Safe Operation of Battery Energy Storage Systems: Electrical Hazards and Risk Management

Understanding the hazards involved in operating these systems is essential for keeping both personnel and the electrical installations safe. Energy storage is now a cornerstone of the energy transition and trying to keep power systems stable. But as these installations grow in scale and become more deeply integrated into the grid, the conventional approach to electrical safety simply isn’t enough anymore. 

In a BESS, several things are happening at the same time: 

• both DC and AC voltages are present 

• short-circuit currents can be dozens of kilo amps 

• there’s a chemical energy source on board (Li-Ion, LiFePO₄, NMC) 

That combination forces us to look at the hazards holistically. Unlike conventional electrical installations, a BESS involves coupled electrical, thermal, and chemical phenomena and that significantly increases the complexity of any risk analysis. 

Battery Energy Storage System Safety: Key Electrical Hazards 

Operating an energy storage system brings with it several major hazard categories, and they all interact with one another. The most important are: 

• electric shock (both AC and DC) 

• arc flash burns (both AC and DC) 

• fire and thermal runaway 

• external short circuits 

• chemical hazards (liquids and gases) 

A Closer Look at Each Hazard 

DC Electric Shock 

DC electric shock is a particularly serious concern in energy storage systems, mainly because voltage levels keep climbing — often above 800 VDC. Unlike alternating current, direct current has no natural zero crossing, which means muscle contraction is continuous rather than intermitten. The longer current keeps flowing through the body, the greater the risk of serious tissue damage, cardiac disturbance, and deep internal burns. On top of that, AC voltage is present in a BESS as well. 

Shock can occur during: 

• routine operational work 

• damage to battery modules (where the voltage exceeds 120 VDC) 

• insulation failure 

It’s also worth remembering that, under EN50110, isolating the work area doesn’t fully apply when you’re working near batteries. We can’t completely “switch off” or discharge a battery’s energy. In practice, the protections we rely on are: 

• defined procedures for working around batteries 

• personal protective equipment 

• engineering solutions (battery sectioning, modular design, module-level protection, and so on) 

Arc Flash in BESS 

An arcing fault is a real hazard during BESS operation. DC voltages here exceed 120 VDC and, as of today, reach up to 1500 VDC (the low-voltage limit for DC under EN 50110). In DC installations, the energy released by an arc depends very heavily on the short-circuit current and on the source’s ability to sustain the arc. Arcing faults can be triggered by: 

• insulation damage 

• operational work (human error) 

• installation errors 

• environmental factors (moisture, contamination, flooding) 

• internal and external short circuits 

Unlike a bolted (metallic) fault, an arcing fault carries a certain arc impedance, and that has real consequences: 

• arc-fault currents are harder to detect because they are lower 

• they’re harder to interrupt unless you use solid state circuit breakers 

• detection and clearing can take longer time  

The distinctive features of an electric arc include: 

• temperatures reaching up to 19,400 °C 

• light radiation (UVA/UVB) 

• a pressure rise (shock wave for now is not DC issue, for now) 

• ionization and heating of the surrounding air 

• ejection of molten metal 

• shrapnel travelling at speeds up to 1,100 km/h 

• a sound wave reaching as much as 160 dB

Thermal Runaway 

Thermal runaway is one of the most serious hazards in any energy storage system. It happens when a cell loses control of its own thermal balance — most often triggered by mechanical damage, electrical overload, high temperature, or internal defects. The graphic below lays out the causes, the mechanism, and the consequences in a very straightforward way. 

The nature of the hazard depends on the cell technology and chemistry. The most vulnerable cells are made with: 

• Lithium Cobalt Oxide (LCO) 

• Nickel Manganese Cobalt (NMC) 

The least vulnerable are: 

• Lithium Iron Phosphate (LFP) 

• Solid-State Batteries (solid electrolyte) 

In battery energy storage systems, a particular concern is the presence of oxidizing substances. Under fault conditions (thermal runaway,for instance), these can significantly intensify a fire and allow it to keep developing independently of any oxygen from the surrounding air. Under the requirements of NFPA 400 and NFPA 704, systems containing such materials should be properly classified and labelled,and their operation should account for scenarios involving the release of oxidizing substances. 

Thermal runaway is set off by: 

• Mechanical damage — puncture, crushing, internal short circuit 

• Electrical overload — overcharging, over-discharging, excessive current 

• Thermal effects — high ambient temperature, fire, loss of cooling 

• Internal cell defects — manufacturing flaws that lead to a short circuit over time 

Short Circuits in DC Circuits 

Short circuits in energy storage systems are a special case because of the battery cells’ very high short circuit current capability. The focus here is on battery energy storage used in industrial and grid-scale installations. To give a sense of scale: utility-scale storage is built from 20-foot BESS containers, typically rated up to 5 MWh / 1300 VDC eg. (12×1P416S) — meaning 12 clusters of 416 modules at 3.2 V each. 

Systems built from these containers reach truly large figures: 

• Edwards & Sanborn Solar — USA, California: 821 MW / 3,287 MWh 

• Collie Battery — Australia: 560 MW / 2,240 MWh 

• Bisha BESS — Saudi Arabia: 500 MW / 2,000 MWh 

In large storage systems, short circuits matter not only locally but at the system level too. These systems also serve a range of roles, from storing energy locally to providing fast frequency support. From the storage system’s point of view, fault current can be divided into: 

• external 

• internal 

The same split applies at the level of the individual cell — that is, short circuits occurring outside the cell, and those occurring within it (for example, when dendrite formation punctures the electrolyte separator). 

Unlike conventional power systems, fault currents in a BESS are largely shaped by the characteristics of the power conversion system electronics. This affects both the energy of an arc flash and how effectively that arc can be detected. 

The operational consequences of short circuits include: 

• accelerated cell degradation 

• shutdown of the installation 

• hazards during operation 

The system-level consequences, for large installations, can include: 

• disruption to grid stability 

• cascading trips 

• fire in the installation 

Standards and Regulations — EU, USA, China 

Awareness of electrical hazards is reflected in a whole range of legal regulations at both the European and national level: 

• Directive 89/391/EEC of 12 June 1989, on measures to encourage improvements in the safety and health of workers at work. Article 6.2 sets out the general principles of hazard prevention. 

• Regulation of the Minister of Energy of 8 June 2021, on occupational health and safety for energy equipment (Polish Journal of Laws, 2021, item 1210). 

• EN 50110-1 — Operation of electrical installations, Part 1: General requirements. 

A number of international standards have also been developed to address protection against arc-flash hazards: 

• IEC 61482-2 — Live working: protective clothing against the thermal hazards of an electric arc, Part 2: Requirements 

• IEC 61482-1-1 — Live working: protective clothing against the thermal hazards of an electric arc, Part 1-1: Test methods, Method 1 — Determining the arc parameters (ATPV, EBT50, ELIM) for flame-resistant clothing materials 

• NFPA 70E — Handbook for Electrical Safety in the Workplace (2024 edition) 

• IEEE 1584-2018 — IEEE Guide for Performing Arc-Flash Hazard Calculations 

• ISSA Guide — Guideline for the selection of personal protective equipment when exposed to the thermal effects of an electric fault arc (2011) 

• DGUV 203-077 — Thermal hazards due to electric fault arcing: guide for selecting personal protective equipment (2021) 

When it comes to energy storage specifically, the following groups of standards are especially important and serve as a valuable knowledge base: 

Europe / IEC: 

• IEC 62933 (series) — Electrical Energy Storage (EES) systems (e.g. IEC 62933-1-1:2018 — Terminology; IEC 62933-5-2 — Safety requirements) 
• IEC 62619:2022 — Secondary cells and batteries containing alkaline or other non-acid electrolytes: safety requirements for secondary lithium cells and batteries used in industrial applications 
• IEC 62485 (series) — Safety requirements for secondary batteries and battery installations (e.g. IEC 62485-2:2018 — Stationary batteries) 

USA: 

• NFPA 855:2023 — Standard for the Installation of Stationary Energy Storage Systems 
• UL 9540 — Energy Storage Systems and Equipment 
• UL 9540A — Test Method for Evaluating Thermal Runaway Fire Propagation in Battery Energy Storage Systems 

Chiny:

• GB/T 36276-2018 — Electrochemical Energy Storage System: Lithium-ion Battery Technical Specification 
• GB/T 34131-2023 (updated version) — Technical Specification for Electrochemical Energy Storage Power Station 
• NB/T 33015 (series) — Technical standards for electrochemical energy storage systems in power applications 
• NB/T 33004 — Technical specification for grid-connected operation of electrochemical energy storage systems 

