There is a moment like that.

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

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

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

It is only just beginning its work.

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

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

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

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

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

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

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

reading time ~10 min

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

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

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

A transformer pays you back for everything in failures.

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

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

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

Ventilation is another topic that often loses to reality.

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

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

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

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

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

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

Grounding is a separate story

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

Everyone has heard that.

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

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

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

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

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

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

At first, everything is by the book.

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

The first signal is often sound.

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

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

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

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

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

Oil leaks in transformers – do not ignore these signals

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

Operation is also about loading.

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

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

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

Maintenance has terrible PR.

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

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

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

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

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

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

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

Oil testing is the best example here.

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

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

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

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

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

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

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

Power transformer installation – a comprehensive checklist

The most important thing is the approach

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

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

An oil transformer does not spring surprises.

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

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

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

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

Don't stop at the start

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

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

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

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

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

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

You can find the current transformer offering here.

Thank you for taking the time to read this text.

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

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

At one of the photovoltaic farms an investor asked with a slight smile:

“Why does this transformer say 15.75/0.42 kV when our grid is 15 kV? Is that a design error?”

This question comes up surprisingly often. And while it sounds simple, it goes straight to the heart of what designers and contractors in the medium-voltage world grapple with every day: the transformer voltage ratio.

Because the ratio is not just about “what goes in and what comes out.”

It is a mathematical promise that voltage and current will behave exactly as required by the grid, the inverter, and the Distribution System Operator.

In this article, we will explain what a transformer voltage ratio is, where common ratios come from, how to interpret them, and what they really mean for the efficiency and safety of your installation.

You will also learn why those “odd numbers” on the transformer nameplate are sometimes exactly what saves your investment from overvoltage issues and grid non-compliance.

Estimated reading time: approx. 8 minutes.

What is a transformer voltage ratio and how does it work in a real grid?

The voltage ratio of a transformer is one of those terms that sounds harmless—almost like the proportion of ingredients in a pancake recipe. And yet, in practice, it is a key parameter that determines whether the transformer will function properly or simply become an expensive piece of decoration in the substation.

By definition: what exactly is it?

The transformer voltage ratio defines the relationship between the voltage on the primary (input) side and the voltage on the secondary (output) side.

If we have a voltage ratio of 15,000 V / 400 V, it means the transformer steps the voltage down from 15 kV to a safe level of 400 V—suitable for end-use devices such as inverters, servers, machines, pumps, or even a humble electric kettle in a production hall.

According to the law of conservation of power (neglecting losses), the transformer must "balance" voltage and current. If voltage goes down, current goes up—and vice versa.

How does it work in a real grid—not just in the textbooks?

In theory, it’s simple: the grid supplies 15 kV, the transformer steps it down to 0.4 kV, and that’s it. But in reality, things look a bit different. The grid doesn’t hold the voltage steady.

On a hot day, with a million air conditioners running, voltage drops. At night, when barely anything is drawing power, voltage rises. Add solar panels pushing excess energy back into the grid on sunny days, and… you get a rollercoaster.

This is why transformer designers have to account for these fluctuations.

A 15/0.4 kV ratio might work in theory—but what if the grid voltage rises to 15.4 kV? On the low-voltage side, that becomes 411 V instead of 400 V—and that could exceed the tolerance of the inverters.

This is where the magic of engineering comes in: tap changers.

The transformer is equipped with the ability to adjust its voltage ratio by ±2×2.5%—meaning it can raise or lower the input voltage without physically changing the windings.

It works like a thermostat: the transformer adapts to real operating conditions.

A good voltage ratio is one that:

• fits the actual voltage at the point of connection (not just on paper),

• provides the proper voltage for inverters and loads,

• includes a margin for regulation,

• allows appropriate selection of protection and switching devices without oversizing.

And that is exactly why transformer nameplates often show values like 15.75/0.42 kV instead of the “neat” 15/0.4 kV.

Because the world isn’t uniform, and the transformer needs to understand that.

Where do typical voltage ratios come from — a story of compromise, grid maps, and engineering flexibility

Imagine an electrical map of Europe, but not with mountains and rivers, but with voltage levels:

10 kV, 15 kV, 20 kV, 30 kV, 13.2 kV…

Each country has built its own system, its own habits, and its own standards—often due to historical, technological, and logistical reasons.

On this map, the transformer is like a multilingual translator who must speak the dialect of a given country, not just in words (voltage), but in tone (current, regulation, tolerances).

Typical voltage ratios—such as 10 kV / 0.69 kV, 15.75 kV / 0.42 kV, 20 kV / 0.4 kV are the result of three forces that every transformer manufacturer must balance:

• Local medium voltage (MV) grid levels.
  In Poland, the most common voltages are 15 kV and 20 kV.
  In Germany, you will find 10 kV, 15 kV, and 30 kV.
  In Spain, 13.2 kV and 21 kV are often used.
  The transformer must “fit into” this local grid reality, which is why part of the voltage ratio comes directly from the region’s MV level.

• Output voltage—what the equipment needs.
  These are typically around 0.4 kV, 0.42 kV, or 0.69 kV—depending on the installation design, device requirements, and local low-voltage standards.
  The output voltage must match what PV inverters or energy storage systems need to operate efficiently.

• Voltage buffer, tap changer range, and network tolerances.
  The grid rarely delivers exactly 15,000 V—it’s often 15,200 V, 15,400 V, or even 14,900 V.
  The transformer must include a margin for tap changer adjustments (± a few percent).
  That’s why you’ll often see numbers like 15.75 kV—slightly above nominal—to allow room for adjustment without losing synchronization with the inverter.

Those fractions (like 0.75 kV) are not a mistakes, they are a result of engineering precision.

Examples of typical voltage ratios and when to use them

In the world of medium-voltage transformers, there are certain classics—ratios that show up on construction sites as reliably as coffee at 6 a.m. in a design office. Each one has its own logic and technical rationale, shaped by decades of practice, grid conditions, and real-world experience.

Let’s break them down—not just by the numbers, but by their personalities.

The first evergreen: 10 kV / 0.69 kV

This one is a favorite in environments where high power meets smart electronics—think large-scale energy storage systems or EV charging stations.

Why? Because many industrial inverters operate at a nominal voltage of 690 V AC, which aligns perfectly with this ratio.

What makes this setup so effective is its low voltage ratio, which keeps secondary current at manageable levels without overloading the windings. Less stress on copper means better performance and a longer lifespan.

In simple terms: if your project includes power electronics with big appetites, this ratio offers pure stability on a silver platter.

The engineers’ favorite: 15.75 kV / 0.42 kV

Call this one the sweet spot for solar farms in Poland and Germany.

It’s a smart compromise between:

• MV grids typically running at 15 kV, and

• inverters working best around 400–420 V.

The extra 0.75 kV on the primary side gives headroom for voltage regulation, especially when tap changers come into play. This makes it easier to hit that Goldilocks zone on the LV side—not too high, not too low, just right.

It’s like finding perfect tire pressure for your electric car: quiet, efficient, and ready for any terrain.

This ratio is often chosen when engineers need grid synchronisation and inverter compatibility without the drama of last-minute design changes.

The all-time classic: 20 kV / 0.4 kV

This duo has been powering European infrastructure for decades.

You’ll find it across public distribution systems, municipal buildings, industrial parks—anywhere where compatibility, reliability, and simplicity are king.

It’s a straightforward setup:
20 kV primary, straight into the grid, and 0.4 kV secondary, ready for standard low-voltage panels.

There’s nothing fancy about it—but that’s exactly the point. It’s the transformer equivalent of a solid handshake: dependable, familiar, and trusted by generations of engineers.

Each of these voltage ratios is like a language dialect—speaking the same physics, just with a different accent.

• One speaks fluent inverter.

• Another chats easily with distribution grids.

• The third bridges both worlds with confident ease.

And that’s why the world of transformers is never boring. Behind those neat numbers on the rating plate lies a dance of engineering pragmatism, grid diplomacy, and yes—just a touch of poetry.

How transformer voltage ratio works – in a nutshell

Put simply, a transformer’s voltage ratio defines the relationship between the primary (input) voltage and the secondary (output) voltage.

If a transformer is rated at 15,000 V / 400 V, it means that for every 15,000 volts on the medium-voltage side, there will be 400 volts available on the low-voltage side.

From a user’s perspective, this means the transformer:

• steps down the voltage from the MV grid to a safe level for downstream equipment, and

• increases the current on the LV side inversely proportional to the voltage ratio.

In other words:
The higher the voltage ratio, the higher the current on the low-voltage side—and vice versa.

This is why we calculate transformer power using the formula:

S = U₁ × I₁ = U₂ × I₂

Where:

S – apparent power (in kVA)
U – voltage (in V)
I – current (in A)

Let’s look at a real-world example:

A transformer rated at 1000 kVA, with a 15/0.4 kV voltage ratio:

• Primary current (MV side):
  I₁ = S / (√3 × U₁) ≈ 1000 / (1.732 × 15,000) ≈ 38.5 A

• Secondary current (LV side):
  I₂ = S / (√3 × U₂) ≈ 1000 / (1.732 × 400) ≈ 1443 A

As you can see, the same transformer delivers dramatically different currents depending on the voltage.

