API 570 Inspection Intervals for Class 1 Hydrocarbon Piping

Short answer: under API 570 (current edition: 5th, February 2024), Class 1 piping has a recommended maximum of 5 years for both thickness measurements and external visual inspection. The thickness interval must also be no longer than half the calculated remaining life, whichever is shorter. External visual inspection includes a CUI check, and suspect insulated areas then get follow-up NDE. RBI can change these limits. Jurisdictional rules always apply on top.

That answers the "how often" question. The harder questions in practice are the ones this guide works through: does the line actually belong in Class 1, is it API 570 piping or DOT-regulated pipeline, what "thickness readings, visual, or both" means in a real inspection plan, and how to document an interval so that an auditor or the jurisdiction accepts it. Every number below comes from API's public material or federal regulation. Where a figure appeared in an older edition of API 570, we say so. Always confirm the wording in your licensed copy of the current edition.

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What API 570 requires for Class 1 piping

API 570 requires every in-service process piping system within its scope to be placed in a service class. The class sets the recommended maximum intervals for thickness measurement and external visual inspection, and the extent of follow-up CUI examination. Class 1 is the highest-consequence class, so it gets the shortest intervals and the largest CUI follow-up effort.

For Class 1, the code's recommended maximum-interval table gives:

• Thickness measurement: 5 years at most, and never longer than half the remaining life calculated from the governing corrosion rate.
• External visual inspection (including the CUI-focused visual): 5 years at most.
• CUI follow-up: after the external visual, a share of damaged-insulation areas and suspect locations in susceptible temperature ranges is examined by NDE or by removing insulation. Class 1 has the highest target percentages of the three classes.

For comparison, the same table gives Class 2 a 10-year thickness maximum and a 5-year visual maximum, and Class 3 10 years for both. The 5th edition, as summarised in secondary references, keeps those values and treats Class 4 (essentially non-flammable, non-toxic services) as optional. The detailed rule for Class 2 is covered in API 570 Class 2 intervals and corrosion rate.

The two clocks that run in parallel

Think of a Class 1 circuit as running two separate inspection clocks:

1. The thickness clock. It is set by the shorter of the class maximum (5 years) and half the remaining life. A fast-corroding line can be due well before 5 years.
2. The external visual clock. It is set by the class maximum (5 years). The external visual covers insulation condition, coatings, supports, hangers, vibration, leaks and CUI indicators. Its findings can trigger follow-up NDE and can shorten the thickness clock if they reveal damage.

The answer to "thickness readings, visual, or both?" is therefore both, on separate schedules that often line up in practice. Many owners schedule them together for efficiency, but the code treats them as separate requirements. Even if a Class 1 circuit has 40 years of calculated remaining life, it still needs an external visual within 5 years, and its thickness interval still cannot go past 5 years.

Is the line really Class 1? How the class is assigned

Classification is the owner-user's decision, made with the piping engineer and inspector and recorded in the inspection programme. API 570 bases it on the potential safety and environmental consequences if a leak occurs. The class follows the fluid and the location, not the pipe size or material. For more on how classes are assigned, see API 570 piping service classes explained.

Class 1 covers services where a leak has the highest potential to cause an immediate emergency, whether for safety or the environment. The 1998 (2nd) edition gave these examples, and later editions describe similar services. Check the current list in your copy:

• Flammable services that may auto-refrigerate on release and lead to brittle fracture.
• Pressurised services that may vaporise rapidly on release and form an explosive vapour cloud, such as C2, C3 and C4 streams.
• Gaseous streams with significant hydrogen sulfide content.
• Anhydrous hydrogen chloride and hydrofluoric acid.
• Piping over or next to water, and piping over public roads.

By contrast, on-site hydrocarbons that vaporise only slowly, hydrogen, fuel gas and natural gas were typical Class 2 examples, and most unit process piping falls into Class 2. That distinction matters for the query we see most often: "Class 1 hydrocarbon piping" is not every hydrocarbon line. A heavy gas-oil line and a pressurised propane line are both hydrocarbon service, but they usually belong in different classes. Over-classifying wastes inspection effort. Under-classifying is the bigger risk, because it sets intervals that are too long and is the kind of gap that PSM audits pick up.

Midstream facilities: API 570 or pipeline regulation?

At a midstream site the first question is which rulebook applies. API 570 was written for refining and chemical process piping, and it says it must not be used in conflict with regulatory requirements. Gas plant, fractionator and terminal process piping is normally managed under an API 570 programme, often because the facility is covered by OSHA Process Safety Management. Pipeline segments regulated by PHMSA under 49 CFR 192 (gas) or 195 (hazardous liquids) follow those rules instead. For example, both 192.481 and 195.583 require onshore atmospheric corrosion inspection at least once every 3 calendar years, at intervals not exceeding 39 months. Both name "under thermal insulation" as a location that needs particular attention. Map the boundary between the facility and the regulated pipeline on your drawings before you set intervals. A line cannot sit in both programmes at once without a documented decision about which rules control.

