Setting a Class 2 Piping Interval From a Measured Corrosion Rate

Short answer: under API 570, the next thickness inspection of a Class 2 circuit is due at the shorter of two limits: half the calculated remaining life, or the Class 2 maximum (10 years in the code's recommended-maximum table). Remaining life is measured thickness minus required thickness, divided by the governing corrosion rate. At 2 mils per year, healthy wall usually leaves the 10-year cap in control. A thin CML or a faster short-term rate can bring the date much closer.

This page works through that calculation with transparent numbers, then covers the parts a calculator cannot do for you: choosing the governing rate, deciding whether the interval is set per CML or per circuit, handling the short-remaining-life rule, and documenting the result so it stands up to audit. The arithmetic follows API 570; the 4th edition (2016) text was reviewed for this guide. The current edition is the 5th (February 2024). API's 2024 Body of Knowledge maps the relevant topics to corrosion rate, remaining life and inspection interval clauses. Confirm wording and numbers against your licensed copy and your jurisdiction.

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The rule: half remaining life or the class maximum

Where RBI is not used, API 570 sets piping inspection intervals from four inputs: corrosion rate and remaining-life calculations, the piping service class, jurisdictional requirements, and the judgement of the inspector and piping engineer. For Classes 1, 2 and 3, the time between thickness measurements at CMLs or circuits should not exceed half the remaining life or the class maximum in the recommended-maximum-interval table, whichever is less.

For Class 2, that table gives:

• Thickness measurements: 10 years maximum, and never more than half the remaining life.
• External visual inspection (including the CUI check): 5 years maximum, on its own clock regardless of thickness results.

These are the 4th edition values; secondary summaries report them unchanged in the 5th edition. The 4th edition also has a special rule when the remaining life is short: if less than four years remain, the interval may be the full remaining life, up to a maximum of two years. The code also requires intervals to be reviewed after every inspection and after any significant change in operating conditions.

Class 2 is the default class for most on-site unit piping, such as hydrocarbons operating above their flash point but below their boiling point, on-site hydrogen and fuel gas, and on-site strong acids and caustics. If you are unsure whether a line belongs in Class 2, see API 570 piping service classes 1-4. Class 1 limits are tighter and are covered in Class 1 hydrocarbon inspection intervals.

The three formulas and the units that trip people up

API 570 uses three simple equations. They are described here in words; check the printed form in your copy of the code.

• Long-term (LT) corrosion rate = (initial thickness − current thickness) ÷ years between them. "Initial" means the reading at installation or at the start of a new corrosion environment, at the same location as the current reading.
• Short-term (ST) corrosion rate = (previous thickness − current thickness) ÷ years between them, again at the same location.
• Remaining life = (current thickness − required thickness) ÷ governing corrosion rate.

Required thickness is the larger of the pressure design thickness and the structural minimum thickness, computed before corrosion allowance and mill tolerance are added. API 574 gives guidance on structural minimums and alert thicknesses. For high-risk services, the piping engineer may decide to raise the required thickness.

Units cause frequent errors. One mil is 0.001 inch, so 2 mils per year (mpy) is 0.002 in/yr, about 0.05 mm/yr. If thickness is in inches and the rate in mpy, convert before dividing; otherwise the remaining life comes out a thousand times too long. The long-term versus short-term choice, and the statistics behind it, are covered in depth in corrosion rate calculation: long-term vs short-term.

Worked example: a Class 2 hydrocarbon line at 2 mpy

The numbers below are illustrative, chosen to show the logic. They are not taken from any real plant or from the code.

Circuit: a 6-inch carbon steel line carrying on-site gas oil above its flash point and below its boiling point, classified Class 2. Nominal wall is 0.280 in. The piping engineer's required thickness for the straight pipe (pressure design, checked against the structural minimum) is 0.150 in.

CML A, straight run:

• Baseline at installation, 16 years ago: 0.282 in.
• Previous reading, 4 years ago: 0.258 in.
• Current reading: 0.250 in.

LT rate = (0.282 − 0.250) ÷ 16 = 0.032 ÷ 16 = 0.002 in/yr = 2.0 mpy.

ST rate = (0.258 − 0.250) ÷ 4 = 0.008 ÷ 4 = 0.002 in/yr = 2.0 mpy.

The rates agree, so the governing rate is 2.0 mpy.

Remaining life = (0.250 − 0.150) ÷ 0.002 = 0.100 ÷ 0.002 = 50 years. Half the remaining life is 25 years. The Class 2 maximum of 10 years is shorter, so the thickness interval for CML A is 10 years. External visual inspection still falls due within 5 years.

CML B, elbow downstream of a control valve, same circuit:

• Baseline: 0.280 in. Previous (4 years ago): 0.229 in. Current: 0.205 in.

LT rate = (0.280 − 0.205) ÷ 16 = 0.075 ÷ 16 ≈ 0.0047 in/yr (4.7 mpy).