That’s why selecting a voltage ratio without understanding the load characteristics, protection devices, and grid conditions is a fast track to problems—like tripping breakers, overheated windings, or inverter synchronization failures.

In transformer design, math is not optional—it’s your first line of defense.Phase configurations and their impact on voltage ratio

Sometimes, the winding connection scheme (such as Y-Δ, Δ-Y, Δ-Δ, Y-Y, etc.) affects the effective voltage ratio in a way that differs slightly from the nominal nameplate values.

For example, in Dyn11 configurations (a star-delta transformer with a 30° phase shift), the actual voltage ratio may require correction compared to what’s printed on the rating plate—especially when you're considering line-to-line versus phase voltages.

And if the configuration includes a neutral point (like Dyn11 with "n"), things get even more interesting. The presence of the neutral introduces new considerations for grounding, fault behavior, and voltage balancing. It’s one of those "small details" that turns out to be not so small when your system doesn't behave as expected.

Taps and voltage regulation

Most modern transformers offer tap changers on the primary winding, typically allowing ±2 × 2.5% adjustment range. This enables tuning of the input voltage to match real-world conditions.

So, when you see a transformer rated at 15.75 kV, don’t assume that’s a rigid number. It’s actually the center point of an adjustable range, giving engineers room to fine-tune voltage levels to ensure compatibility with both the grid and downstream inverters.

Think of it like a tone control knob on an amplifier—just enough to correct the pitch without needing to redesign the whole orchestra.

Losses, efficiency and standards

Every transformer design aims to minimize losses—both no-load (core) and load (copper) losses.

European regulations like Ecodesign 548/2014 require new transformers within specified power ranges to meet strict efficiency standards (e.g. Energy Efficiency Level 2 – EEF2).

And here's where the voltage ratio plays a surprisingly indirect role:

• A poorly chosen ratio can lead to higher conductor losses,

• reduced efficiency in voltage regulation,

• and increased heat generation within the windings.

It’s a domino effect. One decimal point off in your voltage ratio, and suddenly your whole installation is dealing with hotter cables, louder hum, and unhappy electronics.

Bottom line?
The voltage ratio is more than a number on a plate—it’s a fine-tuned parameter that balances thermal performance, energy costs, and compliance with regulations.

Why voltage ratio is key to synchronizing with the DSO grid

Distribution System Operators (DSOs) have very precise requirements when it comes to nominal voltage levels at connection points. That’s why a transformer’s voltage ratio must reflect the actual voltage present in the local grid, which often isn’t exactly 15,000 V but rather values like 15,750 V or 15,400 V.

This is crucial to ensure:

• Stable operation of PV inverters, which require a supply voltage strictly within the 400–420 V AC range,

• Maintaining medium voltage (MV) levels within the ±5% tolerance,

• Compliance with standard PN-EN 50160 on voltage quality parameters.

This is precisely why designers often select a 15.75/0.42 kV voltage ratio. It offers enough headroom for safe tap changer regulation (±2 × 2.5%), without risking loss of synchronization or breaching inverter specifications.

Differences between grids in Poland, Germany and Spain

Europe is a mosaic of medium voltage levels.

In Poland and the Czech Republic, the most common voltages are 15 kV and 20 kV.

In Germany, you often find 10 kV, 15 kV, and 30 kV networks.

In Spain, the typical values are 13.2 kV, 15 kV, and 21 kV.

As a result, a substation designer must not only know the nominal parameters of the grid, but also understand the “philosophy” and legacy of local distribution system operators.

For example:

• In Germany, there are still 10/0.4 kV networks in operation, where transformers with a 10.5/0.4 kV ratio are commonly used. This allows for proper tap regulation and coordination with old and new infrastructure.

• In Spain, 21/0.42 kV transformers are often used because the nominal voltage of 21 kV stems from historical 3×12 kV networks that were later modernized to a 21 kV standard. It’s a legacy system with modern adaptation.

• In Poland, the 15/0.4 kV ratio remains the standard in most cases. However, for industrial energy storage systems and high-power inverters, the 20/0.69 kV configuration is gaining popularity due to improved current distribution and lower cable losses.

These variations help explain why the same transformer might be labeled differently depending on the country of delivery.od kraju dostawy.

We design our units in standard voltage ratios like 10/0.4 kV, 15.75/0.42 kV, and 20/0.69 kV, with voltage regulation options of ±3×2.5% or ±2×2.5%, to meet the technical requirements of DSOs in Poland, Germany, and Spain.
Ask us about a configuration tailored to your project.

Once upon a time: the voltage ratio that saved the project

During the commissioning of a PV farm in Lower Silesia (Poland), the team discovered that the actual voltage at the point of connection was 15.6 kV, not the expected 15 kV.

If the transformer had a 15/0.4 kV ratio, the low-voltage side would have supplied 416–418 V to the inverters – exceeding their acceptable input range.

As a result, the system would have shut down every time the grid slightly boosted the voltage.

The use of a transformer with a 15.75/0.42 kV voltage ratio completely solved the issue. That seemingly small 0.75 kV margin on the MV winding turned out to be critical for stable operation and DSO compliance.

For the investor, this made the difference between a running PV farm and one that was non-operational.

Voltage ratio and protection equipment selection

The voltage ratio also determines the rated currents, which affects the selection of cables, current transformers (CTs), circuit breakers, and protection relays.

In real-world practice, an incorrect voltage ratio assumption can flip the entire logic of the project:

• Too small a ratio = too high current on the LV side = cable overheating, higher I²R losses, and accelerated aging of insulation.

• Too large a ratio = too low LV voltage = inverter undervoltage errors, disconnections, or decreased energy yield.

That’s why standards such as PN-EN 60076-1 and EN 50588-1 recommend that designers always consider the actual voltage at the point of connection, including ±5% tolerance, and the load characteristics (resistive, inductive, capacitive).

In PV and EV systems, an additional factor comes into play: dynamic voltage ratio performance. This refers to the transformer’s ability to compensate for fast changes in voltage, caused by inverter activity or rapid load variations from DC chargers.

It is no longer just about steady-state values – modern transformers must adapt to dynamic grid behavior in real time.

How to select a transformer voltage ratio – a practical example

Let’s assume you are designing a 2 MW substation for a PV farm connected to a 15 kV network, using inverters operating at 420 V AC.

You are choosing between two transformer voltage ratios: 15/0.4 kV or 15.75/0.42 kV.

For an apparent power of 2000 kVA:

15/0.4 kV configuration:

• I₁ = S / (√3 × 15 000) = 77 A

• I₂ = S / (√3 × 400) = 2887 A

15.75/0.42 kV configuration:

• I₁ = S / (√3 × 15 750) = 73 A

• I₂ = S / (√3 × 420) = 2747 A

The differences may seem small, but in practice they result in lower LV current, reduced power losses, and lower operating temperatures for the windings.

Over time, this translates into improved system performance and extended equipment lifespan.

Smart and adaptive transformers

A transformer is no longer a passive component in the power network – it has become an active player in maintaining system balance.

Integrated voltage regulators continuously analyze real-time values on both MV and LV sides and adjust the voltage ratio within a ±5% range.

This allows the substation to maintain optimal output voltage, even when loads fluctuate due to inverter operation or DC charging cycles.

This functionality is crucial in next-generation projects, where energy flows both to and from the grid.

In PV farms, battery storage systems, or e-mobility hubs, where the direction of power flow shifts constantly, a transformer with an adaptive voltage ratio becomes the system’s stabilizing core.

Moreover, an increasing number of distribution system operators (DSOs) across Europe are incorporating such features into their grid connection requirements.

It makes perfect sense. As networks become more distributed and less predictable, they require equipment that can think and react.

From an investor’s standpoint, this is not just about performance – it is about pure economics:

• Lower energy losses

• Reduced O&M costs

• Longer inverter lifespan

• No need for manual corrections – the substation begins to learn its own load profile.

In a world heading toward smart grids, the voltage ratio becomes a strategic parameter, not just an electrical one.

It defines your system’s energy efficiency, grid compliance, and resilience.

You could say that the transformer of the future is made not only of steel and copper, but also of logic and algorithms.

The future

Just a decade ago, voltage ratios were considered set in stone.

Once selected, a transformer would operate for 30 years unchanged, regardless of network variations or load shifts.

Today, that is no longer the case.

Modern designs – such as Energeks MarkoEco2 – offer automatic voltage regulation based on real-time load conditions.

This means the voltage ratio is no longer fixed – it can adapt within a ±5% range, keeping the LV side voltage stable even when the MV grid fluctuates.

Such solutions are now often required by DSOs in large-scale PV plants, energy storage systems, and EV charging stations.

As a result, the voltage ratio is evolving from an electrical specification into a strategic asset for ensuring system efficiency and long-term reliability.

If you are planning to invest in a transformer that understands the new logic of the grid, take a look at our offer:

→ Medium voltage transformers – full Energeks portfolio

You are also welcome to join our Energeks LinkedIn community, where we share knowledge, real-world experiences, and insights into the future of energy – always with gratitude for every partnership.

Because while technology builds the hardware, it is people and relationships that create a system that truly works.