Area	Europe / IEC	USA	China
General BESS scope	IEC 62933 — Electrical Energy Storage Systems (EES)	UL 9540 — Energy Storage Systems and Equipment	GB/T 34131 — Technical Specification for Electrochemical Energy Storage Power Station
Battery safety (cells and modules)	IEC 62619 — Safety requirements for lithium batteries (industrial)	UL 1973 — Batteries for Use in Stationary Applications	GB/T 36276 — Lithium-ion Battery Technical Specification
System installation and integration	IEC 62485 — Battery installations	NFPA 855 — Installation of Energy Storage Systems	NB/T 33015 — Energy storage system technical requirements
Thermal runaway / fire testing	IEC 62933-5-2 — Safety requirements (system level)	UL 9540A — Thermal Runaway Fire Propagation Test	GB/T (partially covered within system-level testing)
Operational safety (OHS)	PN-EN 50110-1 — Operation of electrical installations	NFPA 70E — Electrical Safety in the Workplace	GB 26860 — Safety work regulations for electric power industry
Arc flash	IEC 61482 — Arc-flash protective clothing	IEEE 1584 — Arc-Flash Hazard Calculations + NFPA 70E	No dedicated standard — indirect approaches used

To ensure an appropriate level of safety,  law requires us to maintain a range of instructions and procedures — and these apply to energy storage installations too: 

•  Electrical Safety Plan (various countries use different names) 

•  Electrical  Equipment Operation Instruction (equipment specific manuals) 

•  Distribution Network Operation and Maintenance Instruction (for distribution system operators) 

• Workstation and general safety instructions 

• Live-Working Procedure for electrical power equipment (where required) 

Risk Management in BESS Operation 

Effectively managing arc-flash risk calls for a systematic approach, made up of the following stages: 

• assessing the arc-flash hazard 

• assessing the electric-shock hazard 

• assessing the condition of the equipment and installation 

• making an initial selection of the required PPE 

• assessing the risk and selecting the PPE required for the specific work being carried out 

The first stage of the risk management process is identifying the potential locations where an arc-flash hazard could occur. Doing so lets us: 

• determine the arc-flash energy level 

• determine the arc flash boundary 

• decide on further actions and recommendations 

Once the hazard levels have been identified, the next step is to assess the shock risk — something that depends heavily on how the installationis built and on the work being performed. For example, by: 

• determining the voltages involved 

• determining which work is carried out near live parts 

• determining which work is carried out on live parts 

Then, by estimating how likely electrical hazards are for each individual task and operational activity, we can tailor our measures to: 

• the level of the hazard 

• the degree of exposure to it 

• the condition and state of the equipment 

• the work being carried out 

This approach — developed by MR Power Systems as the “Simplified Task-Based PPE Risk Matrix” — makes it possible to control the protective measures used when working on electrical power equipment. 

Effective risk management requires a systemic approach, and it begins with identifying and defining the hazards. From there, we naturally want to control and limit our exposure to whatever hazards are present. This is where the Hierarchy of Controls from NFPA 70E-2024 comes in, ordering the available actions from most effective to least: 

• eliminate the hazard 

• reduce the energy 

• engineering controls 

• awareness and training 

• administrative controls 

• personal protective equipment 

Case Study: Victoria Big Battery 

One of the best-known incidents involving energy storage was the fire at the Victoria Big Battery (300 MW / 450 MWh) in Australia in 2021. It happened during the system’s commissioning tests, and it stands as an important example of the risks specific to large-scale BESS. 

The direct cause was an internal fault in one of the battery modules. A loss of coolant tightness was followed by a short circuit, which led to localized overheating and then triggered thermal runaway. With the thermal balance lost, the phenomenon spread to neighbouring modules within the container. 

Despite the protective systems in place — detection systems and fire-suppression measures among them — the incident developed into a prolonged fire that burned for several days. Gas emissions and intense thermal effects were observed throughout, which forced a safety exclusion zone to be set up around the installation. Analysis of the event points to several key takeaways: 

• an incident can be initiated at the level of a single module 

• thermal runaway propagates within the container 

• standard suppression systems may not be enough to stop the process, but they do help limit the scale of the fire and its spread 

• early detection and module separation are critical 

• BESS designs should account for escalation scenarios, not just single-point failures 

The Tesla Big Battery case shows that hazards in energy storage are systemic in nature, and they demand an approach that covers both the design and the operation of the installation. 

Conclusion 

Energy storage systems introduce a new level of complexity to electrical-power hazards — one that arises from the combination of DC short circuits, the difficulty of detecting arc faults, voltages above 1000 VDC, and the risk of an incident escalating to the point where a cell loses its thermal balance. Taken together, these factors mean the conventional approach to electrical safety is no longer sufficientEnsuring safe operation calls for an integrated approach that spans the design phase, the operation of the installation, and the analysis of hazards and risk. We should treat BESS containers like installations rather than products. 

Author: Hency Roballo

Primary topic: Arc Flash Risk Assessment

Standards mentioned: NFPA 70E, IEEE 1584, IEEE 1584.1, CSA Z462, OSHA 1910.269, DGUV 203-077, IEC 60909, IEC 61363

Reading time: 9 min read

What Is Arc Flash and Why Is It Dangerous?

Let’s be honest: the risk of arc flash is still widely underestimated or misunderstood. When people hear the term electrical hazard, they often think only of electric shock. While electric shock
is undeniably dangerous, arc flash represents a completely different—
and often more devastating—threat. Unlike shock hazards, an arc flash
can release an enormous amount of energy in a split second, exposing
workers to extreme heat, explosive pressure, and molten metal. For anyone
working in the electrical industry, electrical maintenance, electrical
safety, or related fields, misunderstanding or overlooking the danger
of arc flash can have severe or even fatal consequences.

Electrical hazards are present in our daily lives, so it’s crucial to
be aware of them and take the necessary precautions to ensure we get
home safely from work.

The aim of this article is to explain how arc flash risk assessment
process looks like, from the initial contact to installing label on the
electrical panel door. But before we get into the process, let’s make
sure everyone understands what it’s all about.

Electrical Hazards vs Electrical Risk – Key Differences

These terms may sound similar, but for those who regularly work in the
electrical sector, it’s essential to know the definition. An electrical hazard is the source of the potential to cause harm, for example, damaged equipment that could cause a short circuit or an arc flash. On the other hand, an electrical risk is the likelihood and severity of
harm when a person is exposed to an electrical hazard.

Types of Electrical Hazards in the Workplace

When it comes to electrical hazards, the list is longer than we think.
Below are some examples of electrical hazards:

• Electric shock
• Arc flash hazard
• Arc blast
• Electrostatic discharge
• Electrical fires
• Electromagnetic field exposure
• Explosions in Ex areas
• Burns from hot surfaces of energized components
• Induced voltage
• Battery fires and explosions

Arc Flash: Real Risks, Real Costs

Most of the safety training focuses on shock hazards. Arc flash often gets only a slide,
maybe a warning label without important information, sometimes just a sticker for electric shock, and then everyone moves on. That’s a problem—because in terms of raw destructive potential, arc flash is in a completely different category.

Here are some numbers that tend to attract people’s attention:

An arc flash is not just an electrical fault but a violent arc flash phenomenon—a rapid, uncontrolled release of energy that resembles an explosion more than a typical electrical hazard. In milliseconds, temperatures above 19,000 °C, roughly 15 times hotter than volcanic
magma, can vaporize copper and force it to expand tens of thousands of times its original volume.

This sudden expansion generates powerful pressure waves capable of knocking workers to the ground and hurling molten metal at extreme speeds, while intense thermal radiation causes severe burns without direct contact. Blinding light, deafening noise,
and clouds of superheated gases and metal vapors further compound the danger. Unlike electric shock, proximity alone is enough to underestimate this phenomenon means overlooking one of the most destructive hazards in electrical work.

And the costs aren’t just human. A few real-world examples

• OVH SBG1 — arcing fault in a UPS battery room: €105 million loss
• Ocado warehouse, Andover UK — battery charger fault: £110 million damage + £132k fire-fighting costs
• Notre-Dame Cathedral — officially attributed to an electrical fault: €552 million reconstruction cost

The point isn’t to terrify anyone. It’s to establish that this is worth
doing properly.

Hierarchy of Controls in Electrical Safety

Hierarchy of Controls is a safety framework used to reduce or eliminate exposure to hazards in the workplace. It ranks control measures from the most effective to the least effective, helping organizations prioritize solutions that provide the highest level of protection.