ST rate = (0.229 − 0.205) ÷ 4 = 0.024 ÷ 4 = 0.006 in/yr (6.0 mpy).

Using the faster short-term rate, which gives the shorter life: remaining life = (0.205 − 0.150) ÷ 0.006 ≈ 9.2 years. Half is about 4.6 years. That is shorter than the 10-year cap, so CML B governs at about 4.5 years. Assume the elbow's required thickness matches the straight pipe; if the engineer calculates a different value for the fitting, use it.

CML C, a dead-leg branch with a short remaining life: current 0.165 in., governing rate 6.0 mpy. Remaining life = 0.015 ÷ 0.006 = 2.5 years. Remaining life is under four years, so the 4th edition's short-life rule applies: the interval may be the full remaining life, but no more than two years. Here that means 2 years. In practice, a CML this close to required thickness also triggers an engineering review: repair, replacement, a rerate, or a fitness-for-service assessment commissioned by the owner.

The lesson: a "2 mpy line" is not automatically a 10-year line. The interval is set by the limiting location in the circuit, and that is usually a fitting, a flow disturbance or a dead leg, not the straight pipe that produced the comfortable average.

Choosing the governing corrosion rate

The 4th edition says the LT and ST rates should be compared to see which gives the shorter remaining life. The authorized inspector, in consultation with a corrosion specialist, then selects the rate that best reflects the current process. Older editions said more bluntly that, in most cases, the higher of the two rates should be used. Either way, the conservative choice is the default, and departing from it needs a documented reason.

Situations where judgement matters:

• ST rate much higher than LT. This may mean a real change: a new crude or feed, a lost inhibitor injection, higher velocity, or a temperature increase. Use the higher rate until the cause is understood. Check for a management-of-change record too, since a process change can also change the class.
• ST rate lower than LT after a known improvement (for example, a new inhibitor programme). A lower rate can be justified, but only with process evidence and enough readings to show the change is real.
• Negative or near-zero rates. A later reading thicker than an earlier one is measurement scatter, not metal growth. Do not average it away silently. Look at probe placement, surface condition and calibration, and consider re-measuring.
• Statistical methods. API 570 allows statistical analysis (for example probability plots) for circuits, provided it is documented and reasonably conservative. Point-measurement statistics are not suitable for circuits with significant localised, unpredictable corrosion.
• Repaired or like-for-like replacement piping. The 4th edition bases the rate on the previous worst-case rate at that location or on the circuit average, rather than starting from zero.
• New or changed-service piping with no rate data. Use data from similar service, or published experience. If neither exists, take the first thickness readings within three months of service.

Measurement quality: why 2 mpy is hard to measure

At 2 mpy, five years of service removes about 10 mils of wall. The scatter between two UT readings on a real pipe surface — paint, scale, pitting, couplant, probe angle, a slightly different spot — can be a meaningful fraction of that. A low-rate calculation can therefore be dominated by measurement noise. Some practical controls:

• Mark and re-locate CMLs. API 570 expects CMLs to be shown on inspection drawings, and the piping may be marked so repeat readings land on the same spot.
• Record the thinnest reading in the examination point consistently, using the same rule every time, not a mix of minimums and averages between surveys.
• Use the right technique for the surface. Echo-to-echo modes can read through coatings, while scanning beats spot readings where loss is localised.
• Calibrate and verify on reference blocks of similar material and thickness, and record the instrument, probe and block used.
• Map where loss is localised. Automated UT corrosion mapping at elbows and downstream of valves finds the true minimum in a defined area. A single point can easily miss it.

Better data does not change the code limits, but it makes the calculated rate believable. That helps when an inspector or engineer needs to defend a 10-year interval rather than default to a shorter one.

Per CML, per circuit, and other clocks

API 570 frames the half-life rule "for CMLs or circuits". It also expects corrosion rates, remaining life and next inspection dates to be calculated so that the limiting component of each circuit is identified. In practice, most programmes set the circuit's next thickness date from its limiting CML. Some schedule a few problem CMLs (CML B in the example) more often while the rest of the circuit stays on a longer cycle. Either approach can work, provided the inspection plan says which is used and the scheduling system actually enforces the earlier date.

Other clocks run alongside the thickness interval:

• External visual inspection: 5 years maximum for Class 2, with CUI follow-up NDE on a target share of susceptible insulated piping.
• Injection points: these have their own thickness maximum in the 4th edition table, separate from the class value. See API 570 injection point inspection.
• Soil-to-air interfaces and buried sections, which follow their own rules. See soil-to-air interface and buried piping.
• Non-continuous service: interval years may count actual operating time only if the idle piping is isolated and protected from corrosive conditions.

The 4th edition also links interval to pressure rating. When MAWP is recalculated, the wall thickness used is the measured thickness minus twice the estimated corrosion loss before the next inspection. So a longer interval reduces the pressure the line can be rated for.

