When a technician at a Texas refinery cracked open a motor control center in 2019, the arc flash that followed blew him roughly fifteen feet backward. He lived, but barely. 

The blast was hot enough to scorch his skin instantly. This left him with third-degree burns over 40% of his body, months of treatment, and a long recovery. The company was left with $2.3 million in destroyed equipment, six weeks of downtime, and OSHA citations that could have been avoided with a proper arc-flash analysis.

That’s the stakes. For oil and gas sites, petrochemical plants, and heavy industrial facilities, arc-flash protection isn’t “safety paperwork.” It’s core business protection. A serious event can take out people, hardware, production schedules, and insurance posture in a single hit.

The smartest operators treat electrical safety studies as a reliability investment, not a compliance tax.

Dangers to Humans

Arc flash is not a minor spark. It’s an electrical explosion that can spike to roughly 35,000°F, hotter than the surface of the sun. Creating a pressure wave strong enough to rupture eardrums and physically launch an adult across a room.

Safety organizations estimate tens of thousands of arc-flash incidents every year in the U.S., leading to thousands of burn injuries, thousands of hospital admissions, and hundreds of fatalities.

Financial Impacts

The financial hit can be brutal. One Louisiana petrochemical facility lost about $8 million after a 2018 arc flash wrecked its main electrical room, vaporized high-value switchgear in milliseconds, and froze production for two months.

It’s not just repairing parts. It’s outage penalties, lost throughput, workers’ comp exposure, and long lead times on replacement gear.

Regulation Citations

Regulators are direct about responsibility. OSHA’s 29 CFR 1910.335 requires employers to identify electrical hazards, assess the risk, and protect workers with appropriate practices and protective equipment. 

This includes PPE and face/eye protection where there’s a risk from electric arcs or flashes. If there’s a known arc-flash hazard, it’s on the employer to address it.

NFPA 70E turns that duty into a process. It outlines how employers must build and maintain an electrical safety program: identify and assess electrical risks, apply safety-related work practices, and justify energized work through a documented energized work permit when de-energizing isn’t feasible.

Arc Flash Risks Increase as the Voltage Does

Arc-flash risk shows up anywhere you’ve got energized gear above 50 volts: main switchboards, MCCs, disconnects, panelboards, temporary tie-ins, even that “just for now” junction someone installed during a turnaround and never pulled back out. 

The only way to treat that risk seriously is to map it, quantify it, and coordinate the protective devices so that when something fails, it fails safely.

Think of an arc-flash study as a full electrical risk map of your facility. Instead of blood pressure and cholesterol, you’re measuring incident energy and blast radius. 

• Engineers model every point where a worker might be exposed to an energized part
• Calculate how severe an arc event could be at that location.
• Spell out what PPE and work practices are required.

If you run equipment above 50 volts, you’re expected to have this documented. Insurers ask for current studies. Contractors expect to see them before they’ll quote energized work. Smart plant managers use them for planning outages, setting PPE rules, and controlling who’s allowed to open which covers. Without that map, you’re guessing every time someone cracks a door.

A proper study doesn’t stop at the main switchgear. It starts at the utility service and follows power all the way down to the smallest breaker. 

Engineers need to: 

1. Build a digital model of the system.
2. Calculate available fault current.
3. Review breaker and relay settings.
4. Determine incident energy for each piece of equipment.
5. Generate arc-flash labels and safe-work boundaries.

You walk away with updated one-lines, PPE tables, boundary distances, and task-specific procedures instead of guesswork.

Most firms run these studies with dedicated tools such as SKM, ETAP, or EasyPower. Typical scope for a mid-size industrial facility runs a few weeks and costs in the tens of thousands of dollars. 

Stack that against the multimillion-dollar downside of a single catastrophic event and the math is pretty simple.

Incident Energy

“Incident energy” is how much thermal energy hits a worker standing at a defined distance from an arc. It’s measured in calories per square centimeter (cal/cm²) and it drives PPE. 

• Around 1.2 cal/cm², bare skin will develop a second-degree burn. 
• Around 8 cal/cm², normal work clothes can ignite. 
• By 40 cal/cm², even a heavy arc suit might not be enough to walk away without severe injury.

Arc-Flash Boundaries

From those energy calculations, you get the arc-flash boundary — the distance at which a person without arc-rated PPE could expect a second-degree burn if an event occurs.

