Flow-accelerated corrosion has caused fatal ruptures in power plants, and the reason is not that it is hard to find. It is that it happens in specific places and routine thickness grids are rarely put in them.
Flow-accelerated corrosion is not erosion. Nothing is being scoured away mechanically. Carbon steel in water or wet steam forms a protective magnetite layer, and under certain conditions of flow, temperature, pH and oxygen content that layer dissolves into the flowing water faster than it re-forms. The steel underneath then corrodes freely.
The distinction matters because it tells you where to look. Erosion happens where particles hit; FAC happens where the chemistry and the flow combine, and that is a much more predictable set of locations.
Smooth. That is the giveaway and the danger.
FAC does not leave pits or a rough scarred surface. It thins the wall evenly over an area, sometimes with a faint scalloped or orange-peel texture. Cut a failed elbow open and the inside can look almost polished. There is no corrosion product to see, because the product dissolved and left with the water.
So a visual inspection of the inside of a line — if you could even do one — would show a clean surface. The wall is simply thinner than it was.
FAC needs turbulence and it needs the right chemistry, and the two together produce a short list of locations that shows up again and again in failure reports.
| Location | Why |
|---|---|
| Downstream of elbows and bends | Turbulence at the extrados and for several diameters after |
| Tees and reducers | Flow disturbance and local velocity increase |
| Downstream of orifices and control valves | High local velocity and turbulence after the restriction |
| Feedwater and condensate lines | The classic FAC service — the temperature and chemistry window sits right there |
| Wet steam and drain lines | Two-phase flow is aggressive |
| Just downstream of a weld | Internal weld protrusion creates the turbulence itself |
FAC is worst in a band roughly between 100 and 250 °C, at low pH, with low dissolved oxygen, in plain carbon steel. Small amounts of chromium suppress it dramatically — which is why a low-alloy elbow in a carbon steel line can be untouched while its neighbours thin, and why material upgrade is the standard permanent fix.
Three reasons compound.
The grid is in the wrong place. Condition monitoring locations are typically put on straight runs where access is easy and the reading is repeatable. FAC happens at the fittings. A perfectly maintained twenty-year thickness history on the straight pipe says nothing about the elbow between the readings.
There is no external sign. No leak, no weeping, no rust staining. The outside of the line looks exactly as it did when it was installed, right up until it fails.
The rate can be high. Under the wrong combination FAC removes wall far faster than general corrosion, so a line that was comfortable at the last inspection can be marginal at the next.
Scan the fittings, not the straight pipe. Because the damage is a smooth broad thin area with sound wall around it, a thickness map shows it clearly, gives the true minimum, and gives the extent — which a Part 5 assessment needs.
Cover the elbow and several diameters downstream of it. The thinnest point is often past the fitting rather than in it.
Profile radiography images the wall in outline and is practical on small-diameter lines where a scanner will not fit.
FAC is one of the few mechanisms where the physics is well enough understood to be modelled. Software that takes geometry, flow, temperature, pH, oxygen and material and ranks components by predicted susceptibility is standard practice in power generation, and it exists precisely because you cannot scan every fitting in a plant.
The model tells you which twenty of two thousand components to inspect. The inspection then tells you what is actually there. Neither replaces the other, and using the model alone is what the industry learned not to do the hard way.
A carbon steel line thinning smoothly from the inside, in a location nobody inspects, carrying hot pressurised water that flashes to steam the instant containment is lost. There is no warning stage. The failure is a rupture, not a leak, and the released fluid is lethal at close range. Several fatal incidents in power plants have followed exactly this pattern, and the common finding is not that the inspection was bad but that it was somewhere else.
Where it is found, it goes to API 579 Part 5 as local metal loss — and because the mechanism is active and the rate can be high, the remaining life calculation matters at least as much as whether it passes today.
The quick check runs Level 1 and Level 2 on a thin area — minimum thickness, remaining strength factor and MAWP, on screen.
Open the quick checkWho 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