

In practice, the critical moment is recognized by several signals: shortened cooling time after a load peak, more frequent fan activation, an increase in no-load and load losses measured indirectly through active and reactive power analysis.

Add to this the analysis of gases dissolved in the oil, which shows whether the insulation is starting to react.

A transformer doesn't shout. It whispers in the data.

If we don't look at load profiles on an hourly and seasonal basis, it's easy to miss the moment when 80% of rated power stops being safe because the operational context has changed.

And today, context changes faster than ever.

Why short episodes have long consequences

Many investors think like this:

It was only 30 minutes.

Nothing happened.

From an operational point of view, they're right.

From the point of view of insulation chemistry, not necessarily.

Paper insulation in a transformer ages due to cellulose depolymerization.

Every temperature increase accelerates this process. A short episode of high load raises the hot-spot temperature. The cellulose chain molecules shorten.

We cannot reverse this process.

If there are a few such episodes a year, the impact may be negligible.

If they repeat daily during peak hours, we start building a permanent loss of dielectric strength. The transformer still works, but its safety margin decreases.

It's a bit like metabolic debt in the body. One sleepless night doesn't cause a revolution. Hundreds of such nights change biological parameters.

In systems with a high share of RES, high-load episodes often combine with higher-order harmonics generated by inverters.

Harmonics cause additional losses in the core and windings.

Losses mean heat. Heat means accelerated aging.

A short episode can mean a few percent of annual insulation life loss.

No one will see this at the moment of the event. We'll see it a few years later in the form of a failure that seems sudden.

Physics doesn't forget. It accumulates.

And at a certain point, a very specific question arises: since the transformer is still working, is it better to modernize it, regenerate it, or plan for replacement?

This isn't a zero-one decision.

Factors include oil analysis results, the degree of insulation polymerization, energy efficiency, compliance with Ecodesign Tier 2 requirements, and the real costs of losses.

Sometimes renovation makes sense and allows regaining several years of stable operation.

Sometimes economics and safety clearly indicate that it's better to replace the unit before a failure does it for us.

If you're facing such a dilemma, we discuss this topic more broadly in the article:

Is it worth investing in a new transformer when the old one still works?

It's a good complement to this conversation, especially when the decision concerns the next 20 years of installation operation, not just the upcoming season.

How to make decisions that genuinely extend a transformer's life

The most important decision is moving away from catalog thinking.

Rated power isn't an absolute.

It's a reference point for specific conditions.

If a transformer operates in an environment with higher ambient temperature, variable load profiles, and an increased harmonic level, this must be accounted for in the life model.

In practice, this means temperature monitoring, power quality analysis, and periodic oil diagnostics.

Decision number two is planning reserve with the future in mind, not just based on construction loads.

If we know that within three years, energy storage and high-power DC chargers will be added, it's worth planning for a transformer with a higher thermal class or greater power.

Decision number three is peak management.

EMS systems and energy storage control can realistically flatten the load profile.

Sometimes investing in intelligent control is cheaper than premature transformer replacement.

Extending a transformer's life isn't heroism.

It's consistent data management.

An MV transformer can work for 30 or even 40 years.

Provided we don't treat it like an unlimited resource.

Why aging accelerates non-linearly

Here we get to the heart of the matter.

The aging of paper-oil insulation is described by the Arrhenius law.

Simply put, it states that the rate of a chemical reaction increases exponentially with temperature.

If at 98 °C a transformer uses one unit of life per year, then at 110 °C it may use two or three. At 120 °C, the rate of increase is even greater.

The last 20% of the power margin often means operating in a temperature range where aging acceleration is dramatic compared to the nominal range.

That's why we talk about non-linearity.

In the first 60% of load, changes are gentle.

Near the limit, they become abrupt.

That's precisely why a transformer can work without problems for years, and then, in a short time, enter a phase of rapid degradation.

This isn't a whim of the device. It's a consequence of materials physics.

And it's at this moment that the real dilemma appears.

Should we still invest in renovation, drying, oil replacement, or is this already the stage where insulation parameters directly state that the construction is approaching the end of its technical life?

If the topic concerns units with 30, 40 years of operation, it's worth looking more broadly at the technical and economic aspects of such a decision.

We discuss them in detail in the article:

Refurbish or replace? Your transformer's last chance!

It's a natural complement to this part of the conversation, especially when you want to understand where cost-effective regeneration ends and responsible replacement planning begins.

How much does operating outside rated parameters really cost

The cost isn't limited to the energy bill.

First, we shorten the device's technical life.

If the designed service life is 30 years, and we realistically achieve 22, then the missing 8 years have their own capital value.