Źródła:

European Commission – Regulation (EU) 2019/1783 supplementing Regulation (EU) 548/2014: Ecodesign requirements for power transformers

Forbot: Transformator – budowa, zasada działania i zastosowanie

No-load losses in Tier 2 transformers. Iron, heat and capacitors, the hidden cost nobody sees.

Imagine a kitchen tap dripping once every few seconds.

For a week you ignore the noise. After a month you stop hearing it.

After a year you find out that you paid a water bill that doesn’t match your real usage.

No-load losses in transformers work in a similar way. A transformer connected to the grid consumes energy even when there is no load on the low-voltage side. It is the breathing of the core. It is the magnetization of the laminations. It is heat that quietly escapes and turns into the operating cost of the installation.

Tier 2 tightened the requirements on losses and made it possible to finally measure these differences objectively. This is good news for investors, contractors, designers and asset managers, provided they know which numbers matter and how to read them. In this text we serve it on a plate.

If you are looking for specifics, here you will find formulas, regulatory thresholds, examples of numerical calculations and practical tips on how to read catalog sheets and test reports according to IEC.

We will show you when a difference of a few hundred watts in P0 is worth the effort, and when it is better to invest in better steel, a larger core or a different insulating medium, because the whole TCO will drop already in the first years of operation.

We will also explain the role of capacitors. Let me spoil the ending right away. Capacitors do not reduce the no-load losses of the core, but they can lower currents in the grid and improve the balance of load losses as well as contractual penalties for cosφ.

What you will find inside.

First, briefly and in plain language, I explain what no-load losses are and where they come from.

Then we organize the Tier 2 requirements in the European Union and show what the permissible loss tables really change.

Next we move to money. We calculate how much each additional kilowatt of P0 costs in a year and over a horizon of twenty-five years.

Finally, we check where and when capacitors make a difference and how to select them so as not to fall into resonance and not worsen the situation.

Reading time. About 10 minutes

What no-load losses are and why they always occur

Let us start with the basics.

No-load losses P0 are the power lost by a transformer when it is energized at its rated voltage, while the secondary winding carries no load.

Put simply, this is the price you pay for the very fact that the core is being magnetized by a field at fifty hertz. P0 is mainly composed of losses in the magnetic core laminations.

There are two main mechanisms at play.

First, hysteresis, which is the energy required to take the material through its magnetization cycle. Second, eddy currents, tiny circulating currents induced in the plane of the steel sheets, which dissipate energy as heat.

In practice, P0 remains largely constant from no load to full load under sinusoidal supply, because the core essentially sees the same voltage and frequency. This is why P0 is often colloquially called iron losses. The measurement definition for P0 under no-load conditions and rated voltage can be found in IEC 60076 Parts 1 and 7.

Why this is a fixed cost

Because in real life transformers are rarely switched off.

In medium-voltage substations, PV farms, data centers and industrial switchgears, they run around the clock. That means 8760 hours per year, during which every additional 100 watts of P0 consumes 876 kilowatt-hours of energy.

Over a 25-year horizon, this amounts to 21,900 kilowatt-hours from just that tiny fraction of a kilowatt.

Now let’s put a European number on it. If the combined energy and distribution price is about €0.12 per kilowatt-hour (roughly €0.08–0.20 across EU countries in 2025, depending on sector and contract), then an extra 100 watts of P0 costs around €2,628 over the transformer’s lifecycle.

That means one extra kilowatt of no-load losses equals 8760 kilowatt-hours annually – a merciless factor. For comparison, that is the yearly consumption of a typical European household of 2–3 people.

Where differences in P0 between transformers come from

The shortest answer: from the quality and grade of steel, the technology of cutting and stacking the core, the core size, and the working flux density chosen by the designer.

Higher-quality material and a larger core mean lower no-load losses, but they also imply greater mass and a higher purchase price. The real decision therefore is not about buying cheaper or more expensive, but how to optimize the total cost of ownership (TCO) for the specific load profile.

With Tier 2, manufacturers were required to lower loss thresholds. As a result, many modern transformers achieve P0 values clearly below the tabular limits. We will explore those limits in the next section.

How do capacitors relate to P0?

This is the question that tempts many to search for a shortcut.

Unfortunately, capacitors have no influence on the core losses, because P0 is determined by the material, geometry, applied voltage and frequency. Reactive power compensation lowers currents in lines and windings, which can improve the balance of load losses and reduce penalties for cosφ, but it does not reduce the P0 component.

We will return to the role of capacitors in more detail in a dedicated section, together with resonance risks and sizing guidelines.

A practical control question

Suppose the price difference between two transformers is €3,000–€4,000, but the more expensive version has 300 watts less P0. Which option is cheaper after five years in a continuously operating installation?

In many cases, by the third year the higher-efficiency transformer breaks even, and by the fifth year it begins to generate real savings.

That is why, in Europe’s current energy landscape – with electricity costs rising and climate policies tightening – Tier 2 no-load loss optimization is no longer just a technical matter, but a financial and strategic one.

Tier 2 in practice. What the EU loss tables changed and how to use them

The Ecodesign regulations for transformers in the European Union brought long-awaited order to the topic of transformer losses.

First came the initial stage, Tier 1, effective from 1 July 2015. Then, from 1 July 2021, stricter limits known as Tier 2 were introduced. These include maximum permissible no-load losses (P0) and load losses (Pk) for medium-power transformers up to 3150 kVA, with a distinction between oil-immersed and dry-type designs.

The regulation also requires that documentation specifies the rated power, P0, Pk, and the Peak Efficiency Index (PEI) where applicable. This makes it easier to compare offers directly against the normative tables instead of relying solely on marketing declarations.

How to read the tables and not get lost in the symbols

Take, for example, a three-phase transformer rated 2000 kVA with a high-voltage winding up to 24 kV and a low-voltage winding up to 1.1 kV.

For this configuration, the Tier 2 table for oil-immersed units shows maximum no-load losses of about 1.305 kW. For dry-type designs of the same power, the corresponding Tier 2 table allows P0 of about 2.34 kW.

In practice, permissible values vary with voltage combinations and specific cases. For instance, for 36 kV windings or dual-voltage designs, correction factors apply that increase the permissible limits.

It is therefore crucial to compare offers within the same voltage class and under the same design assumptions. Otherwise, you are comparing apples to pears.

What about units above 3150 kVA?

For larger transformers, the regulation focuses primarily on minimum PEI values. This does not mean that P0 stops being important.

On the contrary. PEI depends on both P0 and Pk, as well as on the load point at which efficiency is maximized.

Documentation should include both the PEI and the load level at which it occurs. If in doubt, demand from the manufacturer a complete data sheet with test results and calculation methods in accordance with IEC standards.

From regulation to money

Now comes the most pleasant part, because numbers simplify decisions.

Let us assume you are comparing two transformers in the same voltage class and with the same rating. One has P0 = 2.0 kW, the other P0 = 2.6 kW. Both are within the permissible Tier 2 limits for the configuration, but the second is 0.6 kW worse.

The difference in energy consumption due to no-load losses is 0.6 kW × 8760 hours = 5256 kWh annually.

At a total price of around €0.12 per kilowatt-hour (average combined energy and distribution cost across EU member states), you are paying about €631 every year just for that difference. Over 25 years, that adds up to roughly €15,780.

Even if the transformer with better steel is heavier and costs more in transport, the total cost of ownership (TCO) often drops significantly, especially where transformers are never switched off. It sounds simple – because it is – but only with Tier 2 did these comparisons become repeatable and quantifiable.

Why investors sometimes overvalue Pk at the expense of P0

Load losses Pk are most painful on sunny days and during production peaks, so they appear more visibly in reports. P0, on the other hand, keeps adding costs silently every day, including during idle periods and off-season.

If the installation runs continuously, every excess in P0 is a guaranteed expense.

It therefore makes sense to split the strategy. For facilities with highly variable loads, you should optimize Pk together with voltage regulation and cooling. For facilities operating seven days a week, you need to pay more attention to P0, because it dictates the baseline bill.

IEC documents define the measurement of P0 in a repeatable way, and Ecodesign enforces transparency of data in catalogues and nameplates.

A note on data quality

It happens that some offers list values like P0 ≤ 2600 W. Such a statement does not tell you what the manufacturer actually achieves in testing. Always demand figures with decimals and type-test reports according to IEC 60076.

This is not nitpicking against manufacturers, but standard purchasing practice for assets that will stay with you for decades.

Why a 5 kW difference means hundreds of thousands of euros over 25 years

No-load losses and the investor’s wallet

From the perspective of an investor or asset manager, every figure in the loss table translates directly into money. Imagine a 2000 kVA transformer with no-load losses of 15 kW. Another manufacturer offers a similar transformer, but with P0 = 20 kW. On paper, 5 kilowatts may look like a minor detail. In practice, it means an extra 5 kW drawn continuously for 8760 hours per year – that is 43,800 kilowatt-hours of energy that no one used but someone must pay for.

A 25-year calculation

At an average European electricity price of €0.12 per kWh (energy plus distribution), the annual cost difference is €5,256. Over 25 years, that adds up to €131,400.

This is not an abstraction. It is the equivalent of a new electric vehicle, an additional solar tracker for panels in a PV farm, or even a year’s maintenance budget for an entire transformer substation.

Why do tenders often overlook this?

