API 570 Piping Service Classes 1-4 Explained

Short answer: API 570 sorts in-service process piping into four service classes by the consequence of a leak, not by its condition. Class 1 covers services where a leak could quickly become an emergency. Class 2 is the default for most unit piping. Class 3 covers lower-consequence flammable and off-site services. Class 4 covers essentially non-flammable, non-toxic utilities, where inspection is optional. The class sets the maximum inspection intervals and how much CUI follow-up is expected.

This guide explains how each class is defined, which deciding factors move a line up or down, what each class means for thickness and external visual intervals, and how to document the classification so an auditor or the jurisdiction accepts it. The class definitions below follow the API 570 4th edition (2016) text. Secondary summaries of the current 5th edition (February 2024) report the same four-class structure and the same maximum-interval table. Always confirm the wording against your licensed copy of the current edition and any addendum (API 570 announcement, api.org).

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What API 570 says about piping service classes

API 570 requires the owner-user to place every process piping system within its scope into a service class, unless the system's inspection is planned on the basis of risk-based inspection (RBI). The reasoning is simple: inspection resources are finite, so the code steers more frequent and more extensive inspection toward the piping where a loss of containment would do the most harm to people or the environment.

Three points in the code's framing are easy to miss:

• The class reflects consequence, not condition. A badly corroded water line is still Class 4. A brand-new propane line is still Class 1. Condition is handled separately, through corrosion rates and remaining life.
• The owner-user must keep a record of fluids and their classes. API 570 requires a list of the process fluids handled and the class assigned to each. NFPA 704 hazard ratings are cited as a helpful input when classifying fluids.
• Classes must be revisited when service changes. If operating conditions change, for example a hydrocarbon stream is heated so it would now flash on release, the class and the inspection plan should be reviewed and updated.

The code also allows owner-users to build a more detailed consequence scheme than the four classes if they want finer resolution. That scheme would weigh explosion, fire, toxicity and environmental effects, and API 570 points to API 580 for consequence-of-failure guidance. Many sites stay with the simple four-class scheme for non-RBI piping because it is easy to apply consistently and easy to audit.

The classification is a decision for the owner-user's inspection organisation: the API 570 authorized piping inspector, the piping engineer and, where relevant, a corrosion or materials specialist. NDE contractors do not assign classes; they need to know the class so the inspection scope matches it.

Class 1: highest potential for an immediate emergency

Class 1 is for services where a leak could quickly become a safety or environmental emergency. In the 4th edition, the examples fall into recognisable groups (paraphrased here):

• Flammables that can auto-refrigerate on release and chill the pipe enough to cause brittle fracture.
• Pressurised services that vaporise rapidly when released, such as C2, C3 and C4 streams, forming vapour clouds that can explode. The code ties "rapidly vaporising" to a low atmospheric boiling point, or to operation above the atmospheric boiling point, which is why high-temperature services can end up here.
• Sour gas with a significant hydrogen sulfide content (the 4th edition sets the line at more than 3 wt% H2S in a gaseous stream).
• Specific toxic acids: anhydrous hydrogen chloride, and hydrofluoric acid in main and trace acid services (with a cross-reference to API RP 751).
• Location-driven cases: piping over or next to water, and piping over public roads. For over-water piping, the code points to national and local rules such as Department of Transportation and Coast Guard requirements.
• Flammables above their auto-ignition temperature. These ignite on release without needing an ignition source.

The last group catches many people out. The 4th edition illustrates it with gasoline. At ambient temperature on site, gasoline is above its flash point but below its boiling point, so it is Class 2. Gasoline at a high enough temperature to auto-ignite belongs in Class 1. The fluid is the same; the operating temperature changes the consequence. A dedicated guide covers API 570 Class 1 hydrocarbon inspection intervals in detail.