On the scale of a PV farm or industrial plant, this means millions of PLN shifted in time.

Second, the risk of unplanned downtime increases.

And the cost of downtime often exceeds the cost of the transformer itself.

Third, power quality parameters deteriorate.

Higher temperatures mean higher losses, higher losses mean lower efficiency.

Differences of one or two percent in large installations translate into significant annual amounts.

Operating outside rated parameters doesn't have to be a mistake.

It can be a conscious decision. There's one condition. We must know its price.

The myth of momentary overload

We hear this often. The transformer is oversized; momentary 110% won't hurt it.

It will hurt it or not, depending on the context.

If momentary overload occurs at low ambient temperature and the transformer has cooling reserve, the impact may be minimal. However, if it's 110% on a hot day, with an already elevated harmonic level, the effects are completely different.

The myth lies in looking at the power percentage, not at the thermal and electrical conditions.

A transformer doesn't feel %%. It feels temperature and electric field.

Momentariness isn't a time category. It's an energy category.

Why failures are the logical consequence of earlier choices

A failure is rarely a single event.

It's the result of a sequence of decisions.

Power selection on the edge. Failure to update load analysis after installation expansion.

Abandoning monitoring because nothing happened for years.

Each of these decisions is rational at the time it's made.

The problem arises when the system changes, but the assumptions remain old.

A transformer doesn't know the budget. It only knows the laws of physics.

That's why we say many failures are the logical consequence of earlier choices.

That's good news. Since they're logical, they can be prevented.

The transformer as part of a strategy, not a cost

In many projects, an MV transformer appears in the budget as a purchase item.

Power, voltage, delivery date, price.

Ordered, installed, connected.

It's supposed to work.

But the moment we start looking at it as a strategic asset, the conversation changes tone.

A transformer isn't just a device for changing voltage levels.

It's the energy node of the entire installation.

Every decision about power expansion, every new DC charger, every additional inverter, every energy storage unit passes through it.

If it's minimally selected, the company's entire energy strategy starts being constrained by one grey box in the station.

Life cycle planning means more than just writing "30 years" into the documentation.

It means analyzing how the load profile will change, what the power growth scenarios are, how the structure of loads will change. Today, a production plant has a specific consumption.

In 3 years, it might have a line that's 40% more energy-intensive.

If the transformer has no room for such a change, investment in development starts with infrastructure replacement.

TCO analysis, or total cost of ownership, often brings surprising conclusions.

A cheaper transformer with higher losses generates greater energy costs over 20 years than the difference in purchase price. A unit non-optimally selected for harmonics may operate with reduced efficiency and age faster. In the long-term balance, savings at the start turn out to be an illusion.

When energy storage enters the system, the transformer ceases to be a passive element.

It becomes part of the power control system.

You can smooth peaks, limit overloads, consciously manage reactive power.

That's specific kilowatts less during critical hours and specific degrees Celsius less in the winding.

In this perspective, the last 20% of power ceases to be a free reserve.

It's a zone we treat as an area of high responsibility.

We enter it when we know why, for how long, and with what consequences.

Not because it "still fits somehow."

This isn't a conservative approach. It's a mature approach.

BONUS: Answers to the most frequently asked questions on the topic

Does a transformer always have to operate below 80% power?

No. The key factors are temperature, load profile, and cooling conditions.

In many cases, 90% is safe if it's well calculated and monitored.

Does oil change extend a transformer's life?

It can help if the oil has degraded, but it won't reverse paper aging.

That's why diagnostics must be comprehensive.

Is it worth installing online sensors in older units?

In many cases, yes.

The cost of monitoring is small compared to the value of information about temperature and gases in the oil.

Does oversizing always pay off?

Not always.

Sometimes a better solution is intelligent load management or support from an energy storage system.

Summary and invitation

Transformer aging isn't linear.

The last 20% of power often tempts, because it looks like a safe reserve.

In practice, that's precisely where the technical cost grows fastest.

Fortunately, we aren't helpless. Data from monitoring, temperature and power quality analysis, sensible power planning, and updating design assumptions allow us to keep the situation under control. Without drama. Without fighting fires at the last minute.

An MV transformer can be just another device in the station. It can also be a consciously managed asset that works stably for decades. The difference lies in decisions made earlier, not in the failure itself.

As Energeks, we support investors, designers, and operators in the selection and modernization of MV units based on real work profiles.

Our offer includes oil transformers and resin-insulated transformers, all in Ecodesign Tier 2 standard, designed for high efficiency and a long life cycle. We also deliver complete transformer stations and solutions integrated with energy storage.

If the topic concerns your installation, it's worth talking sooner rather than later.

