API 570 piping circuits: circuitization to interval

Vessels are easy to count. Piping is not. A single unit can hold hundreds of lines, thousands of welds and tens of thousands of possible measurement points, and API 570 does not ask you to inspect all of them. It asks you to organize them into circuits, classify each circuit by consequence, pick condition monitoring locations that represent the circuit, and then let measured corrosion set the interval. Every step is a decision that has to be recorded, because the interval at the end is only as defensible as the circuitization at the start. This paper walks that chain and describes what a piping record has to carry to survive an audit.

What is a piping circuit under API 570?

API 570 defines a piping circuit as a section, or sections, of piping that has the same material of construction, similar design conditions, the same process stream and, critically, the same expected damage mechanisms. The purpose is statistical: within a circuit, thickness readings at different CMLs can be treated as samples of one corrosion behavior, so a rate derived from ten CMLs can stand for a run with a thousand joints.

Circuits are usually drawn on isometrics or P&IDs and given a stable identifier. Good circuitization follows a few practical rules.

• Break at a change in mechanism, not only at a change in line number. A line that passes from a hot section through a cooler into a cold section has two circuits even if the line number does not change, because the mechanism changes at the dew point or the temperature threshold.
• Break at a change in material or specification. Carbon steel and stainless in the same service corrode differently.
• Break at injection and mixing points. These get their own circuits by the code's own guidance.
• Keep circuits small enough to be honest. A circuit that spans a whole unit cannot have one corrosion rate. If the readings within a circuit scatter widely, the circuit is too big.

The record for a circuit needs its boundaries, its class, its material and design conditions, the damage mechanisms assigned to it, and the list of CMLs that represent it. Change any of those and the circuit's history has to show the change and why.

How do API 570 piping classes set inspection intervals?

API 570 classifies piping by the consequence of a leak, and class sets the maximum interval and the extent of inspection.

• Class 1: highest potential for an immediate emergency. Flammable services that may auto-refrigerate and lead to brittle fracture, pressurized services that flash to explosive vapor, hydrogen sulfide above about three percent by weight in gas, anhydrous hydrogen chloride, hydrofluoric acid, and piping over or adjacent to water or public throughways.
• Class 2: most process piping not in Class 1, including on-site hydrocarbons that vaporize slowly, hydrogen, fuel gas, and on-site strong acids and caustics.
• Class 3: flammable services that do not significantly vaporize, and process lines in remote locations away from populated areas.
• Class 4: optional coverage for non-flammable, non-toxic services such as steam, condensate, boiler feedwater, plant air and nitrogen.

The thickness measurement interval is the lesser of one half of the remaining life or the class maximum: five years for Class 1, ten years for Class 2 and Class 3, and at the owner's discretion for Class 4. External visual inspection has its own maximums, five years for Classes 1 and 2 and ten years for Class 3. Injection point circuits carry a shorter thickness measurement maximum than the parent class. As with vessels, API 570 permits a risk-based interval to API 580 when the assessment is documented, approved and periodically reassessed.

The class is a record, not an attribute. Auditors ask why a line is Class 2 and not Class 1, and the answer must be on file with the date and the person who made the call.

Where should CMLs go on a circuit?

API 574 is the recommended practice that covers piping components, and it carries the detail API 570 leaves open: where measurements belong, how many, and what to do with the awkward parts of a system.

• Turbulence and impingement. Elbows, tees, reducers, control valve outlets, and the pipe downstream of orifices and pumps see accelerated erosion and erosion-corrosion. The outer radius of an elbow is a standard CML.
• Phase change and low points. Where water drops out, where a stream reaches its dew point, and where liquid collects in a low leg.
• Dead legs. Sections with no or intermittent flow: bypasses, spare pump lines, blanked branches, level bridle connections. Corrosion in dead legs often runs faster than in the flowing line, and API 574 recommends they be inspected as their own concern and removed where they serve no purpose.
• Injection points. API 570 recommends the injection point circuit run from a minimum of twelve inches or three pipe diameters upstream, whichever is greater, to the second change in direction downstream or twenty-five feet past the first change, whichever is less, with thickness readings concentrated in that window.
• Small bore and threaded connections. Auxiliary piping of two inches and smaller, especially threaded, fails by vibration fatigue and external corrosion more often than by wall loss, and needs visual attention and support checks rather than only UT.

The number of CMLs per circuit is a judgment. More CMLs for Class 1, more for circuits with high or uncertain rates, fewer for well-characterized low-rate service. What matters for the record is that the same CML is measured each time. A CML that migrates six inches between surveys produces a corrosion rate that is a measurement of the technician, not the pipe.

How is remaining life computed for piping?

The arithmetic mirrors API 510 and the difference is in the required thickness.