Sometimes that line is within 18 inches of a small panel. Sometimes it’s twenty feet out from high-energy switchgear. People need to know exactly where that line is before they open anything, and supervisors need to enforce it.

Fault Current

Fault current analysis shows how much current can actually flow during a short. High available fault current can mean a massive, violent arc. It can also mean breakers and relays trip faster, which limits how long the arc lasts.

Picture a 480-volt panel that can see 30,000 amps. If the protective device clears the fault in a couple of cycles, you’ve limited exposure. If it hesitates, you’ve just created a blowtorch.

Labels

All of that information: voltage, incident energy, PPE category, arc-flash boundary gets turned into a physical label posted on the gear. 

Those labels are not decoration. They’re instructions. Workers lean on them when deciding: 

• Do I need a face shield?
• Full hood?
• Insulated gloves?
• Can I even have this cover open while energized?

Labels have to stay readable in the real environment, and they have to stay accurate as settings and system configurations evolve. Regular label audits catch drift before it turns into a false sense of security during energized work.

Protective Device Coordination

Protective devices have to act in the right order. When something faults, you want the closest upstream protective device to trip first, not the main breaker feeding half the facility. That’s selective coordination. A motor starter breaker should clear its own motor fault. The feeder breaker should clear a feeder fault. The main should only go if everything downstream fails.

Engineers model this with coordination studies that simulate thousands of fault scenarios. They compare breaker and relay curves, account for transformer inrush, motor starting behavior, cable heating limits, and tolerance bands in the protective devices themselves. That modeling exposes weak points long before a live test does.

Here’s where coordination ties back to arc-flash risk. Faster clearing times mean lower incident energy at the point of the fault. Great for the worker. But ultra-fast “hair trigger” settings can also cause nuisance trips on normal events like a motor inrush, which can take down production. 

To solve that, facilities lean on tools like zone-selective interlocking or temporary maintenance modes: aggressive protection while someone’s inside the gear, normal coordination the rest of the time.

Time-Current Curves

Time-current curves plot how each breaker or relay behaves. The x-axis is current. The y-axis is time. Each curve shows, “At this much fault current, I’ll trip in this many cycles.” When you stack curves for devices in series, you can literally see whether they coordinate or overlap.

Good coordination demands daylight between curves so that downstream protection has first shot. Thi is often on the order of a few tenths of a second (roughly 0.2–0.4 seconds, or 2–3 cycles) at expected fault current levels. 

If two curves overlap too tightly, you risk both devices tripping. If you separate them too much, you let the arc burn longer than it should. There’s judgment involved, especially in higher-voltage systems that need wider timing margins and in legacy gear that doesn’t behave like modern microprocessor relays.

That’s why coordination reviews still require an experienced power engineer, even when the software plot looks perfect.

Step one is data. Engineers need transformer kVA, impedance, and winding configuration. They need cable lengths, sizes, and insulation types. They need breaker model numbers and the exact pickup and delay settings. Missing or wrong data wrecks accuracy and leads to false confidence.

Accurate one-line diagrams matter just as much. If your drawings don’t show that “temporary” MCC you tied in last turnaround, or the rental generator someone quietly made permanent, the model will lie to you. Out-of-date single lines are one of the fastest ways to understate real hazards.

Utility data can be painful to get but is critical. Available fault current, system X/R, and upstream relay behavior at the service entrance all drive calculated arc energy downstream. If you guess, you’re gambling with real people.

Once the model is built, engineers calculate incident energy at each bus, evaluate clearing times, and assign working distances. This is where IEEE 1584 comes in. IEEE 1584 gives a lab-tested, math-driven method for predicting arc current, arc duration, incident energy, and arc-flash boundary across common industrial voltage classes (roughly 208 V through 15 kV) using empirical formulas developed from extensive testing.

Working distance is a quiet killer. The math might assume 18 inches at 480 V and 36 inches at 4.16 kV. But if the gear is jammed in a narrow electrical room and you physically can’t stand that far back, real exposure is higher than the model says. Good engineers sanity-check the software with field reality and spot-check critical breakers manually, especially older units that may not clear as fast as their original curves imply.

The study output isn’t just numbers in a binder. You get defined approach boundaries.