On our website and LinkedIn, we share knowledge from projects and implementations, showing how to approach a transformer not emotionally, but strategically.

References:

IEEE Std C57.91 Guide for Loading Mineral Oil Immersed Transformers
A classic document that details the relationship between temperature, load, and accelerated insulation aging. You'll find thermal models, life loss calculations, and a practical approach to short-term and long-term overloads.

CIGRE Technical Brochure 761 – Condition Assessment of Power Transformers via https://www.scribd.com/
A very concrete study on assessing the technical condition of transformers, interpreting oil tests, diagnostics, and making decisions about modernization or replacement based on data, not intuition.

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

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

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

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

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

But everything was brand new! 🤬

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

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

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

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

Reading time: ~10 min

Why transformer accessories determine trouble-free operation

A transformer ages slowly and very consistently.

Insulation loses its properties with temperature.

Oil degrades faster if it's not monitored.

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

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

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

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

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

Each one addresses real problems that genuinely occur.

Insulators and connections, or the first line of electrical peace

It always starts with the connection.

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

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

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

Cable, busbar, transformer termination.

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

The electrical order and the mechanical order.

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

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

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

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

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

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

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

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

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

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

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

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

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

Oil-air bushings are a separate category.

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

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

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

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

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

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

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

Tapered bushings, or safe passage through the housing

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

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

the passage of voltage through the housing.

Leaks, micro-cracks, improper installation.

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

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

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

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

Oil and winding temperature, or what really ages a transformer

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

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

It wears out because it's too hot.

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

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

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

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

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

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

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

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

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

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

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

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

PT100 sensors for transformers have become standard for a reason.

They are stable, precise, and predictable.

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

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

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

A transformer communicates with its surroundings constantly.

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

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

These phenomena occur regardless of whether anyone is observing them.

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

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

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

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

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

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

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

Temperature allows for assessing the transformer's thermal load.

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

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

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

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

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

The reason is simple and very pragmatic.

Installation downtime costs more than a monitoring system.

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

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

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

A transformer vibrates.

Always.

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

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

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

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

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

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

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

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

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

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

Ventilation and cooling, or when nameplate power meets summer

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

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

And then summer comes.

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

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

And here begins the real verification of nameplate power.

Transformer overheating rarely starts dramatically.

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

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

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

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

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

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

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

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

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

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

Accessories as a system, not an add-on

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

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

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

Insulators ensure energy has a stable path.

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

Sensors and monitoring provide information before a problem appears.

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

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

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

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

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

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

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

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

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

Sources:

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

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

Winter is when everything comes to light.

For most of the year, the installation works correctly.

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

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

Flickering lights. Notifications about voltage being too low.

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

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

This isn't a story about faulty technology.

It's also not a tale of user errors.

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

Heat pumps have changed the network load profile.

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

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

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

This article was created to organize these phenomena.

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

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

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

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

Reading time: approximately 13 minutes

How heat pumps really stress the grid in winter

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

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

In winter, the situation changes radically.

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

One key word here is: momentary power.

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

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

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

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

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

Everyone heats at the same time.

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

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

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

Why?

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

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

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

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

This isn't a failure.

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

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

What really happens inside an oil transformer during a frost

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

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

The difference begins on the inside.

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

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

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

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

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

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

The greater the current, the greater the voltage drop.

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

Heat pumps are particularly sensitive to this.

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

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

A further domino effect occurs.

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

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

This is not an overload in the classical sense.

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

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

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

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

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

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

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

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

Why the classical power rating selection method stops working

For years, everything was logical and predictable.

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

Because the loads were passive and spread out over time.

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

Heat pumps have changed this order.

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

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

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

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

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

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

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

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

The first warning signs appear early.

They are not failures or protection tripping.

They are subtle symptoms that are easy to ignore.

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

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

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

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

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

What to check before a real problem begins

In winter, the network doesn't forgive illusions.

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

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

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

A seasonal picture is needed.

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

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

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

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

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

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

A frequently overlooked element is voltage regulation.

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

This brings us to an important distinction.

Not every winter problem means the transformer is too small.

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

A good diagnosis allows you to choose the right tool.

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

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

Renovate or replace? The last chance for your transformer!

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

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

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

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

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

Heat pumps respond to temperature. Simultaneously. Without negotiation.

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

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

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

Operation also requires a new approach.

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

These are signals that appear long before a crisis.

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

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

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

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

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

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

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

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

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

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

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

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

Sources:

International Energy Agency (IEA)

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

ENTSO E

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

2025. The year theory stopped being enough

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

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

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

Reality started to test assumptions.