The pressure design minimum for straight pipe under ASME B31.3 is t = PD / 2(SE + PY), with P the design pressure, D the outside diameter, S the allowable stress at temperature, E the quality factor, and Y a temperature-dependent coefficient (0.4 for ferritic steel below about 900 degrees F). Later editions add a weld joint strength reduction factor at high temperature. Fittings and bends use their own rules.

For small and medium pipe the pressure design minimum is often thinner than the pipe can structurally tolerate under its own weight, wind, and handling. API 574 provides guidance on default structural minimum thicknesses by pipe size for that reason. The retirement thickness for a CML is the greater of the pressure design minimum and the structural minimum, and the record must say which one governs.

Corrosion rates are computed as in API 510: a long-term rate from the initial reading and a short-term rate from the previous reading, with the inspector selecting the one that represents current service. Remaining life is actual thickness minus retirement thickness, divided by that rate. MAWP for continued service is computed from the piping code using the actual thickness minus twice the corrosion expected before the next inspection.

Two records fail here most often. The first stores one tMin for a line rather than for each component size and fitting. The second overwrites the previous reading with the new one, which deletes the short-term rate and leaves only a long-term average that hides a recent acceleration.

Which circuits need their own program?

Some parts of a piping system corrode by mechanisms that have nothing to do with the process stream, and API 570 calls them out for separate treatment.

• Corrosion under insulation (CUI). Carbon and low-alloy steel operating between about 10 and 350 degrees F, and austenitic stainless between about 140 and 400 degrees F, is susceptible. API 570 directs external visual inspection of a percentage of suspect area by class, highest for Class 1, with follow-up thickness measurement where insulation damage is found. Suspect locations include penetrations, damaged jacketing, low points, and the ends of vertical runs.
• Soil-to-air interfaces. Buried lines corrode at the transition where oxygen, moisture and coating damage coincide. API 570 asks for inspection at the interface with excavation of a short length where needed.
• Mixing points and injection points. Covered above, but they also carry their own external visual interval.
• Deadlegs and intermittent service. Circuits that only flow during startup or regeneration cycle through wet and dry conditions.

Each of these is a circuit with its own class, mechanisms, CMLs and interval, and the record has to treat it that way. Folding an injection point into its parent line's circuit averages a fast local rate into a slow general one and produces an interval that is wrong in the direction that matters.

What does a defensible circuit record look like?

Put the pieces together and the piping record has a clear shape.

• A circuit register: identifier, boundaries on a drawing, class with justification, material and specification, design conditions, process stream, assigned damage mechanisms, and a history of changes.
• A CML register per circuit: location, component type and size, nominal thickness, retirement thickness with its governing basis (pressure or structural), and a drawing reference.
• A reading history per CML: every reading with date, method, instrument, technician and any notes, never overwritten.
• Derived values per CML and per circuit: short-term rate, long-term rate, governing rate, remaining life, and the interval that follows, with the rule applied (half-life or class maximum).
• Findings and repairs: external visual findings, CUI locations, temporary repairs such as clamps with their planned removal, and the examination and test that closed each one.
• Approvals: who classified, who selected the rate, who set the interval, who signed the report.

Software that can present this as one thread, from a reading on an elbow to the interval on the circuit, is doing the job API 570 describes. Software that presents it as a list of due dates is not.

How intelliSPEC handles it

intelliSPEC models piping as part of the asset graph, with nodes for facility, asset and component, so a circuit, its lines and its CMLs are related records rather than rows in separate spreadsheets. Thickness readings arrive in intelliNDT from supported ultrasonic gauges over Bluetooth or keyboard wedge without retyping, and each CML carries 64 fields including nominal thickness, OD and schedule, tMin and its method, design pressure, material, allowable stress, latest thickness and three corrosion rates.

The calculation engine routes tMin by equipment type, so piping is computed to ASME B31.3 and the result returns the design code and the formula alongside the number. The corrosion summary produces short-term, long-term and maximum rates per CML, takes the maximum as governing, and derives remaining life as thickness minus tMin over the rate. The API 570 interval is capped at half the remaining life. For local metal loss on a run, ASME B31G remaining strength is available in both the original and modified forms, with results held as provisional until an engineer verifies them and never applied to derate a line automatically.

External visual inspection, CUI surveys and injection point walkdowns are captured in intelliINSPECT, where the CUI wizard family carries the work from visual and suspect area identification through insulation removal, UT, advanced NDE, repair and recoat. Drawing annotation detects CML points on uploaded isometrics automatically, and photos and video are bound to the component at capture. The field app works fully offline with no time limit on the local store, which matters on pipe racks and in tank farms with no coverage. The refining and petrochemical context for this work is described on the oil and gas page, and the terms are defined in the glossary.

API 570 is a program, not a table of intervals. The record that proves the program is the one that shows every decision between the drawing and the due date.