Class 2: the default for most unit process piping

Class 2 is the catch-all: services that do not belong in another class. API 570 describes it as covering most unit process piping and some off-site piping. Typical examples given in the 4th edition include:

• on-site hydrocarbons that would vaporise slowly on release, meaning they operate above their flash point but below their boiling point;
• on-site hydrogen, fuel gas and natural gas;
• on-site strong acids and caustics.

The word "on-site" matters. Several of these services move down to Class 3 when the same fluid runs off-site, for example in remote pipe racks or tank-farm runs, because fewer people and less equipment are exposed. Class 2 lines usually make up most of a refinery or petrochemical unit's CML population, so the way Class 2 intervals are set has the largest effect on the inspection workload. Setting a Class 2 interval from measured data is covered step by step in setting a Class 2 piping interval from a measured corrosion rate.

Class 3 and Class 4: lower consequence and utility services

Class 3 covers services that are flammable but would not vaporise significantly if they leaked (operating below the flash point), and flammable services in remote areas operating below their boiling point. The code also allows services that are harmful to human tissue to be placed in Class 3 when they are in remote areas. The 4th edition's examples include on-site hydrocarbons below their flash point, off-site distillate and product lines to and from storage and loading, tank-farm piping, off-site acids and caustics, and off-site hydrogen, fuel gas and natural gas. It also includes a residual group: other lower-risk hydrocarbon piping that does not fit Class 1, 2 or 4.

Class 4 covers services that are essentially non-flammable and non-toxic, which includes most utilities. The 4th edition's examples include steam and condensate, air, nitrogen, water (including boiler feedwater and stripped sour water), lube and seal oil, ASME B31.3 Category D services, and plumbing and sewers. Inspection of Class 4 piping is optional under API 570. When it is done, it is driven by reliability and business impact rather than safety or environmental consequence.

"Optional" does not mean "ignored". A steam header failure can still injure people, shut down a unit or trigger a jurisdictional issue: steam piping connected to boilers can fall under boiler and pressure piping rules in some states and provinces. Many owner-users therefore apply a reliability-based programme to Class 4 piping, with lighter-touch thickness surveys on known problem services such as condensate return. That choice should be written into the owner-user's inspection procedures so it is applied consistently.

How the class drives inspection intervals and CUI scope

Without RBI, API 570 sets inspection intervals using four inputs: the corrosion rate and remaining-life calculations, the service class, the jurisdiction's requirements, and the judgement of the inspector and piping engineer. For Classes 1 to 3, the time between thickness measurements should not exceed half the remaining life or the class maximum in the code's recommended-maximum-interval table, whichever is shorter. The 4th edition adds a special rule for short remaining lives: when less than four years remain, the interval may be the full remaining life, up to a maximum of two years.

*Values as given in the API 570 4th edition recommended-maximum-interval table and reported unchanged for the 5th edition in secondary summaries. Injection points have their own thickness maximum, and soil-to-air interfaces are inspected visually on the class interval. Confirm every figure against your licensed copy of the current edition and against your jurisdiction.

The external visual inspection includes a check for corrosion under insulation (CUI) and for insulation condition. API 570 then expects follow-up NDE or insulation removal on a share of susceptible insulated piping, and that share depends on class: highest for Class 1, lower for Class 2 and Class 3, optional for Class 4. These percentages are targets for systems with no CUI history and should rise if significant CUI is found. Our CUI monitoring guide covers this follow-up work.

Two further points on intervals. First, the code says intervals must be reviewed after each inspection and after any significant change in operating conditions. Second, piping in non-continuous service may count only years of actual service instead of calendar years. This applies only when the idle piping is isolated from the process and protected from corrosive conditions, for example inert-gas purged.

A worked classification, described step by step

Take a hypothetical refinery hydrotreater area with five circuits. The question for each one is the same: what happens in the first minutes after a leak?