Because most of the attention focuses on the transformer’s purchase price, transport, or foundation costs. No-load losses get lost in the table among dozens of other parameters. On top of that, sales teams often state values like “≤20 kW” without giving the actual measured figure.

It is like buying a car with a brochure that says, “consumption no more than 10 l/100 km”. In reality, it could be 7 or 9.9. Both are technically within the spec, but over years the cost difference becomes enormous.

The takeaway

A small difference in P0 is not a detail – it is money leaking systematically. Anyone comparing offers should convert watts into euros over a 20–30 year horizon before making a decision.

The role of capacitors – hidden ally or unnecessary ballast?

Capacitors and no-load losses

Let’s bust a myth first. Capacitors do not reduce core no-load losses. P0 is determined by the physics of iron, not by reactive power flows. The only way to reduce P0 is by improving the core material, its mass, or the manufacturing technology.

Where capacitors really make a difference

Capacitors play a key role in reactive power compensation. They improve the power factor (cosφ), which lowers currents in cables and transformer windings. This, in turn, reduces load losses (Pk), which are proportional to the square of the current. In other words, capacitors won’t touch P0, but they can significantly improve the loss balance of the whole installation.

How much capacitor power is needed?

That depends on the load profile and type of consumers. If a medium-voltage substation supplies equipment with a large share of induction motors, compensation may require several hundred kvar. In PV farms or energy storage facilities, values are usually smaller but still relevant – often in the range of 50–200 kvar. The rule of thumb is clear: capacitors should be sized to keep cosφ at the level required by the distribution system operator, typically above 0.95.

The resonance trap

Care must be taken to ensure that compensation does not enter resonance with network harmonics. Sometimes capacitors, instead of helping, worsen the situation by causing overvoltages or overheating. This is why modern substations often use detuned capacitor banks with reactors, or even active power factor correction systems.

Capacitors and investment strategy

So, are capacitors worth investing in? Yes – but not as a magic solution for P0. Their role is to reduce load-related losses, improve energy quality, and avoid penalties from the grid operator. In a well-designed system, capacitors can lower total energy losses by 5–10%, improving the transformer’s economic efficiency, particularly under heavy inductive loads.

How to read transformers technical data sheets and manufacturer offers

“≤30 kW” versus “exactly 28.7 kW”

At first glance, both notations look correct. The problem is that the “≤” symbol gives the manufacturer a wide margin – in reality, the transformer may have no-load losses of either 19 or 29.9 kW. In both cases it complies with the standard, but the difference in operating costs amounts to tens of thousands of euros. That is why you should always demand a precise value with a decimal point. This is not a whim – it is standard engineering practice.

IEC type test reports

A catalogue is one thing, but an IEC 60076-compliant type test report is another. The report shows the actual measured loss values, not just the manufacturer’s declarations. In tenders and technical acceptance procedures, it is worth requesting such documents. It is similar to demanding certified fuel consumption tests from a car manufacturer – only then can you be sure the data is real.

Language and marketing traps

In offers you will find terms such as “optimized core”, “innovative design” or “energy-efficient construction”. They sound good, but until you see a hard P0 figure, it is just marketing. Always look at the loss table, not the adjectives.

How to compare offers step by step

• Select transformers with the same rated power and voltages.

• Place P0 and Pk values in a table with accuracy to the watt.

• Multiply the differences by 8760 hours per year and the electricity tariff.

• Project the result over 25–30 years of operation.

• Compare the total with the purchase price difference between transformers.

This simple algorithm shows that “more expensive at the start” very often means “cheaper over the entire lifecycle”.

The myth of the heavier transformer – does heavier always mean better?

More iron = fewer losses?

In many technical discussions there is a myth that the heavier the transformer, the better it is. There is some truth in this. A larger core with more laminations allows for lower flux density and lower no-load losses. But a heavier transformer also means higher costs for transport, foundations, and installation.

A comparative example

Suppose we have two 2500 kVA transformers. The first weighs 6.5 tonnes and has no-load losses of 5.8 kW. The second weighs 7.5 tonnes and its P0 is 5.1 kW. The 0.7 kW difference means about 6130 kWh saved annually. At a European average price of €0.12 per kWh, this equals about €735 per year. Over 25 years, that is roughly €18,375.

The question is: will the extra transport and foundation cost for the heavier transformer outweigh these savings? Often not – but you have to do the calculation.

When lighter beats heavier

If a project requires installation in a hard-to-reach location, where transport and cranes are extremely costly, a lighter transformer may be preferable despite higher losses. This is especially true in prefabricated transformer substations, where mobility and limited space matter – in such cases, weight becomes a real factor.

Heavier does not always mean better. Instead of evaluating by tonnes, you should evaluate by the balance of total cost of ownership (CAPEX plus OPEX). Then it becomes clear that sometimes it pays to add 100 kg of steel, and sometimes it is smarter to optimize logistics and foundation costs.

No-load losses are not a detail, but a strategic decision

No-load losses in transformers are not just “a tiny number in the datasheet”. They are a fixed cost that runs day and night, regardless of the load. Tier 2 standards have enforced greater transparency, but only a conscious approach by the investor, designer, and asset manager turns those numbers into real savings.

We have shown that just 1 kW of no-load losses equals nearly 9 MWh per year.

Over a 25-year perspective, this means hundreds of thousands in currency that can either stay in the budget or silently vanish into electricity bills. We also discussed the role of capacitors. They are not a tool for reducing P0, but a key element in reactive power compensation and in stabilizing the entire installation.

Well-designed capacitor banks reduce load losses, help avoid penalties from the grid operator, and improve the economic performance of the transformer.

For the investor, the key lesson is simple: look at the total cost of ownership (TCO), not just the purchase price.

Datasheets must be read critically, IEC test reports demanded, and watts converted into money. The transformer’s weight, price, or size is only part of the puzzle. Only by summing up all elements do you get the true picture.

Our approach

At Energeks, we have been designing and delivering medium-voltage transformers, prefabricated substations, and switchgears for years. In our portfolio you will find Tier 2 medium-voltage oil-immersed transformers as well as dry-type transformers, all designed to optimize no-load and load losses throughout the entire lifecycle. We support our partners at every stage of project execution – from concept, through transformer selection, to commissioning and service.

If you are looking for a partner who will not only deliver a transformer but also help you realistically calculate and optimize costs over decades – let’s talk.

Join the Energeks community of energy enthusiasts and professionals on LinkedIn

Sources:

EUR-Lex. Commission Regulation EU No 548/2014/ Loss Tables Tier 1 i Tier 2.

IEC 60076. Definitions of no-load loss measurement and test principles.

Schneider Electric. Transformer reactive power compensation and the role of capacitors.

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

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

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

However, the reality might be the complete opposite.

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

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

Why are we writing about this?

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

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

Our goal is simple:

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

In this material you will find:

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

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

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

• The differences between a spark gap and a surge arrester

• Criteria for distinguishing normal operating marks from actual damage

• Inspection and maintenance procedures

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

• When replacement is necessary

• The importance of operator education

• The outlook for the future of overvoltage protection

Reading time: approx. 15 minutes

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

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

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

Principle of operation:

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

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

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

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

Laboratory spark gap with flat electrodes/CC: Wikimedia Commons

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

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

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

2.1. Occurrence of overvoltage

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

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

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

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

• Ferroresonance in systems containing capacitances and inductances

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

2.2. Discharge initiation – ionisation of the medium

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

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

2.3. Breakdown and formation of the electric arc

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

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

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

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

2.4. Energy dissipation to grounding

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

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

2.5. Arc extinction and return to the idle state

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

• Spark gap design (open, enclosed, tubular)

• Pressure and composition of the medium

• Cooling rate

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

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

• Localised burn marks at the initiation point

• Microscopic material losses

• Deposits of metal oxides and carbon

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

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

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

Where the marks come from

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

Such high temperatures cause:

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

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

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

Types of marks

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

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

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

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

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

What the marks mean – interpretation

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

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

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

Everyday comparison

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

Impact of the environment on the appearance of marks

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

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

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

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

Why understanding mark interpretation is crucial

Misinterpretation can lead to two unfavourable scenarios:

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

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

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

4. Differences between a spark gap and a surge arrester

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

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

Spark gap – a component, not a complete device

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

• Under normal conditions, it does not conduct current.

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

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

Surge arrester – a complete overvoltage protection device

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

Types of surge arresters:

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

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

• Why spark gaps are still found in MV substations

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

• Prefabricated transformer substations from the 1980s and 1990s

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

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

Cooperation between spark gaps and surge arresters

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

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

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

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

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

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

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

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

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

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

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

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

5. Criteria for distinguishing normal operational marks from actual damage

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

Visual inspection – the first assessment filter

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

Normal operational marks:

• Small, localised burn marks at arc initiation points

• Slight discolouration of electrode surfaces

• A thin deposit layer, easy to remove during cleaning

Damage indicators:

• Cracks in ceramic or polymer housing components

• Mechanical deformation of electrodes

• Melting with visible depth to the naked eye

Electrode gap measurement

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

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

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

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

Condition of insulating surfaces

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

Normal condition:

• Light surface deposit, removable

• No visible losses or cracks

Failure condition:

• Cracks running through the full thickness of the insulator

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

Type and structure of deposits

Deposit forms from condensed electrode material and airborne particles.