Working from most effective to least effective

1. Identification: We could say that the first step is to identify the risks in the workplace. Once electrical hazards are recognized, the next step is to reduce or eliminate them through engineering controls. However, personal protective equipment is still mandatory. The question is how to correctly understand and apply this process in the workplace.
2. Elimination: No live work. LOTO. Arc quenching devices. If you can de-energize it, de-energize it. This is always the preferred option.
3. Substitution: Lower operating voltage. Arc-resistant switchgear. If you can change the system to reduce the inherent hazard, do it at design stage.
4. Engineering Controls: Physical barriers. Remote operation. Isolating people from the hazard spatially. Things that don’t depend on human behavior to work.
5. Awareness: Arc flash labels. Training. People need to know the hazard exists and understand what the labels mean. This is necessary but not sufficient on its own.
6. Administrative Controls: Electrical safety plans. Work instructions. Written procedures for how tasks get done safely.
7. PPE: The correct arc-rated clothing and equipment for the calculated incident energy. Essential, but it only protects the person already exposed to the hazard.

A good arc flash study informs all of these levels, not just the PPE selection.

In conclusion, when an employer implements all elements of the Hierarchy of Controls, the level of risk can be significantly reduced or even eliminated. As a result, the tasks performed by employees transition from relying on the least effective protective measures to the most effective and safest controls, leading to a substantially safer work environment.

How is it understood in the workplace?

In practice, many workplaces are familiar with PPE and administrative controls because they are easier to implement. However, higher-level controls such as elimination, substitution, and engineering controls are often underestimated or overlooked due to cost, design constraints, or lack of early planning.

Do people know about it?

While the Hierarchy of Controls is widely recognized in safety standards and professional guidance, not everyone truly understands or applies it correctly. In many cases, it is treated as a theoretical concept rather than a practical decision-making tool. Improving awareness and
application of the hierarchy is essential for managing high-energy hazards such as arc flash effectively.

Key Arc Flash Standards (NFPA 70E, IEEE 1584, OSHA)

Regarding arc flash performance, it is necessary to be familiar with and apply the relevant standards; the most important ones are listed below:

Standard	Description
NFPA 70E (2024)	Standard for Electrical Safety in the Workplace
IEEE 1584-2018	Guide for Performing Arc-Flash Hazard Calculations
IEEE 1584.1-2013	Guide for the Specification of Arc-Flash Hazard Calculations
CSA Z462-2024	Workplace Electrical Safety
EPRI TR-2011	Arc Flash Hazard Analysis Methodology
OSHA 1910.269 Appendix E	Protection From Flames and Electric Arcs
DGUV 203-077	Selection of Personal Protective Equipment for Electrical Arc Hazards

Supporting standards for the short-circuit side: IEC 60909 (general), IEC 61363 (marine and offshore). ANSI, IEEE, EN, BS standards as appropriate to the system being studied.

It is important to clarify that each country has its own standards. In general, some approach limits and protection zone requirements may change according to national regulations; however, the calculation methodology is usually the same as, or based on, IEEE 1584-2018.

Step-by-Step Arc Flash Risk Assessment Process

Here is how a proper arc flash risk assessment gets done.

Step 1: Customer meeting:

Before initiating any analysis or field visit, it is essential to clearly define and fully understand the project scope. This requires close collaboration with the client to determine the project size, identify the applicable standards, and collect all critical information necessary
to prepare an accurate and effective offer.

Step 2: Data Collection:

Before conducting an on‑site visit for data collection, all available technical information should be reviewed, and the data‑collection format prepared. During the field visit, relevant data is collected accurately, and a safety inspection is carried out. The findings are then documented in a site report that includes observations, analysis, and safety recommendations aimed at improving workplace safety.

Step 3: System Modelling:

Develop a digital twin of the electrical network using specialized software that accurately reflects the actual installed system. The electrical model shall be created with comprehensive and precise details to ensure it faithfully represents the real-world configuration, equipment
characteristics, and operating conditions.

Step 4: Electrical Analysis Calculations.

Performance an Electrical Analysis calculations based in all standards:

• Short Circuit Analysis. IEC 60909 /ANSI
• Short Circuit Equipment Evaluation
• Selectivity Analysis to find protection issues for exiting situation and provide recommendations for improvements for future adjustments
• Arc Flash Analysis – for existing situation acc. IEEE1584 -2018 / sometimes DGUV203-077, provide recommendations for improvements for future adjustments.

Step 5: Report:

The final report includes all results, analysis tables for existing and recommended situations, different scenarios configuration, recommendations, modeling data, single‑line diagrams, and equipment labeling information, compiled and delivered in appropriate formats such as Word, PDF, and Excel.

Step 6: Customer Meeting:

It is essential to hold a meeting with the client to review the report results, discuss identified issues within the electrical installation, and present the proposed recommendations developed in accordance with the Hierarchy of Controls.

Step 7: Training:

Provide technical training on arc-flash hazards, preferably conducted on-site, with online delivery as an alternative. The training covers hazard identification, arc-flash warning labels, proper selection and use of personal protective equipment (PPE), and methods to reduce or eliminate risks through engineering controls, in accordance with the report findings.

Step 8: Final & follow up:

Overall, periodic revisions should be carried out, with results updated at least every five years or following any significant modifications to the electrical system. This process may include retraining workers and updating or replacing equipment warning labels as necessary.

Author: Dr Stan Zurek

Primary topic: HV Insulation Testing Safety

Standards mentioned: IEEE 43-2013, IEEE 95-2002

Reading time: 12 min read

Every year, engineers and technicians are electrocuted — not during high-voltage insulation testing, but after it. The equipment looks safe. The voltage meter reads zero. But inside the insulation, lethal charge is still quietly stored and the dangerous voltage is rebuilding. This post explains why, and how a new technology from Megger called RE>Act is making HV DC insulation testing safer and faster.

INTRODUCTION

Picture this: a maintenance engineer has just finished a high-voltage DC insulation test on a large motor. The test instrument shows the voltage has discharged to zero, and the operator even used independently a HV discharge stick to ensure that the voltage is indeed discharged. A few minutes later his colleague reaches in to reconnect the motor terminal — and is hit by a shock of several hundred volts. The equipment “looked” safe. But inside the insulation, a hidden charge had been slowly rebuilding.

This phenomenon — known as absorption causing recovery voltage — is well documented in several IEEE and IEC standards, yet still misunderstood by the engineers working with HV equipment every day. RE>Act, a new technology from Megger invented by the team: Paul Swinerd, Stan Zurek, Mark Tutton, Clive Taylor, and Mohineet Kaur, was created specifically to make this invisible hazard visible.

First: what is electrical insulation, really?

Every cable, motor or generator winding, transformer coil, bushing, insulator, surge arrester, and circuit breaker contains electrical insulation — the material that prevents current from flowing where it shouldn’t. Without insulation, high-voltage electricity cannot be safely contained or controlled.

But insulation is not just a passive barrier. From an electrical engineering perspective, insulation behaves like a complex circuit made up of three components working simultaneously:

Component	What it does
Resistance (R)	The classic insulation property — a high resistance means very little current leaks through. This is what insulation resistance (IR) tests measure in MΩ, GΩ, or TΩ.
Capacitance (C)	The insulation stores electrical charge, like a capacitor. This charge builds up quickly during a test and also discharges quickly. It is always dangerous when not discharged.
Absorption (A)	The most misunderstood component. Polarisation of molecules within the insulation material causes charge to be absorbed slowly — and released slowly. This is the hidden hazard.

This three-part model — known as the “equivalent Debye model” — is the key to understanding why HV testing is dangerous even after the voltage source is switched off.

The hidden hazard: what happens after the test?

High voltage is applied to a piece of electrical equipment during the test. The capacitive component charges quickly and discharges quickly when the test ends — this is the part that most discharge procedures are designed to handle, and it is easy to understand.

But the absorption component is different. It charges slowly — and it discharges slowly. Worse still, even after the capacitive charge has been discharged to zero volts, the absorption charge begins to release itself — and this release creates a recovery voltage: the terminal voltage rises again, from zero, back up to potentially dangerous levels. All by itself.

Without any external source. So the capacitance becomes charged again, and charged capacitance is always dangerous.

The confusion is made worse by how standards describe this. IEEE 43-2013 defines the absorption current as one that decays “to nearly zero” — but “nearly zero” reading will be displayed differently by various equipment. Is 0.001 mA nearly zero?

To same people it may, but in reality it is certainly not. At high voltages, this small current can still transfer a lethal charge, from the absorption branch to the capacitive branch. The gap between laboratory theory and workshop reality has safety implications.