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

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

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

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

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

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

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

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

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

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

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

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

Reading time: ~11 minutes

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

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

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

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

On paper, everything looked simple.

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

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

In many projects, Tier 2 exposed old design habits.

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

The problem wasn't the regulation itself.

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

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

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

Added to this was the issue of availability.

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

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

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

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

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

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

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

Nameplate Rating Versus Real-World Usage

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

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

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

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

Oversizing in 2025 ceased to be neutral.

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

On the other hand, problems with undersizing emerged.

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

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

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

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

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

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

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

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

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

And that is a change that makes a huge difference.

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

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

The year 2025 ended this comfortable stage.

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

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

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

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

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

This changed the dynamic of conversations.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The first flashpoint turned out to be dimensions.

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

The second problem was weight.

Transporting a transformer stopped being a simple logistical operation.

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

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

The third aspect is servicing and accessibility after commissioning.

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

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

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

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

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

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

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

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

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

And it's likely here to stay.

Documentation, repeatability, and peace of mind during acceptance

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

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

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

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

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

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

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

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

Operational documents also began to carry increasing weight.

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

This trend is not accidental.

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

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

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

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

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

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

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

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

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

Not because they are the most impressive.

Not because "you have to."

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

• Meeting Ecodesign Tier 2 requirements without interpretive gray areas.

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

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

• Documentation that doesn't require explanations during acceptance.

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

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

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

For the conversations on investment sites.

For the tough questions in projects.

For the exchange of observations and knowledge.

For the feedback that sometimes stings but always teaches.

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

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

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

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

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

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

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

Sources:

Cover Photo: Juan Soler Campello/pexels

International Energy Agency (IEA) - Energy Efficiency 2025

McKinsey Global Institute - Reinventing construction through a productivity revolution

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

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

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

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

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

What exactly lies beneath the steel cover?

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

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

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

After reading, you will know:

• What key components make up an oil transformer.

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

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

• Which design flaws most commonly shorten its lifespan.

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

Reading time: approx. 7 minutes

The magnetic core – the iron heart of the transformer

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

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

What is a transformer core made of?

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

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

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

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

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

Two main types of cores are used in oil transformers:

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

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

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

What does core assembly look like in practice?

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

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

What is the significance of grain orientation?

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

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

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

The result? Lower losses and quieter operation.

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

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

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

Oil meets iron – how the core cooperates with cooling

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

Why does all of this matter?

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

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

• Noise and vibration levels.

• Operating temperature and the durability of the insulation.

• And consequently – the transformer's lifespan.

As assembly floor engineers like to say:

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

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

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

Windings that transform voltage into usable energy

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

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

An oil transformer has two main types of windings.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Insulating oil, the invisible guardian of temperature

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

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

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

Transformer oil serves two main roles.

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

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

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

Two main categories of oil dominate the market.

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

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

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

The operating temperature of a transformer is a complex puzzle.

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

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

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

Every chemical micro-flaw leaves a trace in it.

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

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

Transformer oil also works as a shock absorber.

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

Why does all this matter?

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

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

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

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

Transformer oil leaks – do not ignore these signals

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• The quality of the welds.

• The tightness of the gaskets.

• The mechanical stability of the radiators.

• The condition of the anti-corrosion coating.

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

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

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

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

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

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

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

And compromises in transformers take revenge slowly but surely.

The most common sin is improper winding layout.

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

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

The second classic design error is poor cooling system geometry.

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

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

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

The third problem is tank construction.

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

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

Another mistake is cutting corners on the sealing system.

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

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

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

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

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

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

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

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

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

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

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

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

1. The first is ignoring moisture.

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

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

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

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

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

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

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

5. The fifth error is unsuitable environmental conditions.

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

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

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

What remains when we close the transformer's cover

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

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

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

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

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

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

Sources:

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

Cable Comminuty.com

Power Tech Systems

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

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

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

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

That is exactly what we are doing today.

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

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

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

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

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

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

Agenda:

• Design and digital visualization

• CRGO lamination core and step lap configuration

• Windings. Conductor selection and geometry

• Insulation system. Kraft paper and DDP

• Active part assembly and preparation for testing

• Tank. Corrugated or with radiators

• Surface treatment and anti-corrosion protection

• Drying of the active part and moisture control

• Vacuum oil filling and heat cycling

• Routine tests and readiness for shipment

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

Design and digital visualization

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

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

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

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

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

The designer must reconcile several worlds:

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

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

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

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

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

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

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

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

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

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

CRGO lamination core and step-lap configuration

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

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

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

CRGO – Cold Rolled Grain Oriented Steel.