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

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

Operating history and number of operations

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

Leakage resistance measurement

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

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

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

Normative criteria – when to declare a failure

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

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

• It has mechanical damage that may affect operational safety

• It shows a permanent drop in insulation parameters

A practical rule often applied at Energeks:

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

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

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

We recommend implementing a structured inspection procedure.

1. Preparation for inspection – safety first

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

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

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

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

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

2. Visual inspection – the first stage of diagnostics

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

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

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

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

3. Measuring the electrode gap

• Use a caliper or feeler gauge.

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

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

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

4. Cleaning

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

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

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

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

5. Photographic documentation

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

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

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

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

6. Measuring electrical parameters (optional)

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

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

• Above 100 MΩ – very good condition.

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

7. Replacement criteria

The spark gap must be replaced if:

• it has cracks or mechanical damage,

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

• conductive deposits remain after cleaning,

• insulation parameters have dropped below acceptable limits.

8. Inspection schedule

• Substations in normal environments – inspection every 12 months.

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

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

9. Best practices

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

• Use original spare parts in accordance with DTR.

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

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

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

Humidity and condensation

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

Effects:

• premature spark gap operation under normal working conditions,

• formation of mineral deposits after water evaporation,

• accelerated electrode corrosion.

Service recommendations:

• regular inspections during periods of large temperature fluctuations,

• checking substation ventilation,

• use of hydrophobic coated elements in high humidity environments.

Saline air (coastal zones)

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

Effects:

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

• increase in leakage currents,

• formation of persistent deposits that are difficult to remove.

Service recommendations:

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

• use enclosed or shielded designs,

• periodically rinse components with demineralized water combined with drying.

Industrial dust

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

Effects:

• increased frequency of operation under moderate switching surges,

• higher risk of surface tracking,

• accelerated electrode wear from microscopic abrasive particles.

Service recommendations:

• use air filters in substation ventilation,

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

• inspect insulator surfaces for microdamage.

Agricultural environments and organic dust

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

Effects:

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

• localized conductivity under high humidity conditions,

• accelerated contamination of insulating surfaces.

Service recommendations:

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

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

Extreme temperatures

Mechanism of influence:

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

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

Effects:

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

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

Service recommendations:

• adjust inspection schedules to seasonal weather conditions,

• use materials resistant to UV and temperature fluctuations.

Why the environment must be considered in the service schedule

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

We recommend the following approach:

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

8. When to Replace a Spark Gap

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

Most common reasons for replacement:

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

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

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

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

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

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

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

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

• mechanical damage affecting operational safety,

• insulation parameters below acceptable limits.

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

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

Recommended replacement timing:

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

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

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

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

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

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

Why knowledge is crucial

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

• It enables cleaning or replacement decisions without unnecessary downtime.

• It supports accurate documentation of equipment condition.

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

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

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

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

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

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

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

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

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

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

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

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

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

Thank you for reading this text to the end.

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

SOURCES:

IEEE Xplore – “Spark Gap Devices for Surge Protection”

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

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

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

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

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

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

Why are we the ones writing about this?

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

Who is this article for and what will you gain?

This article should be read by anyone who:

• manages power infrastructure

• designs or operates MV substations

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

By reading this you will:

• learn the critical signs of damage after flooding

• discover how to properly dry a transformer

• understand when repairs are a waste of time

• learn the current standards and manufacturer recommendations

Here is what lies ahead:

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

• Damage assessment: which components suffer the most

• Moisture, insulation and standards: how water affects safety

• Drying or replacement: making the technical and financial decision

• How to carry out an intervention step by step

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

Reading time: approx. 12 minutes

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

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

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

Voltage in water: literally and figuratively

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

If water enters the transformer, it affects key components:

• bushings

• low and medium voltage windings

• magnetic core

• cooling systems and conservator

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

Prefabricated substation and water retention

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

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

The sponge effect: moisture in the dielectric and paper structure

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

• reduced breakdown voltage

• partial discharge activity

• accelerated aging of insulation materials

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

Electricity and water: a deadly mix

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

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

Water does not always leave with the rain

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

That is why it is crucial to:

• test the transformer for insulation moisture content

• perform DGA (dissolved gas analysis)

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

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

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

Damage assessment: which components suffer the most

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

Post-flood diagnostics: from the floor to the bushing

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

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

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

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

• grounding and bonding connections

• pins and busbars

• mounting frames

• conservator valves and breathers

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

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

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

• dielectric dissipation factor (tangent delta) measurements

• dissolved gas analysis (DGA)

• breakdown voltage and insulation resistance measurements

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

What tests should be performed after flooding?

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

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

• DGA testing

• oil breakdown voltage measurement according to PN-EN 60156

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

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

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

What about documentation and responsibility?

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

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

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

Water in the transformer: the invisible enemy of dielectrics

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

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

• reduce winding breakdown voltage by 30 percent

• shorten the expected transformer lifespan by 50 percent

• increase the risk of partial discharges on winding surfaces

• accelerate cellulose aging (depolymerisation)

Why oil does not always protect

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

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

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

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

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

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

• for mineral oil: minimum 30 kV

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

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

What standards and manufacturers say

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

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

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

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

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

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

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

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

How long does insulation drying take

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

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

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

Drying methods include:

• resistive heating with forced ventilation

• cyclic heating and vacuum steam removal

• vacuum drying at around 90 to 110°C

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

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

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

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

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

When drying makes sense?

Drying can be considered only when:

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

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

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

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

When replacement is a better option

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

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

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

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

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

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

Cost comparison: drying vs replacement

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

Drying costs include:

• removal of the transformer from the prefabricated substation

• transport to a service facility with a vacuum drying chamber

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

• oil filtration or replacement

• reinstallation, acceptance testing and commissioning

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

Replacement costs include:

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

• factory transport

• installation and acceptance testing

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

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

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

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

From experience, regeneration makes the most sense when:

• the transformer is relatively young

• its power and parameters are optimal for the facility

• access to the unit and logistics are straightforward

• downtime can be organised or minimised without major loss

Replacement is recommended when:

• the transformer is older

• it already shows signs of wear and efficiency loss

• it serves an installation critical for operational continuity

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

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

Refurbish or replace? Last chance for your transformer!

How to carry out an intervention step by step

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

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

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

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

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

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

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

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

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

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

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

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

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

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

What to do with a transformer after flooding

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

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

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

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

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

Service records are your investigation log:

• has elevated moisture in oil been reported before

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

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

• has anyone reported cooling system repairs or leaks

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

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

A transformer with a past can still have a bright future

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

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

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

Find out more:

• MV transformer offer – Energeks

• Join our community on LinkedIn

• Contact us

Sources:

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

2. CIGRÉ Technical Brochure 445: Guide for Transformer Maintenance

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

Step by Step Through All the Documents Required by the Grid Operator, Technical Inspection Authority – and Your Own Safety Standards

The transformer arrives on site.

New, gleaming, with a precisely engraved nameplate.

Everything seems in order – and yet, something is missing. Commissioning is delayed for days, sometimes even weeks.

Because somewhere, a single document is missing. Or maybe two.

We know exactly what that feels like in practice. The site manager calls: “The registration is missing.”

The grid operator demands: “Please submit the complete test report.”

The investor asks: “Why haven’t we received a wiring diagram with serial numbers?”

These may seem like minor details – but they are exactly the details that determine whether a project stays on schedule or falls behind.

At Energeks, we experience this daily – through conversations with dozens of companies that have implemented hundreds of projects and still regularly ask themselves:

“Do we really have all the documents needed for commissioning?”

And that question alone is a sign of quality. Because this isn’t just about a transformer.

It’s about responsibility.

If you are:

• responsible for ordering a medium-voltage unit and want to avoid unpleasant surprises during acceptance,

• planning or managing an electrical installation where every detail matters,

• preparing technical documentation for the grid operator or technical inspection authority,

• or simply have a transformer currently on a truck and don’t know what to look out for during commissioning,

— then this guide is exactly for you.

We’ll show you which documents are absolutely essential in your transformer documentation package to ensure commissioning runs smoothly – and the unit can be operated legally, safely, and with peace of mind.

No regional guesswork. No hidden requirements.

You’ll learn:

• why technical documentation is an investment – not just a bureaucratic formality,

• what content must be included in the technical datasheet of a medium-voltage transformer (and what’s often missing),

• what a complete documentation set looks like, including operating instructions and test protocols,

• which documents are required by grid operators in different countries,

• when a transformer must be reported to the technical inspection authority,

• and how to prepare a full operational package that supports the transformer across its entire life cycle.

Reading time: approx. 13 minutes.

1. Why the Documentation of a Medium Voltage Transformer Is More Than Just Bureaucracy

Why technical documentation for an MV transformer is far more important than it might first appear – and what risks you face when it’s incomplete.

“Why all the paperwork? The transformer works fine, the readings are spot on, there’s no oil leakage, the nameplate looks perfect…” Sound familiar?

This is how costly stories often begin. Documentation is initially underestimated. Then come the frantic calls – to the planner, the service team, the manufacturer, and eventually complaints management. Usually the day before commissioning… or already after a fault has occurred.

Here’s the truth: the documentation of a medium voltage transformer is like an aircraft’s black box – it records everything from the moment of manufacture to final installation. Without it, you're essentially operating an unregistered vehicle – without a licence, registration, or manual.

