Small-Bore and Auxiliary Piping Under API 570

Short answer: API 570 treats small-bore piping (historically defined as NPS 2 and smaller) by what it does, not by its size. Small-bore lines that are part of the primary process must meet every requirement that applies to the larger pipe. Secondary small-bore lines in the higher-consequence piping classes are inspected like primary piping, while lower-class secondary lines and auxiliary piping such as vents, drains, seal and analyzer lines are inspected at the owner-user's discretion, usually guided by risk. Socket-weld acceptance criteria come from the construction code, not from API 570.

This guide explains how that split works in practice, which failure modes actually take small-bore connections out of service, which NDE methods find them, and how to read a contractor's quality procedure when it cites socket-weld acceptance criteria. API 570 is a copyrighted code now in its fifth edition (2024); clause numbers below are given only where they were checked, and you should always confirm the wording against your licensed copy of the current edition.

What API 570 means by small-bore, secondary and auxiliary piping

Three overlapping labels drive the inspection requirement, and most program gaps come from mixing them up. The size label says how big the line is; the service label says whether it is primary process piping, secondary piping, or auxiliary piping; the class label says how bad a leak would be.

Small-bore piping (SBP). The fourth edition of API 570 defined small-bore piping as pipe or pipe components NPS 2 and smaller. That is a size definition only. It does not, on its own, make a line optional to inspect. Readers working from the fifth edition should confirm the definition in its terms-and-definitions section; we have not seen a published change, but we have not verified the fifth-edition wording line by line.

Primary process piping. This is the piping that carries the process stream in normal operation: the line between the pump and the exchanger, the overhead line, the transfer line. Small-bore primary process piping exists all over a unit, for example small product lines, chemical feed lines and bypasses, and it is not given any relief because of its diameter.

Secondary piping. These are small lines that branch off primary process piping and are normally isolated or used intermittently: level-bridle connections, sample points, bypasses around control valves, instrument tie-ins and the like. They see the process fluid but not continuous flow.

Auxiliary piping. The fourth edition describes auxiliary piping as instrument and machinery piping, typically small-bore secondary process piping that can be isolated from primary piping but normally is not. Examples the code gives include flush lines, seal oil lines, analyzer lines, balance lines, buffer gas lines, drains and vents. Much of this hardware sits on pumps and compressors, which matters because that is where vibration lives.

Piping class. API 570 sorts piping into classes by the consequence of a leak. Class 1 is the highest-consequence service (for example flammable services that can autorefrigerate and cause brittle fracture, or toxic services that can affect people quickly), Class 2 covers most on-site hydrocarbon process piping, Class 3 covers services that are flammable but less likely to create a severe event, and Class 4 covers essentially non-flammable, non-toxic services. The class assignment is the owner-user's; our guide to Class 1 hydrocarbon intervals covers how the class drives the thickness and external inspection intervals.

What is mandatory and what is optional

The fourth edition set out a simple rule, and the logic carries into practice regardless of edition: primary small-bore piping is in scope like any other primary piping; secondary small-bore piping in Classes 1 and 2 is inspected like primary piping where RBI is not used; secondary small-bore piping in Classes 3 and 4 is optional at the owner-user's discretion; and inspection of auxiliary small-bore piping is optional and is usually set by a risk assessment. Threaded connections follow the same small-bore or auxiliary rules as the line they sit on.

"Optional" does not mean "ignore". The code places the decision with the owner-user, and the owner-user is expected to make it deliberately and record it. When an auditor or a process safety reviewer looks at a small-bore program, the question is not whether every drain was thickness-tested, but whether there is a documented basis for what was included and what was not. A plant that has never written down why its Class 3 auxiliary lines are excluded is in a weaker position than a plant that excluded them after a risk screen and can show the screen.

Where the site runs a formal risk-based inspection program under API 580 and 581, the RBI analysis can set the scope and frequency for these lines instead of the class-based rules. RBI is an engineering assessment the owner commissions; it is outside what Atlantis offers, and we mention it only because it changes which rule applies.

How small-bore connections actually fail

Thickness programs are built around general and localized wall loss. Small-bore connections often fail by other mechanisms, which is why a site with an excellent CML program can still have repeated small-bore leaks.

Vibration-induced fatigue. A small branch with a valve or instrument hanging off it acts as a cantilever with a concentrated mass at the end. If the parent pipe vibrates near the branch's natural frequency, the socket or fillet weld at the root of the branch sees cyclic stress. Cracks start at the weld toe or the weld root and run through a full-thickness wall. The fourth edition specifically called out environmental and fatigue cracking on non-braced small-bore piping near compressors and other sources of flow-induced vibration as a factor in deciding auxiliary-line inspection. A thickness reading at that connection will look perfect right up to the leak.