The half-remaining-life rule, worked through

API 570 calculates remaining life as the thickness available above the required minimum, divided by the corrosion rate. The required minimum is the larger of the pressure-design thickness and any structural minimum the owner applies. The corrosion rate is the governing short-term or long-term rate. The code's approach is to compare both and normally use the one that gives the shorter remaining life. The next thickness inspection is then due at the earlier of half that remaining life or the class maximum. For a step-by-step method, see long-term vs short-term corrosion rates.

The examples below use hypothetical numbers chosen to show the logic. They are not data from any facility.

Scenario A is the case behind the question "with readings averaging 2 mils per year, what interval does industry practice support?". On a Class 2 line those numbers would allow up to the Class 2 maximum of 10 years. On a Class 1 line the class cap of 5 years governs, however slow the corrosion. Scenario C shows why averaging readings across a circuit can mislead. API 570 expects the representative sample to include the condition monitoring locations (CMLs) with the earliest projected renewal dates. A localised hot spot sets the circuit's interval, not the average.

Justifying the interval in the inspection plan

A defensible inspection plan for a Class 1 circuit records:

• The circuit boundary, the class, and the reason for the class (fluid, release behaviour, location).
• The damage mechanisms considered, for example internal thinning, CUI, environmental cracking or injection-point corrosion, with reference to API 571 where relevant.
• The CML layout and the reasons it is representative (see CML and TML selection).
• The minimum required thicknesses and how they were derived.
• Short-term and long-term corrosion rates, which one governs, and why.
• The calculated next-inspection dates for thickness and for the external visual, and which limit set each one.
• Any RBI-based adjustment, with the review and approval the code requires.

External visual and CUI on Class 1 circuits

The external visual covers more than the pipe surface. Under API 570 it looks at the insulation system, paint and coatings, supports and hangers (including spring supports that have bottomed out and dummy legs that may hold water), misalignment, vibration and leaks. API RP 574 supports this with practical inspection guidance. On insulated Class 1 lines, the visual feeds the CUI programme:

• Where CUI is likely. Carbon and low-alloy steel operating in the temperature bands where moisture condenses and re-evaporates. Intermittent service that cycles through those bands. Austenitic stainless steel in the range where external chloride stress corrosion cracking can occur. API 570 and API RP 583 give the current temperature ranges, which have been revised since earlier editions, so take them from your current copies.
• Where to look on the line. Breaks in the jacketing at deadlegs, vents and drains. Hangers, supports and bolted shoes. Valves and fittings with irregular insulation. Steam-tracer penetrations. Insulation ends at flanges and on vertical runs. Hardened or missing caulking. Bulging or stained jacketing. Low points downstream of known breaks. Old insulation plugs left from earlier thickness readings.
• Follow-up. The code sets target percentages for examining damaged-insulation areas and suspect areas by class, with Class 1 the highest. If significant CUI is found, the examination is widened, up to the whole circuit where warranted. Owners with documented CUI experience may adjust the targets, and the code allows for that.

Lines with a known remaining life well beyond the next interval, or that are well protected against external corrosion (for example effectively sealed systems, or temperatures that keep water out), may be excluded from the CUI NDE targets. The reason must be recorded. Our CUI inspection service page covers how screening is carried out in the field.

NDE methods for Class 1 piping and what each one finds

API 570 leaves the choice of method to the inspector and the owner's programme. The aim is to detect the damage mechanism you expect. The table below gives a practical summary.

API RP 583 describes the strengths and limits of CUI methods in more depth, including guided wave, profile and real-time radiography, pulsed eddy current, neutron backscatter and thermography. For circuit and CML survey services, see piping circuit and CML inspection. For targeted area scanning, see corrosion mapping.

RBI, jurisdiction and PSM: what can change the interval

API 570 allows a risk-based inspection assessment, under API 580 and 581 principles, to increase or decrease the class interval limits and the extent of CUI inspection. When RBI is used, the code requires it to be reviewed and approved by the piping engineer and the authorized piping inspector, and to be repeated on a defined cycle or when conditions change. RBI is an engineering assessment that the owner commissions. It is not something an NDE contractor sets. Atlantis does not provide RBI. We mention it here only because it changes how intervals are applied.

Several layers of regulation sit on top of the code:

• OSHA PSM, 29 CFR 1910.119(j). Piping systems are covered equipment. Inspection and testing must follow recognised and generally accepted good engineering practices, at a frequency consistent with manufacturers' recommendations and good engineering practice, and more often if operating experience shows it is needed. Each inspection must be documented with the date, the inspector, the equipment identifier, a description of the work and the results. API 570 is widely used as that practice for process piping.
• EPA Risk Management Program (40 CFR 68). Facilities covered by RMP Program 3 have mechanical integrity requirements that parallel PSM.
• State and local jurisdictions. Some jurisdictions set their own requirements for certain piping or pressure systems. API 570 lists applicable jurisdictional requirements as one of the criteria for setting intervals.
• PHMSA for regulated pipeline segments, as described above.