What does “complete documentation” really mean?

It’s not just an operating manual.

It’s a comprehensive package of documents that:

• forms the foundation for technical acceptance by the investor and the distribution network operator (DNO),

• is essential for any warranty or claims procedure,

• enables compliant operation under LVD, EMC, RoHS, and CE regulations,

• and contains critical data for operation, maintenance, and regular inspection.

If even one of the following documents is missing – for example:

• the electrical schematic,

• the type test report,

• or the registration with the relevant inspection body (e.g. UDT in Poland),

— the consequences may include:

• project delays of several weeks,

• rejection of the commissioning by the DNO,

• invalidation of the manufacturer’s warranty,

• and serious insurance issues in the event of an incident.

What exactly is an “Operating Manual”?

In Poland, this is often referred to as the DTR – Dokumentacja Techniczno-Ruchowa, which roughly corresponds to the operating and maintenance documentation in the German-speaking world. However, it goes far beyond a standard instruction manual or CE sheet.

In Germany, Austria, and Switzerland, equivalent requirements are governed by various terms and standards, including:

• the Operating Manual as per the Machinery Directive 2006/42/EC,

• Technical documentation in accordance with the Product Safety Act (ProdSG),

• Declarations of Conformity as per DIN EN 60204 or IEC 60076,

• and, where applicable, additional proof for approval by an authorised inspection body (ZÜS), such as TÜV, DEKRA, or Bureau Veritas – especially for oil-filled, hermetically sealed transformers classified as supervised equipment under national safety regulations.

In practice, “complete documentation” means a bundled dossier containing:

• all technical specifications and tolerances of the transformer,

• connection diagrams and connection conditions,

• definitions of operational limits and environmental factors,

• test protocols as per IEC 60076-1 or VDE 0532-76,

• instructions for maintenance, cleaning, servicing, and decommissioning,

• plus disposal and recycling guidelines in line with WEEE and national legislation.

Additionally, utility providers across the DACH region (e.g. Bayernwerk, Netze BW, Westnetz, or Wiener Netze in Austria) often require:

• standardised manufacturer declarations,

• certificates for insulating oils (e.g. based on CIGRE test procedures),

• and proof of energy efficiency classes according to Ecodesign Regulation EU 2019/1783.

So this isn't merely regulatory red tape. It's:

• proof of warranty and product liability,

• the basis for commissioning and DNO acceptance,

• legal documentation in the event of incidents or audits,

• and above all, a tool for safe, economic operation throughout the asset’s lifespan.

A relatable analogy:

Imagine buying a new company car. You receive the keys and logbook – but there’s no service history, no warranty card, no EU type approval. Sure, you can drive it – until the first roadside check or first breakdown. That’s exactly what a transformer without documentation is like.

A transformer without proper paperwork is an expensive gamble. Will it work? Sure. But for how long? Under what conditions? Who is responsible if something goes wrong? What can your technician repair – and what needs the manufacturer’s approval?

Where do gaps in documentation most often occur?

From our ongoing conversations with engineers, contractors, and investors, we know that certain documents are frequently missing:

• incomplete nameplate data (or inconsistencies between the plate and the technical documents),

• missing electrical schematics – without which proper commissioning is nearly impossible,

• absent test reports – despite being a basic requirement for DNO acceptance,

• incomplete CE declarations, often lacking the manufacturer’s name or serial number.

All of these can be addressed before delivery, clearly defined in the contract, and provided upfront. But only if you know what to look for – and that’s exactly why we created this guide.

Because only a complete technical documentation set enables a transformer to cross the threshold legally – from production into operation in your energy infrastructure.

In the sections that follow, we’ll walk you through:

• what a correctly completed technical datasheet should look like,

• what a full operations manual and test protocol should contain,

• and how to avoid getting lost in DNO bureaucracy.

2. Technical Datasheet of an MV Transformer – 11 Essential Parameters (Plus 4 You Should Add Sooner Rather Than Later)

A transformer’s technical datasheet is like its CV. You skim over it, compare key figures, glance at the performance values – but are you reading it with the eye of an engineer, or in the rush of a logistics manager?

In practice, this is where the quality of the entire investment begins. Planners use it to select protection devices. Installers base foundation layouts on it. Grid operators check connection parameters. Harmless? A single incorrect line can cost hundreds of thousands – if the transformer doesn’t match the station or fails to meet DNO requirements.

Let’s break it down point by point – with examples and practical context.

1. Rated Power – ONAN vs ONAF makes all the difference

The transformer’s power (e.g. 1000 kVA) represents its nominal transmission capacity. But without the cooling method, you won’t know whether this is a “paper rating” or real performance under load. If the manufacturer quotes 1000 kVA under ONAN (natural oil and air cooling) but your application needs ONAF (forced cooling), the unit may overheat within hours of continuous operation.

→ Ideally stated as: 1000 kVA (ONAN) / 1250 kVA (ONAF) – this tells you the unit can deliver higher output with fans.

2. Primary and Secondary Voltage – not just numbers, tap range matters

A 15/0.4 kV transformer? Classic. But a savvy planner asks: what’s the tap range? Voltage regulation on the primary winding (e.g. ±2×2.5%) allows for grid fluctuation compensation. Without this detail, you're risking mismatched voltages on the low-voltage busbar.

→ If the datasheet only states nominal voltages, ask specifically about tap positions.

3. Vector Group – a small code with serious implications

Dyn5? Yzn11? Not spy codes, but winding configurations. Why does it matter? They define the phase shift between HV and LV sides and impact grid compatibility.

→ Choosing the wrong vector group = synchronisation and protection headaches.

4. Cooling & Insulating Medium – dry, oil-filled, hermetic? Choose wisely

ONAN, ONAF, AN, AF – not a game of Scrabble. Different settings demand different cooling concepts. A forest-side station differs from one in an industrial hall. Dry-type units are safer for fire, but noisier. Oil-filled types run quieter but require maintenance and leak control.

→ Check if the unit uses eco-friendly insulation such as ester fluid – increasingly relevant for EU-funded projects.

5. No-Load and Load Losses – who pays for idle time?

No-load losses (P₀) arise from core magnetisation – even without load. Load losses (Pk) appear under current flow.

→ For a 1000 kVA unit, a 100 W difference over 20 years can mean thousands in energy cost. Always compare based on EN 50588-1 efficiency classes – e.g. Tier 1 or Tier 2.

6. Short-Circuit Impedance – vital for protection selectivity

For a 1000 kVA transformer, standard impedance is around 6% ±10%. Too low = high fault currents. Too high = large motors may not start properly.

→ Planners need this value to size protection correctly. If it’s missing, commissioning becomes guesswork.

7. Short-Circuit Currents & Overload Capacity – how much can your unit take?

When large motors start or grid faults occur, the transformer must withstand serious stress. Without these values, there’s no guarantee the device won’t fail at the first surge.

→ Check overload thresholds for 1 and 5 seconds.

8. Dimensions & Weight – will it fit the substation without cracking the foundation?

A 1000 kVA transformer can weigh between 1800 and 2500 kg. The difference: insulation type, oil volume, housing. The planner needs to know the total weight (with/without oil) and exact dimensions.

→ Not just for logistics – but crucial for crane choice and base design.

9. Protection Rating (IP) – rain, dust, or curious fingers?

IP23, IP44, IP54 – different levels of protection against solids and moisture. A factory floor has different needs than an outdoor unit.

→ IP54 protects against water spray from all directions – a key factor in ensuring long-term reliability.

10. Manufacturing Standards – not decoration, but legal foundation

Look for references to the EN 60076 series (Parts -1 to -22). These ensure both technical quality and legal compliance (CE marking, national requirements).

→ Without these, no DNO registration or market surveillance approval.

11. Unit Identification – manufacturer, year, serial number

Sounds obvious? Yet it’s not uncommon for the nameplate to show a serial number different from the one in the docs. No match = no acceptance and doubts about authenticity.

→ Make sure all documents are issued and signed by the manufacturer.

Optional but Strongly Recommended:

• Energy Efficiency Class – increasingly demanded by grid operators and ESG-focused investors.

• Winding conductor cross-sections – important for protection, cooling, and terminal compatibility.

• Oil type – e.g. MIDEL 7131, mineral oil, silicone – each affects performance.

• Safety features – e.g. pressure relief devices, temperature sensors, leakage detectors.

A great project begins with a great datasheet. It’s not a sales brochure – it’s the instruction manual for 30 years of peace of mind.

In the next section, we’ll guide you through the operating documentation and test protocols that every transformer needs.

3. What Is the Operating Manual – and Why No MV Transformer Passes Final Acceptance Without It, Even If It Looks Perfect

The operating manual of a medium-voltage (MV) transformer is not some throwaway document destined to sit unread in a site manager’s binder. It’s the official “passport” of your transformer – a comprehensive technical record that accompanies the unit from the factory floor through to the end of its service life (and sometimes beyond).

It’s not without reason that it’s often referred to in the industry as “the queen of MV documentation.”

Within the operating manual, you’ll find everything required to:

• install the transformer safely,

• commission it in compliance with relevant standards,

• operate it efficiently and with legal assurance,

• and correctly hand it over for servicing or decommissioning.