What do the standards actually say?

Both IEEE 43 and IEEE 95 — the two main standards governing HV DC insulation testing for rotating machines — acknowledge the hazard, but offer surprisingly vague guidance on how long to wait before touching the equipment.

Read those carefully. The standards say: wait at least 2 hours. Or 4 times the test duration. And you can’t accelerate it. In practice, this means engineers face a choice: wait for hours (with no confirmation that it’s actually safe), or take a risk of confirming that the dangerous voltage is absent. But the standards don’t explain how to do that safely.

In busy maintenance environments, the pressure to get equipment back online is substantial. The lack of real-time feedback — any way to actually see whether the discharge is complete — is exactly the gap that RE>Act was designed to fill.

Introducing RE>Act — see the invisible

RE>Act stands for RE-Absorption Current Test. It’s a new inventive technology (patent applied for) integrated into the new Megger S1 and MIT 5–10–15 kV insulation testers.

The core idea is elegant: instead of disconnecting the equipment and hoping the discharge is complete, RE>Act connects a low-impedance ammeter through a discharge resistor while monitoring the actual discharge current in real time. Both the capacitive discharge and — crucially — the absorption discharge are measured and displayed as they happen.

The operator can now see the real discharge progress in real time, so the guessing is eliminated. So this “dual discharge” process can be now observed in real time by the operator.

How it works — step by step

The RE>Act display shows additional information. At the bottom it is the real-time measured current during absorption discharge. In the middle it is the voltage of the next test as selected on the equipment. The actual voltage is zero (the insulation remain short-circuited), so the RE>Act test is inherently safe by itself. However, the information about the next test voltage and the real current is used for estimation of the usable measurement range for the next test on the same insulation.

If the next expected result is in the accurate range then the next test can be started even without waiting for the full discharge. But if the next result is likely to fall in the blocked range, then longer discharge is necessary, otherwise an unknown amount of measurement error will occur. This helps in avoiding condemning good insulation as bad, or worse still approving bad insulation as good.

Real-world results

RE>Act was tested on multiple types of equipment. Even on a relatively small 50 kVA oil-filled transformer, the discharge behaviour was clearly visualised and the absorption component took significantly longer to dissipate than the capacitive component. The absorption current was above 1 nA even 20 min after the test was finished. On a 90-metre long HV cable (20 kV rated, 16 nF capacitance), the cable remained unsafe for over 25 min after the capacitive voltage had reached zero — precisely as IEEE 95 warns, but now visible and quantifiable in real time.

Operators who used RE>Act on HV motors were able to significantly improve productivity, because they could significantly reduce the 2 h blind waiting time. But more importantly – they were able to eliminate the invisible danger.

PI Predictor — faster testing without compromising safety

RE>Act solves the safety side of the equation. But the productivity is also improved, almost as an effortless byproduct of using this feature.

The Polarisation Index (PI) is a standard diagnostic test that compares the insulation resistance at 10 min and 1 min. A healthy insulation shows increasing resistance over time (good absorption behaviour). But waiting 10 min for every test — and then waiting another 40 min (or even 2 h, depending on the standard) for safe discharge — creates a significant bottleneck in maintenance schedules.

PI Predictor exploits a physical symmetry: shorter polarisation (absorption) means shorter depolarisation (reabsorption). By running a shorter polarisation test and measuring the depolarisation behaviour, the PI Predictor algorithm can predict the 10-minute PI result in typically in just half of the time.

50 min Standard PI test + discharge (10 min charge + 40 min discharge)

14 min With PI Predictor + RE>Act (5 min charge + 9 min discharge)

72% Reduction in total test time — while remaining equally safe and accurate

The test was validated on a 90 kW LV motor. The predicted PI result matched the standard 10-minute result. Total test time: 14 min vs. 50 min. For facilities running dozens of insulation tests per year — on motors, cables, transformers, generators — the productivity gains compound rapidly.

Three benefits that change how HV testing works

Benefit	What it means in practice
Safety	Visualise the complete discharge process — both capacitive and absorption — in real time. Know with certainty when it is safe to touch the equipment, rather than guessing based on a 2-hour waiting rule.
Accuracy	Quantify the correct measurement range before the next test. RE>Act shows not just whether discharge is complete, but the prospective IR range for the next test cycle on the same insulation — eliminating errors due to negative currents.
Productivity	Eliminate unnecessary “blind” discharge time. With PI Predictor, as the total test + discharge time can be reduced by up to 72% while maintaining the same safety margin and diagnostic accuracy.

Why this matters beyond the test lab

HV insulation testing is performed routinely on industrial motors, generators, transformers, and cables — in power stations, manufacturing plants, marine vessels, wind farms, and anywhere else large rotating machines or power distribution equipment is maintained.

The engineers doing this work might be experienced professionals. But experience doesn’t protect you from a hazard you can’t see, and boring routine can be dangerous. Recovery voltage — the insulation recharging itself — is invisible, silent, and can appear minutes or hours after the test ends. The fact that IEEE standards call for 2-hour waiting periods tells you everything about the severity of the risk. And that is with insulation short-circuited. Without short-circuiting the danger can remain for “indefinite” time.

RE>Act doesn’t change the physics. It makes the physics visible. And in safety-critical work, the difference between “I think it’s discharged” and “the instrument confirms it’s discharged” is the difference between risk and certainty.

Author: Dr. Ricardo Granizo Arrabe

Primary topic: Line Differential Protection (ANSI 87L)

Standards mentioned: ANSI 87L

Reading time: 8 min read

The Big Picture: Why This Matters

Europe’s electricity grid is under serious strain. Almost every major substation is running at or near its maximum capacity. On top of that, we’re connecting more and more renewable energy sources — solar farms, wind parks — which need new power lines and transformers to bring their electricity into the grid.

To keep up, engineers are adding new lines and transformers to existing infrastructure. But this creates a problem: the safety systems that protect those lines were designed for simpler setups. Now, the setups are getting more complex.

This article explains one key safety system — called Line Differential Protection (or ANSI 87L) — and how it’s being adapted to work in these newer, more complicated configurations.

1. What Is Line Differential Protection?

Think of a power line like a water pipe. If you measure the water going in at one end and the water coming out at the other, they should be equal. If they’re not — some water is leaking somewhere.

Line Differential Protection works the same way with electricity. Sensors called Current Transformers (CTs) measure the current (electricity flow) at both ends of a protected section of line. Under normal conditions, what goes in equals what comes out. If there’s a difference — a fault (like a short circuit or a break in the insulation) — the system detects it and automatically switches off that section to prevent damage or danger.

Why is this important?

Standard Line Differential Protection uses two measurement points (one at each end of the line) and works very well for simple, straight lines. The challenge is: what happens when the line isn’t simple anymore?

2. Three New Challenges

Modern grid development is creating three types of configurations that go beyond the classic straight-line setup:

Challenge	What it is	Main problem
A	A line that splits into a T-shape (three branches)	Three ends to measure, not two
B	A line with a transformer attached at the end	The transformer shifts the signal in ways the sensor must account for
C	A T-shaped line with a transformer in the mix	Both A and B combined — needs four sensors and more complex calculations

3. Challenge A: The T-Shaped Line

What’s the problem?

Imagine a road that splits into three directions. At each road end, you have a sensor. Now, instead of just checking that traffic in equals traffic out at two points, you need to balance three roads at once. That’s what happens with a T-junction in a power line.

With three branches, you need three protection relays (safety devices), all connected to each other by a fiber-optic cable so they can share their measurements in real time.

The hidden complication: cable shields

Modern underground cables are wrapped in a metal shield — a bit like the outer foil on a coaxial TV cable. This shield helps contain the electric field and carries fault current if something goes wrong. The tricky part is how the shield is connected to the ground.

There are three common ways to do this: Solid Bonding (both ends grounded), Mid-Point Connection (only the middle is grounded), and Cross Bonding (the most common in long high-voltage cables, where sections of shield are swapped and grounded in a pattern that nearly cancels out induced currents).

The protection system sees these shield currents too. It needs to know which currents are normal and which signal a real fault. The algorithm has to be configured for the grounding method used in each installation.

4. Challenge B: The Line with a Transformer

Why are transformers being added to existing lines?

A transformer changes the voltage level of electricity — for example, from 30,000 volts (30 kV) down to 20,000 volts (20 kV) — so it can be distributed to homes and businesses. As new areas or renewable energy installations are connected, engineers often attach a new transformer at the end of an existing cable rather than building a completely new substation.

