A condition monitoring grid assumes the reading you take represents the metal around it. There are two places in every plant where that assumption is simply false, and they are responsible for a disproportionate share of piping leaks.
Most piping corrodes in a way that suits the way we inspect it. The fluid is moving, the conditions are similar all along the circuit, and a handful of readings genuinely represents the whole. Two locations break that, and they break it badly enough to deserve their own treatment.
A dead leg is any branch or section where the fluid does not move: a capped-off future tie-in, a bypass that is never used, a standby pump suction, a drain, a vent, an instrument line, a section abandoned when a unit was revamped and left in place because removing it needed a shutdown.
Stagnation changes the chemistry, and it changes it in several directions at once:
Not in the middle of the branch. The damage concentrates at the far end — the closed end, the cap, the low point — and at the transition where flow stops, a short distance in from the header. A reading taken conveniently near the header, where the scaffold is, is taken in the one part of a dead leg that is still being swept.
API 570 expects dead legs to be identified and monitored, and it is worth saying what the standard is implicitly admitting: a dead leg is a design defect that inspection is being asked to manage. The correct answer, whenever a shutdown allows it, is removal — cut it out and cap at the header. Every dead leg you delete is a monitoring location you never have to reach again.
An injection point is anywhere a second stream enters the main one: corrosion inhibitor, neutraliser, wash water, antifoulant, chlorine, caustic, methanol. The problems are different from a dead leg's and they are more concentrated.
API 570 handles this by defining an injection point circuit — a specified length of pipe around the injection that is treated as its own inspection circuit with its own, shorter interval and its own denser set of monitoring locations. As commonly applied, it runs from a short distance upstream of the injection — the greater of about 300 mm or three pipe diameters — downstream to the second change of flow direction, subject to a limit past the first change. The exact wording belongs to the standard; the intent does not need it. The area around an injection is not part of the line it sits in, and must not be assessed on the line's corrosion rate.
The common thread is that both of these are places where a mechanism operates over a few hundred millimetres of pipe, in a circuit that may be tens of metres long and otherwise behaving perfectly. Assessment methods handle localised metal loss well once you have found it. Finding it is the part that has to be planned deliberately, because the grid will not do it for you.
Once you have a minimum thickness from a dead leg or an injection point, the quick check runs the Level 1 and Level 2 metal loss assessment on it.
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