What belongs in a complete operating manual?

1. Technical Description of the Unit

Not just a repetition of the datasheet, but an in-depth overview: tolerances, temperature classes, detailed specifications, circuit diagrams, and, where applicable, special notes on the build or design.

2. Installation and Commissioning Instructions

These must refer to up-to-date standards – in Germany, for example, DIN EN 60076 (equivalent to IEC 60076:2011 ff.), or SN EN / SIA standards in Switzerland, depending on the application field.

3. Environmental Conditions and Permitted Operating Limits

This includes acceptable temperature ranges, humidity levels, altitude, and short-term overload capacity – all crucial for safe operation and accurate planning.

4. Internal Wiring Diagrams and Connection Layouts

Often custom-made for the specific unit – and critical for seamless integration into your substation infrastructure. Any error or omission here can lead to costly commissioning delays.

5. Routine Test Results (Factory Acceptance Tests)

These form the technical foundation for acceptance by investors, DNOs (Distribution Network Operators), and statutory authorities.

6. Maintenance and Cleaning Instructions

With intervals, tools, and recommended procedures clearly specified. Particularly important for oil-filled units, where oil ageing, loss and regeneration must be monitored.

7. Warranty Terms

Clearly stated and legally compliant: what’s covered, what isn’t, and how to proceed in the event of a fault.

8. Disposal Instructions

In line with EU directives WEEE, RoHS, etc., including handling guidance for waste oil, magnetic cores, windings, and casing components.

But what about the test report?

The routine test report – also referred to as the factory acceptance test (FAT) – is an essential part of the operating manual. It cannot be replaced by a mere handwritten tick on the enclosure.

This document confirms that the specific transformer (not just the model series) meets the stated performance values and safety criteria.

Standard contents include:

• Winding Resistance Measurements
  For each winding, corrected to reference temperature – vital for long-term service diagnostics.

• Short-Circuit Voltage / Impedance Measurements
  Directly affects network protection and must be known to calibrate protection relays properly.

• High-Voltage Withstand Test (50 Hz)
  Verifies the insulation’s dielectric strength – mandatory for all transformers rated above 1 kV.

• No-Load Losses and No-Load Current
  Should match the datasheet values. Any deviations could indicate manufacturing flaws or out-of-spec tolerances.

In certain scenarios – particularly where higher technical or environmental demands apply – the test protocol may also include:

• Type Tests in accordance with EN 60076-1,

• Noise Level Measurements, especially for use in urban areas,

• Leakage Current Tests, relevant for EMC compliance,

• Real-Condition Short-Circuit Tests, to prove mechanical robustness.

Why it matters

A transformer without its operating manual is like an aircraft without its flight log – you might take off, but you’re not certified to land.

In the next section, we’ll explore what individual test protocols must contain, how they tie into grid compliance, and why documentation can’t be treated as paperwork – because it’s protection, reliability, and your long-term peace of mind.

Take a look at how we test our transformers at Energeks. You won't find this information on Google:

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

Why Transformer Documentation Isn’t Just a Local Matter – It’s an International Passport

Whether your transformer is bound for Bavaria, Birmingham or Bergen, one truth remains: proper documentation isn’t a bureaucratic nuisance – it’s your device’s visa to operate legally, safely and efficiently.

In countries like Germany, Austria and Switzerland, the documentation expectations are crystal clear and strictly enforced. A medium-voltage transformer without its full suite of documents – including operating manuals, factory test certificates, and CE compliance declarations – is like trying to board a flight with no passport, no ticket and a scribbled boarding gate. The result? No commissioning by the TÜV, no grid connection from your local DSO (like Bayernwerk or E.DIS), and no payout from your insurer if things go wrong.

Move west to the UK or north to Scandinavia, and the principle shifts slightly in name but not in weight. In these regions, what’s expected is the as-built documentation – a full and final technical dossier that must be handed over to the client upon project completion. Forget to include a type test or wiring diagram, and you’re not just risking a frown from the engineer – you may face contractual penalties or even be disqualified from manufacturer warranties.

And what about across the pond? In the United States, the standards may run on ANSI/IEEE rather than IEC, but the demands are no less firm. For any transformer above 600 V, Operation & Maintenance Manuals and Factory Test Reports are non-negotiable. Major players like GE Grid Solutions, ABB USA and Siemens Energy US won’t touch a project without them.

So what’s the common thread? Across borders and time zones, full documentation is the golden key. It unlocks commissioning, grid integration, safety assurance, and long-term reliability – and ensures your transformer doesn’t become a very expensive lawn ornament.

How to Verify if Your Documentation Is Complete

Before signing the handover or acceptance protocol for a medium-voltage transformer, we recommend checking the following:

• Does the documentation include all key components listed above?

• Do the values match the nameplate and the product datasheet?

• Have the measurements been taken for the exact serial number of the delivered unit?

• Is the documentation signed and stamped by the original manufacturer?

A complete operating manual is not just a formality – it’s your legal, technical, and operational shield.

4. Formal Requirements from Grid Operators – Documents That Decide Whether Your Transformer Connects to the Grid

You’ve received the technical datasheet, operating manual and factory test report for your medium-voltage transformer? Excellent – but you’re only halfway there. Just as important – and in practice often even more decisive – are the formal requirements of the relevant Distribution System Operator (DSO), who is responsible for the technical approval and grid connection of your equipment.

Depending on the country, region and network characteristics, operators may impose varying requirements for connection documentation, certification, and the format of technical data. And these differences aren't just cosmetic – they are rooted in national legislation, safety regulations, system compatibility and operational accountability.

The bad news?

The requirements vary widely.

The good news? They’re predictable – and you can prepare for them in advance.

What do grid operators typically expect?

DSOs generally require a complete, standards-compliant and internally consistent documentation package, usually consisting of the following:

Certificate of Compliance with International Standards

Typically, compliance with the IEC 60076 or DIN EN 60076 series (Europe) is required, or ANSI/IEEE standards for non-European markets.
The certificate must confirm that the transformer meets all structural, electrical and operational requirements of the relevant standard.

Factory Routine Test Report

A mere declaration is not enough – concrete test results for the delivered unit must be provided. Ideally, these are conducted in the presence of a DSO representative or an accredited independent testing body (depending on the country).

Declaration of Conformity with Regulations

This document must confirm that the product complies with:

– Low Voltage Directive (LVD),
– Electromagnetic Compatibility Directive (EMC),
– RoHS Directive (Restriction of Hazardous Substances),
– Ecodesign Directive (Energy Efficiency / EcoDesign).

Outside the EU, equivalent national declarations or certificates from recognised organisations (e.g. UL, TÜV, SGS) may be required.

Installation Documentation – Technical Description and Wiring Diagrams

This includes details of the site, installation method, connection type, operating data and internal wiring. It is often submitted as an annex to the grid connection request or the formal acceptance process.

Proof of Compliance with Technical Oversight Requirements (if applicable)

For transformers with conservators, flammable insulating mediums or installations in explosive environments, evidence may be required that the equipment has been registered or reported to a technical regulatory authority.
Within the EU, this usually involves CE documents with full construction-level documentation.

Certificates of Manufacturer or System Integrator Quality Assurance

Commonly accepted proofs include:

– ISO 9001 (Quality Management),
– ISO 14001 (Environmental Management),
– ISO 45001 (Occupational Health & Safety),
– and factory audit certificates or conformity approvals based on market requirements.

Operating Manual + Wiring Diagrams + List of Auxiliary Devices

If the transformer is part of a compact or containerised substation, the DSO may request full documentation for all components delivered with the unit:
Switchgear, protection devices, meters, secondary circuits, measurement systems, etc.

What happens when documentation is incomplete?

Unfortunately, these situations occur more often than you might expect. The consequences?

• Rejection of technical approval by the grid operator,

• Costly rework or repeated testing,

• Delays in grid connection – sometimes lasting weeks,

• Contractual penalties for the investor, loss of warranty for the contractor,

• And in the worst-case scenario: dismantling or complete replacement of the unit.

Only those who understand the requirements can prepare confidently.
In the next section, we’ll show you how to structure your documentation to ensure smooth approval – both nationally and internationally.

We invite you to read our article:

Grid connection: challenges, barriers, and future solutions

What Can You Do to Avoid These Issues?

1. Identify the grid operator’s requirements before the project even starts
Even in regions with supposedly harmonised standards, it’s always worth downloading or requesting the current version of the DSO’s technical connection requirements (known in Germany as Technische Anschlussbedingungen, or TAB). These documents define exactly what your transformer needs to comply with to be connected to the local grid.

2. Inform the manufacturer or supplier about the intended installation site and the specific DSO requirements
From the very first request for quotation or tender documentation, make it clear that the documentation must be delivered in the format required by the relevant grid operator. Surprises can be charming – but not when they derail your acceptance protocol.

3. Check that the quote includes a complete documentation package
Look carefully at the proposal:
– Is the documentation offered in both printed and digital format?
– Are all required test reports included (routine tests, and where applicable, type tests)?
– Are the wiring diagrams complete?
– Are all components clearly labelled with reference to the transformer nameplate?