Two things that make this tricky

1. Phase shift: Transformers don’t just change voltage — they also shift the timing of the electrical wave. The protection relay on one side sees the current slightly out of step with the relay on the other side. Without correction, this looks like a constant fault. The relay must be programmed to apply the right correction factor.

2. The tap changer: Most transformers can fine-tune their output voltage using an automatic mechanism called an On-Load Tap Changer (OLTC). Each step changes the current ratio by about 1–2%. The protection settings must cover the full range of tap positions while still being sensitive enough to catch real faults.

Where to put the sensors?

5. Challenge C: T-Junction + Transformer

This is the most complex case — a T-shaped line where one branch connects to a transformer. You now need four protection relays, all communicating with each other.

The system must handle everything from Challenges A and B at the same time:

• Balancing currents across three cable branches
• Correcting for the transformer’s phase shift
• Staying stable across all tap changer positions
• Correctly interpreting cable shield currents

It’s a lot — but modern protection hardware and software can handle it, provided it’s set up correctly.

6. Does It Actually Work? Simulation Results

Before deploying these systems on a real power grid, engineers test them in computer simulations (MATLAB/Simulink). The key test for each scenario: does the protection correctly trip (switch off) when there’s a fault inside the protected zone, and correctly stay on when the fault is outside?

Challenge B: Fault outside the protected zone

Challenge B: Fault inside the cable

Challenge B: Fault at transformer input terminals

Challenge A: Fault outside the T-cable area

Challenge A: Fault inside the T-cable area

Challenge C: Summary result

In every case, the extended ANSI 87L algorithm correctly identified whether the fault was inside or outside the protection zone. No false alarms, no missed faults.

7. Key Lessons

The basic principle still works — but needs adaptation

The ‘what goes in must equal what comes out’ principle is still valid for all three configurations. What changes is the implementation: more sensors, more communication between devices, and more sophisticated calculations.

Sensor placement is critical

You can’t just put the current sensors anywhere convenient. The rule is straightforward: sensors must be placed at every point where current can enter or leave the protected zone. Getting this wrong doesn’t just reduce effectiveness — it can make the protection completely blind to certain types of faults.

Cable shield currents are useful, not a nuisance

Engineers sometimes see shield currents as an unwanted complication. In reality, they’re a valuable signal. During an internal cable fault, shield currents spike to levels that are easy to distinguish from normal operation. A well-designed system uses this as an extra early-warning indicator.

The tap changer must be factored in from the start

If a transformer with an automatic tap changer is included in the protected zone, the protection settings must cover the full range of tap positions. A setting that works fine at mid-range may cause false trips at the extremes. The safest approach is to verify this through simulation before the system goes live.

8. Conclusion

Line Differential Protection is one of the most reliable safety tools in the power engineer’s toolkit — it’s fast, accurate, and robust. These qualities don’t disappear as power grids become more complex, but they do require more careful engineering to preserve.

The three challenges described in this article reflect real trends: more underground cable, more renewable energy connections, and more complex layouts driven by the need to expand grids without always building entirely new infrastructure.

The good news is that all three configurations can be safely and reliably protected with modern systems — as long as engineers follow these principles:

• Define the protection zone clearly and put sensors at every boundary point.
• Account for the cable shield grounding method in the protection algorithm.
• Apply the correct correction for the transformer’s phase shift.
• Design the settings to remain stable across the full tap changer range.
• Use simulation to verify everything before commissioning.

Author: Marcin Ruta

Primary topic: Arc Flash Safety and Risk Assessment

Standards mentioned: IEEE 1584, IEEE 1584.1, NFPA 70E, IEC 61482-1-1, IEC 61482-1-2, CSA Z462, DGUV-I 203-077, IEC 60909

Reading time: 10 min read

What Is Arc Flash? 

Before diving into calculations, it helps to be precise about what arc flash is — and how it differs from a short circuit. 

Short circuit vs arc fault 

A short circuit (bolted fault) is a 1, 2 or 3-phase fault where impedance at the fault location is assumed to be zero or not, depends on calculations we need. It produces the theoretically maximum fault current and determines equipment interrupting ratings.  

An arc fault is different. It is almost any fault that is not a short circuit fault — one with electrical arc formed (impedance) in the fault path, sometimes intermittent. The impedance of arc causes arc current to be lower than bolted fault value, but the arc generates an enormous release of heat and mechanical stress on the installation and personnel nearby. 

Definition

Arc Flash Hazard (NFPA 70E-2024): A source of possible injury or damage to health associated with the release of energy caused by an electric arc. Risk increases when energized conductors are accessible during maintenance or operation.

LV vs MV — which is worse? 

A common misconception is that high-voltage systems are automatically more dangerous. At medium voltage (10 kV), arcing current stays close to the bolted fault current level. At low voltage (400 V) the ratio drops steeply: at 50 kA bolted fault current, the arcing current may be only 37-50% of the bolted value so even down to 20kA in this example. 

This means that at low voltage, with very high available fault currents, arc energy can reach extreme levels. The answer to ‘LV or MV worse?’ is: it depends on the installation. Without calculation, you do not know. 

Do you know?

Where is the worst location for short-circuit stress in a typical MV/LV substation?

1. MV switchgear 15 kV
2. transformer 15/0.4 kV
3. main 400 V circuit breaker?

Answer: the main LV CB (incoming panel) is almost always the worst — it sees full transformer fault current with the longest possible clearing time.

Standards — Knowing What You Are Working With 

Arc flash safety uses a combination of standards. Understanding which apply to your situation — and how they interact — is a prerequisite for any study. 

Most commonly used (EU and global):

• IEEE 1584-2018 — primary standard for arc flash incident energy calculations (AC, 208 V to 15 kV). 
• IEEE 1584.1-2023 — requirements for performing arc flash studies. 
• NFPA 70E-2024 or local version— primary reference for PPE selection, working distances, and electrical safety programme structure. 
• IEC 61482-1-1 — open arc test for PPE (ELIM rating in cal/cm²), most relevant in Europe. 
• CSA Z462-2024 — Canadian equivalent of NFPA 70E, used in some international projects.

Less common but technically significant:

• DGUV-I 203-077 — German guide using IEC 60909 short-circuit data; applies a 1-second maximum duration time rule (vs unlimited or 2 seconds in NFPA 70E — a key difference that significantly affects results). 
• IEC 61482-1-2 — box test PPE (APC1 or APC2 classes) used to select PPE 

Common practical approach in EU: IEEE 1584-2018 for calculation + NFPA 70E-2024 for PPE selection + IEC 61482-1-1 for PPE testing standard. The difference between DGUV203-077 and IEEE1584 is a critical and must be understood before choosing your methodology. Its not simple change 

Arc Flash Boundary and Labels 

Hazard zones

Arc flash hazard zones are distinct from shock hazard zones. The arc flash boundary is defined by energy: the distance at which incident energy decays to 1.2 cal/cm² — the onset of a second-degree burn on bare skin. In practice the arc flash boundary is often significantly larger than shock hazard zones. 

Line side vs bus side

The upstream (line) side of an incoming circuit breaker is typically much more dangerous than the downstream (bus) side, because it is protected by the upstream device — which may have, a much longer clearing time. A real example: line side 37.1 cal/cm², bus side 2.85 cal/cm² on the same panel. Both need separate labels and separate PPE assessments.

Arc flash label content (per IEEE 1584 / NFPA 70E) 

A compliant label must include:  nominal voltage level, incident energy (cal/cm²) at working distance, arc flash boundary, required PPE level and/or minimum arc rating or PPE Category   

And optionally but very useful:  location identifier, insulation glove class, shock hazard zones, line side or bus side, date of analysis, and the standard used. 

The Hierarchy of Controls — Design First, PPE Last 

The correct approach follows the classical hierarchy: eliminate first, then substitute, then engineering controls, then administrative controls, then PPE. PPE is the last resort. 

The problem becomes stark at extreme energies. No PPE exists at 200 cal/cm² or above. So before anyone opens a PPE catalogue, the energy must be brought down to a level where selection is even possible. 

Five key mitigation tools 

Protection setting optimisation: cheapest and most technically demanding. Reduce fault clearing times while preserving selectivity. Longer tripping times improve selectivity but increase arc energy — getting both right requires skilled engineering, but can transform the numbers without touching hardware. 

Optical arc detection: light sensors that react to an arc flash far faster than overcurrent protection. Response time is decoupled from current-time settings. 

Arc quenching systems: deliberately create a short circuit inside the panel, collapsing arc voltage to near zero. Results are dramatic: incident energy can drop from 100 cal/cm² to 0.1 cal/cm². 

