Every local metal loss calculation contains a term called Mt that most people apply without knowing what it represents. It is the reason a long shallow flaw is worse than a short deep one, and it is worth ten minutes.
Take a flat plate with a thin patch in it, pull on it, and the calculation is simple: less section, more stress, in proportion.
Now put that same thin patch in the wall of a pressurised cylinder. Something extra happens. The thinned area is less stiff than the wall around it, so internal pressure pushes it outward relative to its neighbours. That local bulge introduces bending on top of the membrane stress, and the stress at the flaw goes up by more than the loss of section alone accounts for.
The Folias factor is the multiplier that captures this. It is named after L. F. Folias, whose work in the 1960s on cracks in pressurised shells produced the original solution, and it appears throughout API 579, ASME B31G and the pipeline assessment methods that came from the same lineage.
Not on depth. This surprises people. The bulging factor depends on the length of the flaw, the diameter and the wall thickness — combined into one dimensionless group:
λ = 1.285 · s / √(D · t)
where s is the flaw length, D the diameter and
t the wall thickness.
The quantity √(D·t) is a characteristic length for a shell — roughly, the distance over which the shell can redistribute a local disturbance. A flaw much shorter than √(D·t) is carried by the surrounding wall and barely bulges. A flaw much longer has no help available and bulges freely.
The bulging factor then follows, in the form API 579 uses for a Level 1 assessment:
Mt = √(1 + 0.48 λ²)
For a vessel of 576 mm inside diameter and 12 mm wall, so √(D·t) = 83.1 mm:
| Flaw length | λ | Mt | RSF at 50% depth |
|---|---|---|---|
| 25 mm | 0.39 | 1.035 | 0.967 |
| 50 mm | 0.77 | 1.134 | 0.894 |
| 100 mm | 1.55 | 1.465 | 0.759 |
| 150 mm | 2.32 | 1.892 | 0.680 |
| 200 mm | 3.09 | 2.364 | 0.634 |
| 300 mm | 4.64 | 3.365 | 0.587 |
| 400 mm | 6.18 | 4.399 | 0.564 |
Three things are visible in that table and all three are useful.
At 25 mm the bulging factor is 1.035 — a 3.5% penalty. Half the wall is gone and the component still has 97% of its capacity. A short flaw, however deep, is largely carried by the metal around it.
RSF falls from 0.894 to 0.634 across that range at constant depth. Nothing about the depth changed. That entire loss is the flaw getting longer.
From 200 to 400 mm, RSF only moves from 0.634 to 0.564. Once a flaw is long compared with √(D·t) there is no more help to lose — the shell has already stopped supporting it, and further length adds little.
Flaw length matters most in the range around one to three times √(D·t). Below that, length is nearly irrelevant. Above it, length has already done its worst. For most process vessels and piping, √(D·t) lands somewhere between 40 and 120 mm — so the sensitive range is roughly 50 to 350 mm, which is exactly the size of a typical corrosion patch.
A report that says "minimum remaining thickness 6 mm" is half an answer. The other half is how far the thinning extends, and the table above shows it can matter more.
Which is a direct argument for corrosion mapping over spot readings wherever the damage is localised: a grid gives you a minimum and no extent, and the assessment cannot be done without the extent.
Several bulging factor expressions exist and they do not all agree.
They give different answers on the same flaw. Which is correct depends on which code you are working to — and mixing the bulging factor from one method with the acceptance criterion from another is a real and surprisingly common error.
The same physics applies to crack-like flaws in shells, so a bulging correction appears in Part 9 fracture assessments too — there it raises the stress intensity for a flaw in a curved pressurised shell above the flat-plate value. Same reason, same behaviour: the shell bulges locally and the flaw feels more stress than the membrane calculation suggests.
The Level 1 demonstration lets you change flaw length and see Mt and the remaining strength factor respond together.
Open the demonstrationsWho writes this. A mechanical engineer with twelve years in oil and gas — in-line inspection, fired heater and furnace inspection, and pipeline integrity. What is here comes from the published standards and from what those years in the field actually looked like. It is not written by an API-certified inspector.
This is not an assessment. Nothing on this site may be used to justify a decision about real equipment. Assessing plant requires the current editions of the applicable codes, data from a licensed source, and a competent engineer who signs for the answer. · Integrity Field Guide