Mechanical overload. Vents, drains and level bridles get stepped on, used as hand-holds, hit by scaffolding and loaded by unsupported valve weight. The fourth edition specifically flagged mechanical overload of vents, drains and bridles as needing attention. Bent nipples, cracked welds and sheared threads come from this, not from corrosion.

Thread-root corrosion and thread failure. A threaded joint removes metal at the thread root, so the effective wall is already reduced before any corrosion starts. Corrosion, crevice attack under thread compound, and fatigue all concentrate there. Seal-welded threaded joints add a further crack initiation site at the seal weld.

Corrosion under insulation. Small lines are often insulated or heat-traced along with the parent line, and their insulation is easier to damage and harder to seal. The fourth edition named insulation stripping and radiography as the preferred methods for insulated small-bore piping. See CUI monitoring for how screening and follow-up work on insulated systems.

Deadleg and stagnant-end corrosion. Many secondary small-bore lines are deadlegs in all but name. Water, chlorides and corrosive species settle at the closed end. Where a small line is also an injection or mix point, the dedicated injection point circuit rules apply as well.

Thermowell damage. Thermowells are small-bore attachments in their own right. The fourth edition listed thermowell fatigue and erosion among the considerations for auxiliary-line inspection, because a thermowell that fatigues off can leave an open hole in a high-pressure line.

Damage carried over from the parent line. If the parent line has a corrosion history, its small-bore branches see the same fluid and often less flow, so corrosion experience on adjacent primary systems is one of the factors the code tells owner-users to consider.

NDE methods for small-bore piping: what each finds

Method choice for small-bore piping is a matter of geometry and damage mechanism. Standard 0-degree thickness probes struggle on small diameters and curved fittings; socket welds hide their roots; threaded joints cannot be measured by a single point. Our method-selection guide covers the general logic; the table below applies it to small-bore work.

In practice, profile radiography does a lot of the work on small-bore lines, which is why the code has historically pointed to it, and why CML selection should include threaded connections that can be radiographed. For connections at risk of fatigue, the program usually pairs a visual check of bracing and support with surface examination or PAUT at the branch weld. Thickness alone is the wrong tool for a fatigue problem. Where small-bore connections keep failing on rotating equipment, the fourth edition noted that renewal with a heavier wall or an upgraded joint design may be warranted; that is a design decision by the owner, not an inspection finding.

Atlantis performs these methods through ASNT-certified technicians; see radiographic testing and phased array inspection. Radiography is carried out by crews licensed in the state where the work is done.

Socket welds: where the acceptance criteria actually come from

A common question from QA leads reviewing a contractor's quality procedure is: what is the standard acceptance criterion for visual inspection of socket weld root fusion in hydrocarbon piping? The direct answer is that root fusion of a socket weld cannot be confirmed by visual examination, because the root is inside the socket, and that acceptance criteria for new welds come from the construction code the piping was built to, which for most process plants in the US is ASME B31.3.

API 570 is an in-service code. It governs inspection, repair, alteration and rerating after the piping is in service, and for repair and alteration welding it points back to the principles of the construction code. It does not contain its own visual acceptance table for new socket welds. A contractor procedure that cites "API 570" as the source of socket-weld visual acceptance criteria is citing the wrong document.

ASME B31.3 does three things that matter for socket welds. It sets a minimum fillet weld size related to the pipe's nominal wall thickness. It shows an approximate gap (about 1/16 in.) between the pipe end and the bottom of the socket before welding, which is there so that weld shrinkage does not pull the pipe against the socket bottom and crack the root. And it tabulates acceptance criteria for weld imperfections by examination method and fluid service category, applied to what visual examination can actually see: surface cracks, surface porosity, undercut, reinforcement, and fillet size. Check the current edition of B31.3 for the exact table, fluid service categories and numbers; we do not reproduce code tables here, and edition changes do occur.

So a defensible contractor procedure for hydrocarbon socket welds usually says:

• Fit-up is checked before welding, including the gap, by visual measurement at fit-up or by a witnessed hold point, because it cannot be checked afterwards by eye.
• Visual acceptance of the completed weld follows the construction-code table for the applicable fluid service, covering surface imperfections and fillet size and profile.
• Where the engineering design or owner specification requires it, volumetric examination such as radiography is used to confirm gap and root condition; profile RT is a common way to show the socket gap after welding.
• Surface examination (MT or PT) is applied where the owner specification calls for it, for example in severe cyclic service.
• Examination personnel are qualified to the owner's written practice, typically ASNT SNT-TC-1A, and visual inspectors meet whatever the owner or code specifies.