Maintenance mode : temporarily overrides protection settings with faster parameters for the duration of work. A lockout/tagout procedure must prevent deactivation during work. 

Covers and separation forms: simplest and cheapest mitigation, most frequently overlooked. Easiest way to reduce likelihood.

Optimizing Protection Settings — A Real Project 

The following case study shows what is achievable purely through engineering, without replacing any switchgear. Starting installation: MV/LV transformer substation ,a small part of much bigger electrical model. 

The entire improvement was achieved without replacing switchgear and withou hundred thousands to t multi-million investment. Purely through engineering: reprogramming the MV relay, reviewing LV trip units, activating maintenance mode, and adding optical arc detection. 

At 90 cal/cm², PPE selection is irrelevant — there is no practica PPE to select, at least in Europe. At under 4 cal/cm², the hazard is fully manageable with standard arc-rated PPE. Same installation. Different settings. Dramatically different hazard profile. 

IEEE 1584:2018 — The Calculation Framework 

IEEE 1584:2018 equation application range: 

voltages 208 V to 15 kV; 50/60 Hz;  

bolted fault currents 500 A to 106 kA (LV) and 200 A to 65 kA (MV);  

electrode gaps 6.35 mm to 254 mm.  

Below 240 V and at fault currents below 2000 A, a three-phase arc is unlikely to sustain — which doesn’t make the system safe, but limits calculation applicability. 

Step-by-step procedure:

1. Select electrode configuration (VCB, VCBB, HCB, HOA, or VOA). HCB — horizontal electrodes facing the worker — is typically the worst case. 

2. Calculate intermediate arcing current at 600 V, 2700 V and 14300 V reference voltages using the polynomial equations in Table 1. 

3. Correct for actual system voltage — e.g. interpolate from the 600 V equation down to 415 V using Equation 25. 

4. Apply variation factor (VarCf) — actual arcing current may be lower than calculated. If it falls on the flat part of a time-current curve, tripping time and incident energy increase dramatically. 

5. Calculate enclosure correction factor (CF) — compares actual enclosure dimensions to the standard’s reference test dimensions. 

6. Calculate incident energy using the interpolated arcing current, clearing time, and CF. 

7. Calculate arc flash boundary — distance at which energy decays to 1.2 cal/cm². 

Worked example: 2 MVA transformer at 415 V 

Why calculation software is not optional at scale 

In softwares like ETAP, SKM, CYME and so on  modifying one element triggers automatic recalculation of the entire model. In a spreadsheet, the same update can mean days of work per revision. The practical consequence: people stop updating their calculations — and an outdated arc flash study is more dangerous than no study at all. 

NOT Fun Fact: Before you order the switchgear — check, calculate, verify. Once equipment is installed and the budget is spent, the money for upgrades are gone. 

Data Quality — The Make-or-Break Factor 

The most important observation from any arc flash study has nothing to do with calculations. It concerns the data that feeds them. 

The single-line diagram is the foundation of every arc flash study. In the real world it is frequently ten to twenty years out of date, inconsistent with actual field configuration, and ambiguous — multiple transformers labelled ‘Tr1’, multiple breakers labelled ‘Q1’. 

In one project, the model had to be started from satellite imagery. Getting usable data from clients can itself be a major challenge. 

Knowing what to do with the results — adjusting settings without compromising protection coordination, proposing solutions that are actually implementable — is where the real expertise lies. 

Conclusion

Arc flash safety is not about buying PPE randomly. It is a multi-layered system that begins at the design stage, runs through hazard identification, engineering solutions, electrical safety plans, and operating procedures, maintenance plans — and only then arrives at PPE selection as the final line of defence.

IEEE 1584:2018 provides a solid calculation framework, but it only works with reliable input data, a well-constructed network model, and engineering judgement. Calculation software does not replace knowledge — but without it, keeping arc flash studies current through every design revision is practically impossible.

PPE is the last line of defence, not the first. When incident energy exceeds 40 cal/cm², engineering mitigation must come before any PPE discussion. Protection settings optimisation alone can reduce incident energy by 50–80% — at zero hardware cost. The worst location in a typical MV/LV substation is almost always the main LV incoming panel, where full transformer fault current meets the longest clearing time.

Two things are worth remembering above all: outdated arc flash studies are worse than none, because they create false security. And data collection accounts for 30–40% of the total study effort — garbage in, garbage out. 

Things to check

• Check how you selected PPE in the first place? 
• Do you know your arc flash hazard incident energy ? 
• Do you solve problems with PPE or as written above? 
• Do you have locations above 40 cal/cm2 that can be improved ? 

Author: Marcin Ruta

Primary topic: Task-Based Electrical Risk Assessment and PPE Selection

Standards mentioned: ISO 45001, PN-N-18001, NFPA 70E, IEEE 1584, DGUV 203-077, CSA Z462

Reading time: 9 min read

Arc Flash Risk Assessment

Risk assessment. What can be done to ensure that it does not become merely a formal obligation – a forgotten sheet in a binder or an exercise in creative table filling? This article is devoted to this issue.

Although the starting point is electrical hazards – in particular the risk of electric arc – the issues discussed are universal. In practice, risk assessment in electrical work is a difficult area to properly address. Is it even possible to capture its specificity in a simple, repeatable, and useful way?

In this article, we will discuss:

•  What is the difference between hazard analysis and risk assessment?

•  What are the consequences of weak processes?

• What can be done differently to make risk assessment actually work.

Hazard analysis and risk assessment – what is the difference?

The terms hazard and risk are often used interchangeably. I have heard many times—and I have to  admit that I have also used—phrases such as “this is a major hazard” or “this is high-risk work.” They sound similar, but in fact they are different concepts.

Based on the approach of ISO 45001, PN-N-18001, and NFPA 70E, we can adopt simplified but very useful definitions:

• Hazard – a source of potential injury or deterioration of health. In electrical work, these include electric arc energy, electric shock, electromagnetic fields, and electrostatic charges.
• Probability – the chance or frequency of a given event occurring within a specified period of time (day, month, year).
• Risk– combination of hazard and probability of its occurrence.

This is most often written in simplified form:
Risk = Hazard × Probability

This is where resistance often arises: “It’s not gambling or poker – why do we need probability?” Ironically, the English word “hazard” means in polish  “gambling.” But let’s leave word games aside.

What hazard and risk mean in practice?

Hazard and risk are inseparably connected, but only by separating them do we gain real practical value.

Example:
The level of hazard from an electric arc is 7.6 cal/cm² (arc flash  incident energy). This is a calculated value and difficult to dispute. However, the probability depends on what activities we perform, under what conditions, and on what equipment. What’s more, not every accident is the result of human error.

To assess this, we need a system: data, criteria, and a tool, such as a risk matrix.

The grey zone of probability

It’s hard to argue about the level of hazard — it’s numerical and measurable.
Probability, however, is a different story. In my experience, this is exactly what creates the so-called grey zone of risk assessment. Data is lacking, and subjective judgment easily leads to manipulating the outcome.

Example:
Voltage measurement on the main busbars of a 415 V / 2000 A switchgear, with an arc flash incident energy ( hazard )of 7.6 cal/cm².

Let’s assume a 3×3 scale:

• Hazard: arc flash – medium (2)

• • Probability: high (3)

Risk = 2 × 3 = 6 

However, it is enough to arbitrarily reduce the probability to 1 for the risk to drop to 2 or 4. The difference is huge – and it may determine whether additional control measures or protective actions will be implemented.

Consequences of incorrect risk assessment

An overly general assessment leads to:

• broad scope for interpretation of results,

• actions that are not applicable to actual risk,

• loss of employee confidence in the entire procedure,

• more serious injuries due to a lack of adequate protection,

• lack of repeatability.

On the other hand, an overly detailed assessment results in:

• mental overload for employees,

• impractical process,

• implementation resistance

• increased time and costs.

How to limit subjectivity?

Risk assessment will never be completely objective – but subjective part can be significantly reduced by:

• initial visual inspection,

• analysis of tasks performed,

• assessment of the technical condition of equipment,

• consideration of human factors,

• decision paths preparation

• PPE pre-selection

The goal should be simple, practical tools, not more procedures “on paper.”

Task-based PPE Selection Matrix – practical example

One such tool is the Task PPE Risk Matrix implemented by MR Power Systems. This is not a universal solution—it was designed for specific requirements and working environments—but it perfectly illustrates a practical approach.

The matrix takes into account, among other things:

• condition of equipment, 

• type of hazards (arc flash, electric shock), 

• list of tasks performed, 

• preselection of PPE, 

• probability assessment, 

• final risk assessment. 