1. Reactor effluent with high-pressure hydrogen and light ends. On-site hydrogen alone points to Class 2. Next, check whether the stream holds enough light hydrocarbon to flash into a vapour cloud. Also check whether it operates above the auto-ignition temperature of its hydrocarbons. Either would push it into Class 1. Many sites put high-temperature reactor loops in Class 1 for that reason, but the decision rests on the actual process data.
2. Sour gas from the high-pressure separator. Look up the H2S concentration in the gas. If it is above the code's threshold for a gaseous stream, the line is Class 1 whatever its temperature.
3. Naphtha rundown from the stabiliser to off-site storage. On-site, a naphtha line above its flash point is typically Class 2. The section that runs off-site to the tank farm can be Class 3, provided it is genuinely remote and below the boiling point. That split creates a class break, which is worth showing on the isometric.
4. Diesel product line at ambient temperature, running over a public road. The fluid on its own would be Class 3, below its flash point. The road crossing is a location trigger for Class 1, so that span is classified for its location.
5. Nitrogen purge header and cooling water. Class 4. Inspection is optional, but the site may still schedule reliability surveys of the cooling water piping because of under-deposit corrosion and MIC history.

The result is an area with Class 1 to Class 4 circuits, several class breaks within single process lines, and a written basis for each class. That basis — process data, flash and boiling points, H2S content and location — is what an auditor will ask to see.

NDE methods by class: matching scope to consequence

The class does not change which NDE methods are technically suitable; the damage mechanism does that. The class changes how much coverage is justified and how quickly findings must be followed up. In practice:

• UT thickness at CMLs is the backbone for all classes with thickness programmes. Class 1 circuits usually get denser CML placement at fittings, injection and mix points, and dead legs. See piping circuit and CML inspection.
• Automated UT corrosion mapping (encoded scanning) finds the true minimum in a defined area where single-point readings might miss localised loss. It suits Class 1 and Class 2 locations with localised attack. See corrosion mapping.
• Profile radiography sees through insulation for wall loss and CUI on small and medium bore lines. Crews must be licensed by the radiation control authority where the work takes place.
• Guided-wave screening covers long runs, road crossings, sleeves and soil-to-air interfaces from one location. It is a screening method: indications need quantitative follow-up with UT or RT. See guided wave testing.
• Phased array UT and TOFD are used for weld and cracking concerns in services where environmental cracking is a credible mechanism, which often coincides with Class 1 sour or caustic services.
• Visual examination under the external inspection programme, including insulation condition, supports, and soil-to-air interfaces.

Method selection by damage mechanism is covered in more depth in NDE method selection by damage mechanism.

Common mistakes with piping classes

• Classifying by fluid name only. The same hydrocarbon can be Class 1, 2 or 3 depending on temperature relative to its flash point, boiling point and auto-ignition temperature, and on whether it is on-site or remote.
• Not updating after a management-of-change. A temperature increase, a new crude slate with more sulfur, or a rerouted line can change the class. The code expects classes and plans to be reviewed when service changes.
• Missing location triggers. Over-water and over-road spans can be Class 1 even when the fluid is benign by process criteria, so the class can change part-way along a line.
• Treating Class 4 as "no inspection ever". Inspection is optional under API 570, but a written reliability basis is better practice. Separate boiler or pressure piping rules may still apply to some utility services.
• Mixing RBI and classes without saying so. RBI-planned piping is exempt from the class requirement. The inspection programme should state clearly which circuits use RBI under API 580 and which use the class-based intervals.
• No record of fluids and classes. API 570 requires this record. Without it, the class shown on the isometric cannot be traced back to its basis.

Regulatory overlay in the US and Canada

In the United States, API 570 is widely treated as recognised and generally accepted good engineering practice (RAGAGEP) for process piping covered by OSHA's Process Safety Management standard, 29 CFR 1910.119. Paragraph (j) of that standard requires inspection and testing of process equipment, including piping systems, at frequencies consistent with applicable manufacturer recommendations and good engineering practice, and more often if operating experience shows it is needed. EPA's Risk Management Program rule (40 CFR Part 68) has parallel mechanical integrity provisions for covered processes. Some states and cities add their own process safety rules, so check local requirements.