Canada note

In Alberta, ABSA's AB-506 (Inspection and Servicing Requirements for In-Service Pressure Equipment) links pressure piping inspection to API 570 practice, with an outer limit on external inspection intervals unless an accepted RBI programme sets them. Ontario (TSSA) and other provinces apply their own pressure equipment regulations, under the CSA B51 framework. Federally regulated pipelines follow CSA Z662 through the Canada Energy Regulator. Confirm the current provincial document before you set intervals for registered piping.

Common mistakes with Class 1 intervals

• Extending Class 1 thickness intervals past 5 years because corrosion is slow. The half-life calculation can shorten the interval but never lengthens it beyond the class maximum without a documented RBI basis.
• Treating the external visual as optional when thickness is fine. The external and CUI visual runs on its own 5-year clock.
• Averaging CML readings to get the circuit rate. The worst credible location governs. Average rates hide localised damage.
• Leaving injection points and deadlegs in the parent circuit. API 570 treats injection points as their own circuits with defined boundaries. Earlier editions also gave them a shorter thickness interval than any class (3 years in the 1998 edition), so check the current table.
• Forgetting small-bore and secondary piping. API 570 has historically required Class 1 secondary small-bore piping to be inspected like primary piping, while it is optional in lower classes. Confirm in the current edition.
• Not resealing insulation plugs. Every inspection port is a new place for water to get in.
• Undocumented classification. If the class is not recorded with a reason, the interval cannot be defended.

How Atlantis supports this

Atlantis NDT performs the NDE that an API 570 programme needs: UT thickness and CML surveys, corrosion mapping and phased array, profile radiography through radiography crews licensed where the work is, guided wave screening and CUI screening. All work is carried out by ASNT-certified technicians under ASNT Level III oversight. We deliver the data, with locations, readings and findings, to your API-certified authorized piping inspector, who stays the inspector of record. The class, intervals and any RBI basis remain decisions for the owner and inspector under the code and your jurisdiction. See API 570 piping inspection support and guided wave testing. Our teams have completed more than 1,500 inspection activities. Ask for a CML and CUI survey quote.

FAQ

How should API 570 inspection intervals be interpreted for Class 1 hydrocarbon service at a midstream facility, including external visual, CUI and thickness measurement frequencies?

First confirm that the piping is facility process piping under API 570 and not a PHMSA-regulated pipeline. If it is Class 1 API 570 piping, the thickness interval is the shorter of 5 years and half the remaining life. The external visual, including CUI, is due at most every 5 years, with follow-up NDE at suspect insulated areas at the Class 1 targets. Jurisdictional and PSM requirements apply on top.

What is the typical inspection interval for Class 1 hydrocarbon piping circuits in a refinery, and what governs the method: thickness readings, visual, or both?

Both. API 570 sets a 5-year maximum for each on Class 1 piping. The thickness interval is also capped at half the remaining life. The method within each inspection (spot UT, scanning, profile RT, guided wave screening) is chosen to detect the expected damage mechanism.

For Class 2 hydrocarbon piping with readings averaging 2 mils per year, what interval does practice support, and how is it justified?

For Class 2, API 570 allows thickness intervals up to 10 years, or half the remaining life if that is shorter, and external visual up to 5 years. Base the calculation on the governing rate at the worst CMLs, not the average, and record the rate selection and the limit that governs in the inspection plan.

Can RBI extend Class 1 intervals beyond 5 years?

API 570 allows a documented RBI assessment, reviewed and approved as the code requires, to change interval limits. It is an owner-commissioned engineering assessment that must be repeated on a defined cycle and when conditions change.

Does the Class 1 external visual require insulation removal?

Not across the whole line. The visual assesses insulation condition and CUI indicators. Follow-up NDE or insulation removal is then targeted at damaged and suspect areas at the Class 1 target extent.

Who decides the piping class?

The owner-user, working with the piping engineer and the authorized inspector, records the classification and its basis. An NDE contractor provides data but does not classify piping.

Are injection points inspected on the Class 1 schedule?

API 570 treats injection points as separate circuits with defined upstream and downstream limits, because corrosion there can be accelerated. Earlier editions gave them a shorter thickness interval than any class. Use the value in your current edition.

Which edition of API 570 applies in 2026?

The 5th edition, published February 2024, is current. Many free copies online are older editions, so check figures and clause numbers against the current edition and any addenda.

Does OSHA PSM require API 570 intervals?

PSM requires inspection frequencies consistent with manufacturers' recommendations and recognised and generally accepted good engineering practices, and more often if operating experience shows it is needed. API 570 is widely used as that practice for process piping.

Planning a Class 1 thickness and CUI campaign? Talk to our Level III team.