What the inspection plan must document

An interval is only as good as its paper trail. An auditor or jurisdictional inspector will typically expect to trace each next-inspection date back to:

1. The class and its basis (fluid, temperature relative to flash and boiling points, location).
2. The required thickness for each component, with its basis (pressure design, structural minimum, engineer adjustments).
3. The CML history: identifiers, locations on the isometric, dates, readings, technique, and the examiner's certification.
4. The LT and ST rates, which one was selected, and why, with the corrosion specialist's input where the rate was not the conservative choice.
5. The remaining-life result, the half-life value, the class cap, and which one controlled.
6. Any deferral of the due date, documented and approved under the code's deferral rules. The 5th edition expanded the requirements for reviewing and deferring inspection repair recommendations.

In the US, OSHA's PSM standard (29 CFR 1910.119(j)) requires inspections and tests on process piping at frequencies consistent with good engineering practice, and more often if operating experience shows it is needed. It also requires each inspection to be documented with the date, the performer, the equipment identifier, a description and the results. API 570 is widely treated as RAGAGEP for process piping. State programmes and, in Canada, provincial regulators such as ABSA (via AB-506 integrity management programmes) and TSSA may impose additional or different requirements. Confirm with your jurisdiction.

Common mistakes when setting Class 2 intervals

• Using the circuit-average rate when one fitting is corroding three times faster than the straight pipe.
• Applying the 10-year cap without checking half-life at every CML, especially fittings and dead legs.
• Starting the long-term rate from nominal thickness instead of a measured baseline. Mill tolerance alone can make nominal unreliable.
• Mixing units (mpy and in/yr), which can inflate remaining life a thousandfold.
• Leaving required thickness unchanged after a rerate or change in design conditions.
• Forgetting the separate 5-year external visual clock and the CUI follow-up that goes with it.
• Treating RBI and the class table as interchangeable without saying which governs. Under API 570, an RBI assessment that follows API 580 may set intervals instead of the class table, but the programme must state which basis applies to each circuit. See time-based vs risk-based intervals.

How Atlantis supports this

Atlantis NDT supplies the measured data the calculation depends on. That means UT thickness surveys at marked CMLs, automated corrosion mapping at elbows, tees and flow disturbances, profile radiography through insulation, and guided-wave screening where access is limited. The work is done by ASNT-certified technicians under ASNT Level III oversight. Each report carries the CML identifiers, technique, instrument and calibration, and the technician's certification, so readings from one turnaround to the next are comparable. Your API 570 authorized piping inspector and piping engineer select the corrosion rate, set the interval and own the inspection plan. See piping circuit and CML inspection and corrosion mapping, or request a quote within 24 hours.

FAQ

Class 2 hydrocarbon piping, TML readings show 2 mils per year: what is the inspection interval?

Calculate remaining life as (current thickness − required thickness) ÷ 0.002 in/yr. The thickness interval is half that remaining life or 10 years, whichever is less. With healthy wall, the 10-year cap usually governs. Check the limiting CML, not just the average.

What is the API 570 Class 2 thickness measurement interval?

The recommended maximum in the 4th edition table is 10 years, limited by half the remaining life. Secondary summaries report the same for the 5th edition; confirm in your licensed copy.

How do you calculate the API 570 half remaining life interval?

Divide the wall above required thickness by the governing corrosion rate to get remaining life, then halve it. Compare that with the class maximum and use the shorter.

Should I use the long-term or short-term corrosion rate?

Compare both and identify which gives the shorter remaining life. The inspector, with a corrosion specialist, selects the rate that best reflects current conditions. The conservative (faster) rate is the usual default.

What if remaining life is less than four years?

The 4th edition allows the interval to be the full remaining life, up to two years. Engineering review of repair, replacement or rerating usually follows.

How often is external visual inspection required for Class 2 piping?

Up to 5 years under the recommended-maximum table, including a CUI-focused visual and follow-up NDE on part of the susceptible insulated piping.

Can a Class 2 interval be longer than 10 years?

Not under the class table. Longer intervals need a documented RBI assessment that follows API 580, plus acceptance under your jurisdiction's rules.

How is the interval set for new Class 2 piping with no corrosion data?

Use rates from similar service or published experience. If none are available, take the first thickness readings within three months of service and set the interval once a rate is established.

How do I justify a piping inspection interval in the inspection plan?

Document the class basis, required thickness, CML history, both corrosion rates and the one selected, the remaining life, half-life versus the cap, and who approved it.

Who sets the API 570 interval, the NDE contractor or the inspector?

The owner-user's inspector or piping engineer, under the owner-user's quality system. NDE contractors provide the measurements.

For more on how corrosion rates drive intervals across API 510, 570 and 653, read remaining life calculations. To plan a CML survey on your Class 2 circuits, contact Atlantis NDT.