• The arc-flash boundary is where an unprotected person could receive a second-degree burn if an arc occurred.
• The limited approach boundary and restricted approach boundary deal with shock and accidental contact. Limited keeps unqualified people away from energized conductors (think 42 inches at 480 V, jumping to about 10 feet at 13.8 kV). Restricted is the “you’d better have written authorization and the right gear” zone where an accidental slip could put your body in contact with live parts. Those distances are not suggestions — they’re work control lines.

These boundaries go on durable equipment labels along with voltage, incident energy, required PPE category, and any special notes. Labels must survive the environment and remain readable, and they have to match what’s actually in the gear today, not what was there five years ago.

Routine label reviews catch fading, damage, or changes in calculated values that creep in after system modifications or breaker setting tweaks. People can’t protect themselves from hazards they can’t see, and they can’t follow rules they can’t see either.

NFPA 70E

NFPA 70E is essentially the playbook for electrical work practices in U.S. facilities. It expects you to build and maintain an electrical safety program, perform arc-flash and shock risk assessments, define energized work procedures and permits, train “qualified” workers, and audit that the program is actually followed in the field.

OSHA

OSHA enforcement sits behind that. OSHA 29 CFR 1910.335 says employers have to assess electrical hazards and provide protective equipment and tools suited to the task, including arc-rated PPE and face/eye protection where there’s a risk from electric arcs or flashes. In plain terms: if you expose employees to an energized hazard, you’re responsible for knowing the hazard and mitigating it.

IEEE 1584

IEEE 1584 moved arc-flash assessment from “best guess” to engineering discipline. It gives the calculation methods for arc current, arc duration (based on protective device clearing times), incident energy at a defined working distance, and the arc-flash boundary. Those results drive labeling, PPE, and procedural controls. Facilities that haven’t been updated since older calculation methods often find their required PPE levels and safe distances change once they’re re-run under the current model.

Engineering Controls

• Arc-resistant switchgear is built to contain and redirect arc blast energy through reinforced housings and vented plenums, so the blast goes up and away from the operator instead of out the door.
• Current-limiting fuses slash peak fault current by opening extremely fast, which reduces how violent the arc can get. You give up reset capability — a fuse is done after it operates — but you often gain a dramatic cut in incident energy.
• Maintenance mode / instantaneous trip: many modern breakers include a temporary “maintenance” setting that removes intentional delay and trips almost instantly while technicians are working, then goes back to normal coordination for production.
• Remote racking and remote switching let workers stand clear of the arc-flash boundary altogether. Motor operators, wireless controls, and fixed cameras mean you don’t have to be face-to-face with live gear to open or rack it.

Administrative Controls and PPE

• Energized work slows people down and forces the hard question: “Why can’t we de-energize?” The permit process often exposes safer alternatives to live work before anyone puts on a hood.
• Arc-rated PPE selection starts with the incident energy on the label, but practicality matters. Can the person see, move, and breathe well enough to do the job without creating a new hazard? The highest category suit is not automatically the safest choice if it destroys dexterity.
• Competency checks shouldn’t end in the classroom. Workers need to be observed actually donning the suit, staying outside restricted boundaries they’re not cleared to cross, and using insulated tools correctly.

Condition-based maintenance helps too. Infrared scans, partial discharge testing, and targeted inspections reduce how often you have to open energized gear in the first place. Every avoided “hot” exposure is risk reduction.

Arc-flash studies and protective device coordination aren’t academic paperwork exercises. They’re the backbone of an electrical safety program that protects people, limits outage blast radius, and keeps production from falling apart after one bad breaker event. They also create a common language between operations, maintenance, safety, and insurance: everyone can point to the same label and see the same risk.

Treat the study as a living document, not a one-and-done binder. Update it when you add a big motor, swap a transformer, change utility service, or tweak breaker settings. Focus upgrades where energy is highest and human contact is most frequent — that 40 cal/cm² main switchboard deserves priority long before a 2 cal/cm² lighting panel.

Finally, choose engineers who understand both math and plant reality. The cheapest study isn’t a bargain if it ignores how your people actually work, or if it hands you labels without explaining maintenance mode, switching procedures, and PPE strategy. You don’t need paperwork. You need a plan that people can execute tomorrow without getting hurt.