API 570's buried piping section explicitly excludes piping regulated by the US Department of Transportation. Transmission and distribution pipelines under PHMSA's 49 CFR Parts 192 and 195 follow those regulations, not API 570 service classes. The boundary at a plant fence is covered in API 570 vs ASME B31.4/B31.8: where the pipeline boundary sits.

In Canada, provincial pressure-equipment regulators set the framework. In Alberta, ABSA's in-service requirements for pressure equipment integrity management programmes (AB-506) apply, and many owners reference API 570 within their accepted programme. Other provinces, such as Ontario through TSSA, have their own requirements. Confirm with your provincial regulator how API 570 classes are recognised within your integrity programme.

How Atlantis supports this

Atlantis NDT performs the examinations an API 570 programme calls for. That includes UT thickness and CML surveys, automated corrosion mapping, profile and conventional radiography by licensed crews, guided-wave screening, phased array UT, TOFD, MT, PT and VT. All of it is carried out by ASNT-certified technicians under ASNT Level III oversight. We scope coverage to the class your inspection organisation has assigned, and we deliver traceable data — CML identifiers, procedure, technician certification and calibration — to your API 570 authorized piping inspector. Classification, interval setting and acceptance remain with the owner-user's inspector and piping engineer. See API 570 piping inspection support or request a quote within 24 hours.

FAQ

What are the API 570 piping classes 1, 2, 3 and 4?

They are consequence-of-leak categories. Class 1 is the highest potential for an immediate emergency. Class 2 is most on-site unit piping. Class 3 is lower-consequence flammable and off-site service. Class 4 is essentially non-flammable, non-toxic utility service.

How do you assign an API 570 piping class?

Start with the fluid and its operating temperature relative to flash point, boiling point and auto-ignition temperature. Then check for toxic components such as H2S, HF or anhydrous HCl, and check location triggers such as over-water and over-road spans. Record the basis for each decision. The owner-user's inspector and piping engineer make the call.

What are examples of API 570 Class 1 piping?

In the 4th edition: flammables that can auto-refrigerate, rapidly vaporising light hydrocarbons such as C2 to C4 streams, gaseous streams above the H2S threshold, anhydrous HCl, HF acid services, piping over water or public roads, and flammables above auto-ignition temperature.

Is inspection of API 570 Class 4 piping optional?

Yes. API 570 leaves Class 4 intervals to the owner-user, based on reliability and business needs. Other rules, such as boiler or pressure piping regulations, may still apply to some utility services.

What is the inspection interval for Class 2 piping?

Under the 4th edition table, thickness measurement is at most 10 years or half the remaining life, whichever is less, and external visual at most 5 years. Secondary summaries report the same values for the 5th edition; confirm in your licensed copy.

Does tank farm piping count as Class 3?

The 4th edition lists tank farm piping as a Class 3 example. Location, temperature or toxicity can still put a specific line in a higher class.

Can the piping class change during the life of a line?

Yes. API 570 expects classes and inspection plans to be reviewed when service conditions change, for example when a temperature increase means a hydrocarbon would flash on release.

Do piping classes apply if we use RBI?

Piping planned under an RBI assessment that follows API 580 is exempt from the class requirement. RBI then sets intervals and scope. RBI is an engineering assessment the owner commissions; it is not an inspection activity.

Who is responsible for the API 570 piping classification record?

The owner-user. API 570 requires a record of the process fluids handled and their classes. Contractors performing NDE use the class to scope their work but do not assign it.

Are DOT pipelines classified under API 570?

No. API 570 excludes DOT-regulated piping from its buried-piping provisions, and transmission pipelines follow 49 CFR 192 or 195. Confirm the regulatory boundary at your facility.

Ready to scope a CML survey to your class register? Contact Atlantis NDT for a quote within 24 hours. For a wider view of the code, see the API 570 overview.