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

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

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

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

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

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

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

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

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

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

This is why the following are so critical:

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

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

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

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

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

An interesting fact

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

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

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

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

Windings. Conductor selection and geometry

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

First, the choice of metal. Copper or aluminium?

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

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

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

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

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

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

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

Insulation secrets – cellulose and DDP in action

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

Insider jokes

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

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

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

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

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

Insulation system. Kraft paper and DDP

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

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

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

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

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

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

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

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

A tidbit from high-voltage laboratories

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

Active part assembly and preparation for testing

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

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

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

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

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

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

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

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

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

Stability, tightness, and cleanliness

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

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

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

• Winding resistance measurement,

• Vector group verification,

• Ratio measurement,

• Inter-system insulation check.

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

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

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

A short digression on vibrations and patience

In experienced assembly teams, a rule prevails:

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

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

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

Where theory meets practice

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

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

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

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

Tank. Corrugated or with radiators

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

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

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

Corrugated tank – the master of compact solutions

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

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

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

Tank with radiators – industrial-grade classic

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

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

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

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

From steel to tightness – the engineering of precision welding

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

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

The sustainable direction – recycling and hot-dip galvanizing

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

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

Vacuum oil filling and heat cycling

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

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

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

Oil under vacuum – the physics of pure calm

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

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

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

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

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

Heat cycling – a spa for the windings

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

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

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

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

Oil quality and purity control

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

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

Learn more:

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

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

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

When oil becomes a witness to history

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

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

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

Routine tests and readiness for shipment

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

Routine tests – or "mandatory exams of everyday life"

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

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

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

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

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

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

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

Additional tests for demanding applications

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

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

• Measurement of magnetic circuit losses at different temperatures.

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

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

Engineering Aesthetics: Preparation for Shipment

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

This includes:

• Draining excess oil and filling hermetic tanks with nitrogen.

• Sealing all openings and securing transport fittings.

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

• A final visual inspection of coatings and welds.

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

Documentation – The Transformer's DNA

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

• Technical and operational documentation.

• Measurement and test reports.

• Oil test results.

• Material certificates for components used.

• Certificates for weld quality and anti-corrosion coatings.

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

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

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

Conclusion

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

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

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

Discover Energeks’ middle voltage transformers solutions, including:

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

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

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

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

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

Let's do it together.

References:

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

2. CIGRÉ Technical Brochures

3. MDPI Energies - MDPI researches

4. Siemens Energy - Power Engineering Guide

Autumn-winter morning.

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

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

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

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

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

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

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

The decision is not about conservator versus modernity.

It is about context versus coincidence.

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

Who is this article for?

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

Agenda

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

• Transformer with an oil conservator: when to use it

• Transformer with an oil conservator: when it is necessary

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

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

Reading time: approximately 10 minutes

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

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

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

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

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

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

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

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

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

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

But its function doesn’t end with breathing.

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

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

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

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

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

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

A conservator is not always necessary

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

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

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

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

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

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

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

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

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

They simply have different temperaments.

One is lik

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

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

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

What is your actual operating environment?

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

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

• Where a transformer with a conservator truly makes sense.

• Where a sealed design is the more rational choice.

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

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

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

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

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

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

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

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

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

Environments where a conservator makes sense

So, when is the environment favorable for a conservator?

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

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

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

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

Where a conservator is not needed

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

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

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

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

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

So when does a conservator come back into play?

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

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

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

The third aspect is gas protection—the Buchholz relay.

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

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

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

In short then:

When to choose a transformer with a conservator?

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

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

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

And when to opt for a sealed transformer?

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

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

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

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

3. A conservator for a transformer when is it necessary

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

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

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

3.1 Requirements of distribution system operators (DSOs)

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

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

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

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

3.2 When the environment demands flexibility

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

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

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

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

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

3.3 Longevity and parameter stability

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

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

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

3.4 When simplicity is not enough

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

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

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

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

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

3.5 Summary

A transformer with a conservator is necessary when:

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

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

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

• The substation lacks air conditioning or active cooling systems.

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

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

4. Oil transformer selection, service and good practices

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

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

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

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

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

4.1 Maintaining the transformer's breathing

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

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

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

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

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

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

4.2 Monitoring oil level and quality

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

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

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

• Dielectric strength

• Water content

• Acid number

• Dissolved gas content (DGA)

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

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

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

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

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

4.3 Selecting a conservator for the environment and load

Not all conservators are the same.

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

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

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

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

4.4 Good operational practices

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

In practice, this means:

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

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

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

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

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

4.5 Grid stability and smart maintenance

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The differences in maintaining these transformers are significant

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

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

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

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

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

Both solutions are excellent, each within its intended environment.

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

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

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

Conclusions

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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