As a result, most of the analytical work has been done in advance by specialists. The employee receives a tool that is ready to use.

How to create an electrical work risk assessment?

The presented model uses several key indicators:

• equipment assessment (condition, inspections, documentation),
• risk assessment (arc flash study, electric shock),
• list of tasks performed (e.g., from the electrical safety plan or operating manuals),
• PPE preselection matrix based on hazard assessment
• risk assessment.
  

What can be done about it?

Condition of equipment:

1.    The device is correctly installed.

2.    The device is properly maintained.

3. The device is adapted to the available short-circuit current.

4. The device is used in accordance with the manufacturer’s documentation or instructions.

5. The device doors are closed and secured.

6. All covers are in place and secured.

7. There are no signs of an impending failure

Task list:

• determining what work will be performed,

• assessing whether the work involves any specific hazard.

Wymagane poziomy ŚOI: 

• preselection of PPE for use on the customer’s premises,

• specification of PPE protecting against electric arc burns,

• minimum PPE requirements (e.g., for subcontractors),

• specification of PPE protecting against electric shock,

• system for selecting and using PPE (e.g., multilayer, all-day, dedicated).

Determining likelihood:

• determination based on data or work analysis,
• assignment in a matrix (e.g., 2×2),
• determination of the impact of equipment condition on probability

Hazard level

It refers to the incident energy level. There are several methods — and at least three common approaches — to determine it:

• Performing detailed arc-flash incident energy calculations (e.g., IEEE 1584, DGUV 203-077, DC calculation models)
• Using table-based approaches (e.g., NFPA 70E, CSA Z462)
• Applying predefined or pre-calculated incident energy values

Each approach has its benefits, but the key requirement is to obtain a dependable estimate of the potential arc-flash hazard. Among these options, the IEEE 1584 calculation method is the most comprehensive and is widely considered the preferred standard.

Example of arc flash pre-calculation

Because each stage carries the risk of error, this approach is suitable only when applied under strict oversight and should not serve as the primary method for determining arc-flash incident energy.

The final result

Ultimately, we obtain a PPE selection matrix for the work to be performed. It takes into account the condition of the switchgear, the type of work performed, exposure to live parts (e.g., unshielded busbars or cable terminals), and the level of risk.

In this form, most of the analytical work has already been done by a specialist team. The tool can be easily verified based on real events or accidents. In the case described, the matrix was prepared for a large group working in service mode (i.e., not on their own installation). The list of tasks has been grouped and simplified to correspond to real situations.

Inherent and residual risk – and the role of the control hierarchy

In classic risk assessment, we always talk about the situation before and after the application of mitigating measures. In the case of the task matrix, this pre-selection has been done in advance.

Here, it is worth referring to the control hierarchy according to NFPA 70E, which clearly shows that PPE is the last line of defense, not the only solution. Technical, organizational, and procedural measures are of key importance.

Two perspectives – one goal

From the perspective of:

• the employer – we implement solutions and eliminate risks,

• the employee – we use the measures provided.

From the perspective of an employer, health and safety department, chief power engineer, or consultant, the process is the opposite of that from the employee’s point of view. First, we analyze how to eliminate or reduce the hazard, and then we expect the implemented solutions to be applied.

In practice, some measures only require technical implementation, while others require acceptance and understanding on the part of the staff. Although resistance to change is natural, solutions whose purpose is clearly communicated work best.

The matrix can be expanded to include a preselection of measures to reduce the risk or probability, which is justified because the employer bears the responsibility and has a decisive influence on the selection of solutions.

In practice, the biggest challenge is not technology, but acceptance of change. My experience shows that resistance is lower when people understand why we are implementing something.

Conclusions

• Probability should be based on data and analysis, not intuition.

• Matrices allow you to clearly define the minimum requirements for PPE.

Summary

The selection of PPE can only be made on the basis of a risk assessment. However, ignoring work procedures, the condition of equipment, and employee experience, it is easy to end up in a situation where we use full protection “always and everywhere.” Paradoxically, a well-designed matrix limits the use of PPE to places where it is really needed—and not where we are simply “afraid” to do something.

Wyświetl ten post na Instagramie

Post udostępniony przez MR Power Systems| Arc Flash Electrical Safety (@mrpowersystems)

Author: Marcin Ruta

Primary topic: Arc Flash Analysis – Results Review and Risk Mitigation

Standards mentioned: IEEE 1584.1

Reading time: 4 min read

Why it is important for us to do review? 

Recommendations as per IEEE 1584.1 should be included in Arc Flash Risk Assessment. It requires evaluating project, implement recommendations, re-do calculation. Physically, it should be a separate part or chapter in our report, so end customer can see influence or our proposed improvements. Sometimes our improvements in one area may affect negatively other parts of the electrical network. This often happens when an electrical system has a lot of non-selective protection devices. 

Step #9 is not a real step. Results review is constant activity during project. It is needed to : 

• Review any data quality issues and abnormal results or errors
• Identify high incident energy locations
• Identify equipment short circuit withstand rating failed equipment (panels, breakers, etc.)
• Identify protective devices non-selective operation (very important) 
• Identify worst case scenarios or combination of it

What’s next?

Once we have it done, we need to review arc flash results and protective device coordination and assess possibilities for improvements. This is where things are starting to get more complicated. There are multiple ways to do it and it partly depends on: 

• What we would like to achieve (zero risk, reasonable approach, or budget approach) 
• What was scope of work (contract details) 
• How far we can go with recommendations (budget, technical possibilities, equipment in use)

This is a good time to have a technical meeting with customer to discuss initial findings and identify technical possibilities if it was not done earlier during scope of work discussion. To improve the situation, we can use different mitigation and elimination arc flash techniques. It usually depends on initial incident energy results and combination of solutions mentioned below. All of this should be closely discussed with customer. 

What possible solutions do we have? 

Most common solutions to reduce or eliminate arc flash incident energy are: 

• Improving protective device settings – this is usually a big step as it is compromise with selectivity study, so two (usually opposite)  requirements at the same time. 
• Exchange protective device to new type e.g. retrofit old LV breaker with new type with digital trip unit, change fuse size/type, exchange MV protection relay with digital type.
• Exchange/ retrofit LV switchgears with new type –  it may be higher separation form, arc resistant, and it will allow for further modifications.  
• Install Fibre Optic Arc Detection system – add-on to switchgear, requires some re-wiring, but most of the time is possible even for old equipment (depends on system).
• Install Arc Quenching device –  add-on to switchgear (extra panel) or comes with new switchgears if system is replaced. 
• Use ZSI (Zone Selective Interlock)  in LV breakers – requires communication wires between breakers and requires new trip unit  (sometimes trip unite change is enough in LV breaker, depends on type).
• Use ARMS (Arc Flash Maintenance Switch) function – extra functionality of some LV breaker trip units, simple solution with right trip unit. 
• CLR (Current Limiting Reactors) – specific topics, as it can make it better and worse when reducing short circuit current.  
• Programmable Maintenance Switch for MV relays –  MV version of ARMS programmed into relay with some minor wiring needed for activation by SCADA, LOTO switch etc. 

How long it takes and how to handle it on site? 

Preparing recommendations takes time, but it is well spent time. As IEEE 1584.1 recommends, it should be part of every arc flash study. 
Once we have report with information what to do, we need to implement it on the site. Improvement process can take weeks, months, or even more than a year as it depends on the size of facility.  Since this process can take a while, it is good to already use our ”existing” results and install labels and match PPE based on it.  
Upgrades or protective device settings changes should be done exactly as proposed in report. Otherwise, we can end up having different calculated results than in real situation.  Every change should be noted and evaluated as part of “as built” documentation and any changes should be implemented in the model and results updated. 

Author: Marcin Ruta

Primary topic: Arc Flash Analysis – Existing Situation

Standards mentioned: NFPA 70E, IEEE 1584-2018, DGUV 203-077, IEC 60909, IEC 61660, IEC 60076, IEC 61439, IEC 62271, IEC 60364, BS 7671, NEN 3140, NEN 3840, VDE 0100

Reading time: 5 min read

What means existing situation? 

This step ends first part of arc flash analysis. It is called existing or as built situation as it provides information’s about incident energies and arc flash boundaries of current situation without any improvements. It is important to identify existing situation because: 

• it allows installation owner to act fast and provide temporary solutions to prevent staff from arc flash if necessary 
• implementing recommendations can take some time even counted in years, depending on size of facility, so existing results will serve as a base 
• it is a reference point for comparison of results and providing recommendations  

What standards to follow? 