4. Request a full list of materials and components with certificates and approvals
This includes cables, bushings, transformer oil, protection relays, liquid level indicators and temperature monitoring devices.
Some DSOs demand not just a parts list, but also compliance documents (e.g. CE, IEC, or national test marks).

“Ready-to-Connect” Documentation – A Standard That Pays Off

More and more manufacturers now offer documentation in a “Ready-to-Submit” or “Ready-to-Connect” format. What does this mean in practice?
You don’t have to compile the documents yourself, chase additional certificates, or sign off forms at the last minute. The complete documentation package is delivered pre-checked, fully coordinated and signed by authorised parties – ready to be handed over to the DSO or inspector.

If you value a smooth grid connection process, fewer errors and a predictable approval timeline, it’s worth including this as a contractual requirement when placing your order.

In the next chapter, we’ll address the question of registration with technical oversight authorities and CE labelling – and how to ensure that your transformer is legally approved for operation across the European Union (and beyond).

5. Technical Oversight and CE Marking – When It’s Mandatory, and When It’s Just a Formality

It’s a question many investors and project managers don’t ask until the very last minute:
“Does this transformer actually need to be registered or inspected by an authority?”
The knee-jerk response is often: “Well, it’s not a steam boiler, is it?”
And that’s precisely where problems tend to begin.

Depending on the transformer type, location, and operating environment, a medium-voltage transformer may very well be subject to inspection, registration or even approval – in Germany, Austria, Switzerland, and many other countries.

When Does a Transformer Require Notification or Oversight?

Here are some common scenarios where notification or regulatory registration may be required:

Use of flammable or environmentally hazardous fluids
For example, with hermetically sealed units or conservator transformers filled with mineral oil, silicone fluid or natural esters.

Installation in critical infrastructure
Hospitals, airports, tunnels or military facilities often fall under strict supervisory regulations.

Operation in potentially explosive atmospheres (ATEX zones)
In sectors like chemicals, refineries or mining, all electrical equipment must meet special safety requirements.

Presence of safety-relevant components
If the transformer is equipped with pressure relief valves, monitoring sensors, oil level indicators or advanced ventilation systems, it may be classified as subject to inspection.

What Documents Are Needed for Notification or Certification?

Depending on the local regulations, the following may be required:

• Notification form including registration number, equipment designation and site address

• Engineering drawings of the tank, safety devices and protective housing

• Description of environmental and operating conditions (temperature, humidity, explosion protection)

• Risk assessments or safety data sheets (e.g. for PCB content)

• Certified translations of technical documents (if required)

• Factory audits by accredited inspection bodies

• Evidence of regular maintenance and safety inspections

What Happens If You Skip the Registration or Certification?

Failure to register or certify a qualifying transformer can have serious consequences:

• Rejection of commissioning or connection to the grid

• Orders to dismantle or remove the equipment

• Denial of insurance claims in case of failure or damage

• Fines or administrative penalties

• Criminal liability in the event of endangerment to human life or the environment

And What About the CE Marking?

The CE mark ("Conformité Européenne") indicates that the product complies with relevant EU directives.
For medium-voltage transformers, it’s not just a sticker – it’s a legal obligation if the unit is to be placed on the EU market or operated within the EU.

Key directives include:

• Low Voltage Directive (LVD) 2014/35/EU

• EMC Directive 2014/30/EU

• RoHS Directive 2011/65/EU

• EcoDesign Directive 2009/125/EC + Regulation (EU) 2019/1783

What’s required?

• A signed EU Declaration of Conformity from the manufacturer or authorised EU representative

• A list of applied harmonised standards, such as IEC/EN 60076 or EN 50588-1

• The unit’s serial number, model and type

• Contact details of the responsible party within the EU

Better to Ask Early Than Explain Late

Before placing your order, clarify the following:

• Does this transformer require notification or oversight under local law?

• Will the supplier provide full CE documentation – and, if needed, national registration paperwork?

• Is the CE mark clearly displayed on the nameplate?

Whether your unit is headed for Germany, Poland or elsewhere, one thing is certain:
Documentation and regulatory compliance are what stand between your transformer and legal operation.

Because a transformer isn’t just made of steel, copper and oil.
It also carries responsibility

6. Operating and Warranty Documentation – The Transformer’s “Passport” for the Next 30 Years

It’s been installed, connected and energised – your transformer begins its new life in a substation, switchroom, factory hall or photovoltaic plant. But don’t be fooled: this doesn’t mean the paperwork is over. On the contrary – this is where the long-haul journey truly begins.

From this moment on, operators, maintenance teams and service technicians rely on a completely different set of documents – not for commissioning, but for daily operation, emergency response, scheduled inspections and long-term servicing.

This section explains which documents should always accompany a medium-voltage transformer to ensure safe and forward-looking operation – not just today, but in 5, 15 or even 25 years. Because while a transformer may seem like a silent background actor, its life cycle is long. And every act in the script deserves proper documentation.

What Belongs in the Operating Documentation for a Medium-Voltage Transformer?

1. Warranty Terms – Clear, Specific and Complete

Good warranty documentation is about more than just duration. It should include:

• Coverage period (typically 24 months, up to 60 months for premium manufacturers),

• Claims process: whom to contact, what info to provide, format of fault reporting,

• Contact details for technical support or authorised service partners,

• Clear exclusions: e.g. unauthorised modifications or missed maintenance intervals.

Internationally, such documents are often titled Limited Warranty Statement (US, UK) or Manufacturer Warranty Terms in Europe.

2. First Energisation Guide and Maintenance Recommendations

Even if the unit arrives “ready to run”, energisation should be a structured process – especially for oil-filled or hermetically sealed transformers.

Documentation should cover:

• Pre-energisation steps (e.g. earthing checks, insulation resistance, tank venting),

• Seasonal, annual and multi-year maintenance intervals,

• Actions for oil contamination, leakage or overheating,

• Guidelines for operation in demanding environments (e.g. high humidity, dust, ATEX zones).

EU standards typically reference IEC 60076-7 and EN 60505 as the basis.

3. Operating Logbook – The Long-Term Memory of Your Transformer

Not always required, but incredibly valuable – a logbook (ideally digital and printable) should include:

• Scheduled maintenance records,

• Service visits and repair notes,

• Oil level and temperature measurements,

• Overload or disturbance events,

• Notes on faults and corrective actions taken,

• Names of inspecting engineers or technicians.

This documentation helps verify regular care and supports warranty claims and preventive maintenance planning.

4. Overload Guidelines, Thermal Stress and Oil Deterioration

Transformers can be overloaded – but only for defined durations and within safe limits.

Your documentation should include:

• Overload curves and permissible durations,

• Critical temperature thresholds and actions required,

• Oil condition indicators (colour, pH, dissolved gases),

• Contact details for DGA (Dissolved Gas Analysis) and furan tests.

In DACH countries, DGA and furan testing are standard practice for units >1 MVA.

5. End-of-Life Disposal Guidelines – Planning for Decades Ahead

Even if dismantling is decades away, disposal instructions should be clear from day one – especially for components with environmental implications:

• Oil: does it contain PCBs? Can it be regenerated?

• Windings: copper or aluminium – recyclable?

• Tank, magnetic core and insulation: how to handle safely?

In the EU, the WEEE Directive (2012/19/EU) applies. In the Americas, national agencies like the EPA issue strict rules on PCB handling and disposal.

6. Safe Operating Actions – What Can the Operator Actually Do?

To protect both staff and warranty validity, the documentation should clearly differentiate between:

• Permitted actions by operators: checking oil level, cleaning insulators, reading nameplate.

• Specialist-only tasks: tap changer adjustment, sensor replacement, relay calibration.

Many manufacturers make their warranty conditional on proper handling by qualified personnel.

Without Operating Documents, a Transformer Is Like a Car Without a Service Manual

It might run for a while – but no one knows for how long.
A well-prepared set of operational documents:

• Ensures long-term safety and quality control,

• Reduces the risk of unexpected failure,

• Simplifies troubleshooting and emergency repair,

• Protects the interests of operators, service teams and manufacturers alike.

In short: documentation isn’t paperwork – it’s peace of mind.

Documentation is not bureaucracy. It's safety, time – and peace of mind.

A transformer is more than a technical device.

It’s a promise – of continuity, efficiency and operational security. But that promise only holds when there’s more behind the steel, the windings and the oil: a complete, structured and understandable set of documentation. One that speaks a common language – to investors, grid operators, inspectors and service technicians alike. One that leaves no room for guesswork.

At Energeks, we believe that quality starts in the details. That’s why we deliver our medium-voltage transformers not just with a nameplate – but with a story, a future, and… a phone number where someone will actually pick up the call when it matters most.

If you're looking for more than just a product – if you want the confidence that everything is ready for commissioning, grid connection and long-term operation – we invite you to explore our current range:

→ View our transformer catalogue

Have questions? Need a sample document or a commissioning checklist?

We’re happy to share our expertise.

Join our growing community on LinkedIn, where we talk openly about documentation practices, utility requirements, and transformers without secrets:

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Thank you for helping us set a new standard.
You are shaping a market where quality is no longer a bonus – it’s the baseline.

References:

IEC Standards Database – IEC 60076 series: Power Transformers

EU Legislation: CE Marking & Technical Documentation Requirements

IEEE Standards Association – Transformers and Electrical Equipment Standards