We prepared base model, and now it is necessary to add arc flash related data and parameters. It is worth to mention that we are focusing on incident energy calculation and not table method. (see NFPA70E for details). Possible calculation standards and reference papers are: 

• IEEE 1584 – 2018 IEEE Guide for Performing Arc-Flash Hazard Calculations (worldwide) 
• DGUV Information 203-077 (Germany) 

Since I am focusing on European customers or locations it is also recommended to follow EN/IEC/CENELEC/VDE/BS specific standards to align our results more with IEC: 

• IEC 60909 – Short-circuit currents in three-phase a.c. systems – Part 0: Calculation of currents 
• IEC 61660 – Short-circuit currents in d.c. auxiliary installations in power plants and substations – Part 1: Calculation of short-circuit currents 
• IEC 60076 – Power transformers – Part 1: General 
• IEC 61439 – Low-voltage switchgear and controlgear assemblies – Part 1: General rules 
• IEC 62271 – High voltage switchgears 
• Local references for protection (if any) 
• IEC 60364 – selected parts  
• BS 7671 – 18th Edition The IET Wiring Regulations 
• NEN 3140/3840 
• VDE 0100 series 
• Etc. 

What Arc Flash is about? 

Our goal is to identify incident energy for modelled installation. I am writing modelled as it depends on scope of work, and sometimes it will be only part of the whole system. The most dangerous effect of an arc flash incident is tremendous temperature up to 19000 °C. This what arc flash calculation is all about. To identify how much energy can possibly be released and allows us to think in advance how to protect our life and do it the right way. 

Few words about calculation 

In most cases it will be done acc. IEEE 1584-2018 but depends on voltage level, AC or DC there are some very useful papers recommended in NFAP70E, IEEE 1584 or by equations by EPRI, ArcPro and tables by OSHA. Into this we will dive in next articles. 

How to present results? 

We have now arc flash results of our facility model for existing situation. How to present it? What to comment? To keep quality of our work it is recommended to give even brief explanation of results. Technically it is a bridge between existing situation and our future recommendations.  Depending on software or data processing tools we can present results in many forms. My recommended combinations to keep it simple and easy to read are:

• Single Line Diagram(s) – overview with Arc Flash results, e.g. Incident energy cal/cm2, AF boundary and/or AF label number (in PDF, dwg) 
• Arc Flash table – summary with all results worst scenario and/or per scenario if required 
• Colour coding – advised to use it SLD’s and tables as it is easy to find locations with higher energies (depends on how we set up colours but recommended is to follow NFPA70E) 

Some examples: 

Or by table:

Author: Marcin Ruta

Primary topic: Equipment Evaluation Withstand Rating

Standards mentioned: IEEE 1584, IEC 61439, IEC 60909

Reading time: 3 min read

What is Equipment Evaluation? 

Equipment evaluation, equipment sizing or device withstand rating verification is based on short circuit results. It verifies if short circuit rating of electrical equipment is high enough comparing to calculated short circuit current. Such calculations should be normally included in design phase however for existing installation it is recommended to verify it, especially when there is no previous design report available. 

Why is it important?

Proper sizing of equipment is crucial for safe operation under normal and faulty conditions. Cables, switchgears, breakers, transformers are design to withstand specific short circuit current in time. For proper operation of the breaker, it is critical that the breaker can withstand specific currents. If it is undersized, it can lead be damaged and pose threat to people and rest of electrical installation. 

How this relates to Arc Flash? 

It is included as a recommended step in IEEE 1584. Besides this, it is important to know that our equipment withstand rating is related with performance under fault conditions and normal operation. Constant overload or dynamic stress can cause damage to it and affect proper operation. This can lead to nuisance tripping, no tripping, thermal damage or fire etc. We can select worst case scenario out of multiple scenarios, however for experienced engineers it is easy to identify it. 

Example: 
We have low voltage switchgear rated 2000A 50kA/1s 105kA peak. If we do not know peak value, it is good to check in IEC 61439 table 7 for details.

We calculated two values in two scenarios: 

1. Ik” ≈Ith=46,45kA and Ip=100,5kA it is at the end of rating but can be accepted. In practice, it is good to keep 5-10% safety margin. 

2. Ik” ≈Ith=53,38kA and Ip=119,44kA – this switchgear rating is too low, and we need to look for higher short circuit rating or verify short circuit study input data first.  

When comparing short circuit results with different equipment, IEC 60909 comes with help and indicate which values to compare: 

Summary of equipment evaluation using SKM Power Tools

Below is an example of summary of equipment evaluation for switchgears and panel boards made with use of SKM Power Tools in this case. It can look different for other software’s like ETAP, CYME, EasyPower, DigSilent however core values should be similar. Such verification gives a very useful overview and directly indicates possible rating issues.  

In specific cases it is necessary to verify X/R or R/X of network and network time constant if not known as it affects results. Especially when local generation exists on site, This is very visible in marine and offshore installations. We need to keep in mind also renewable sources, battery storage systems, (DR) UPS-es with bypass in our calculations.

Author: Marcin Ruta

Primary topic: Protective Device Coordination and Arc Flash

Reading time: 4 min read

What Is Selectivity Analysis in Arc Flash Studies? 

It can be also called Protective Device Coordination (PDC), Selectivity Study, Discrimination Study. It is usually mandatory analysis for new electrical installations but also applies for upgrades, retrofits, or major electrical installation modernizations. Protective Device Coordination is a proper selection and settings of protective devices in order to isolate only faulted branch or place. If made properly, it will limit damage to installation itself and connected devices. A very important part of Selectivity Analysis is to eliminate fault as close as possible to the source of fault without affecting operation of the system. 

Why Is Selectivity Analysis Important for Arc Flash?

Non-selective protection system can increase damage to the equipment, extend and expand downtime and costs related. In some cases it can lead to dangerous situation especially related with safety   like fire, shock hazard, automatic disconnection or arc flash etc. In some cases it may not react at all, and obviously we don’t want it. 

How Does Selectivity Analysis Affect Arc Flash Results? 

Arc Flash calculation requires us to determine protective device tripping time.  In previous steps, we already modelled all necessary protective devices like: 

• LV fuses 
• LV breakers (ACB, MCCB, MCB) 
• MV breakers with protection relays (electromechanical, digital) 
• MV fuses 
• and specific protection schemes like differential protection, fibre optic arc detection, arc quenching devices, arc flash reduction maintenance switches, etc.

Arc flash and selectivity requirements are usually contradictory, and it requires compromise in some situations. In order to lower arc flash incident energy, tripping time need to be as low as possible (faster tripping). On the other hand, standard selectivity requirements are pushing tripping time higher (slower tripping).  There are hardware solutions that can overcome this problem, but they are not always available or feasible (due to cost, retrofit possibility or technical issues).  

Selectivity and Arc Flash? 

Arc Flash analysis itself doesn’t require the system to be selective, however it is very useful to perform such analysis. This step is important as it allows us later to provide tailor made recommendations for improvements of selectivity and arc flash. Protective device coordination is a much bigger topic, and it is very often omitted in arc flash analysis leading to identification of only existing situation while good practice is to focus on possible improvements. In order to do it right, we need to identify system issues like: 

• wrong settings of protective devices  
• non-selective areas 
• under protected equipment like cables, transformers, switchgears, and motors 

 The best way is to split analysis in two parts: 

• first step is providing information for “as build” or “existing” situation 
• second step is providing recommendations for selectivity and arc flash improvements 

Below sample of two TCC’s for existing and recommended selectivity for transformer branch. 

Selectivity Analysis Findings and Observations 

Left TCC shows a partially selective system, and it can be seen that MV relays are set with definite time settings, which is very common practice. There are few areas which can be discussed here: 

• Overlapping overload LV and MV settings may lead to MV side nuisance tripping, which we don’t want as it will de-energize the complete system and access to MV substation may be restricted or not possible. 
• MV and LV side transformer cables are not protected properly against short circuit currents 
• Transformer short circuit protection can be improved for primary and secondary faults 
• Overall arc flash results for 11kV and 415V switchgears can be improved  

Arc Flash Results Comparison – Existing vs Recommended 

Component	Existing IE cal/cm2	Recommended IE cal/cm2
BUS-11kV	18.2	6.18
BUS-LV 415V	11.1	2.4

 
It needs to be noted that in some situations it is a compromise. This means that in order to improve arc flash results, we will sacrifice selectivity and vice versa. This doesn’t happen very often and nowadays, we can use communication based protection solutions, interlocking schemes, arc flash maintenance switches to name a few.