If a procedure claims that visual examination verifies root fusion, that is the point to challenge. For more context, see ASME B31.3 process piping requirements.

Building the small-bore part of a piping inspection plan

A practical small-bore plan sits inside the circuit-based API 570 program. The approach most owner-users take looks like this, described qualitatively:

1. Inventory. Walk the circuit isometrics and the field, and record each small-bore connection: size, service type (primary, secondary or auxiliary), joint type (socket weld, threaded, seal-welded threaded, butt weld), whether it is braced, what mass hangs on it, and whether it is insulated.
2. Classify. Apply the class of the parent piping. A small branch on a Class 1 line is not automatically Class 3 because it is small.
3. Screen for fatigue risk. Note proximity to compressors, reciprocating pumps, control valves with high pressure drop, and lines with a history of vibration. Unbraced connections with heavy valves near these sources go to the top of the list.
4. Decide in or out, and record why. Mandatory lines go into the program. For optional lines, document the decision and its basis.
5. Assign CMLs and methods. Thickness CMLs on primary and Class 1 and 2 secondary SBP, with profile RT where geometry or insulation makes UT impractical; visual and surface or PAUT checks at fatigue-sensitive branch welds; profile RT for threaded connections selected as CMLs.
6. Link to the parent circuit's corrosion rate. Small-bore CMLs feed the same long-term and short-term corrosion rate logic; see corrosion rate calculation.
7. Close the loop with operations and maintenance. Small-bore findings often lead to bracing, support or redesign actions. Those recommendations go through the owner's repair-recommendation process; the fifth edition added requirements on reviewing and deferring inspection repair recommendations, so confirm how your program handles deferrals.

Worked example, described qualitatively

Consider a Class 2 hydrocarbon line downstream of a reciprocating compressor. It has a 3/4-inch level-bridle connection, two 3/4-inch drains and a 1/2-inch pressure gauge tie-in, all socket-welded, one drain with a threaded plug. The bridle connection is secondary small-bore piping in a Class 2 line, so under the fourth-edition logic it is inspected like primary piping: it gets thickness CMLs and is included in the external visual inspection. Because it is near a reciprocating machine and carries the weight of the bridle valves, the plan also calls for a visual check of bracing and a surface or PAUT examination of the branch weld at a defined frequency set by the owner's inspector.

The drains are secondary small-bore lines in the same Class 2 service and are treated the same way; the threaded drain is selected as a radiographic CML so thread-root condition and plug engagement can be assessed. The gauge tie-in is instrument piping, which falls under auxiliary piping; inspection is optional, but because it sits on an unbraced connection close to the compressor, the owner's risk screen keeps it in the program for visual and bracing checks. Every decision, including any line deliberately left out, is recorded with its basis. Nothing in this example is an interval recommendation; the intervals are set by the owner's API-certified inspector under the code and any jurisdictional rules.

Common mistakes in small-bore programs

• Treating "small" as "optional". Primary small-bore piping and Class 1 and 2 secondary small-bore piping are in scope under the class-based rules.
• Relying on thickness to manage fatigue. A full-wall reading says nothing about a crack at the socket-weld toe.
• Losing small-bore CMLs between surveys. Small lines are modified frequently; if the isometric is not updated, the CML disappears and the corrosion rate history breaks.
• Leaving optional decisions undocumented. An excluded line with no recorded basis looks like an oversight in an audit.
• Citing the wrong code for acceptance. New-construction weld acceptance comes from the construction code, not from API 570.
• Ignoring insulation on small lines. Insulated small-bore lines are a classic CUI location; insulation stripping or profile RT are the historically preferred approaches.
• Not following up bracing findings. A missing brace found during visual inspection needs a repair recommendation, not just a note.

Regulatory overlay and the Canadian note

In the US, process piping in covered processes falls under OSHA's Process Safety Management standard, 29 CFR 1910.119, whose mechanical integrity element requires inspection and testing following recognized and generally accepted good engineering practices. API 570 is widely used as that practice for in-service piping, and API has noted that its codes are referenced in federal and state regulations. Small-bore piping is not exempt from PSM because of its size: if it is part of a covered process, it is part of the mechanical integrity program. EPA's Risk Management Program (40 CFR Part 68) has parallel mechanical integrity requirements for program 3 processes. Confirm the specific obligations for your facility with your jurisdiction and your PSM coordinator.

In Canada, pressure piping is regulated provincially. In Alberta, ABSA administers the Pressure Equipment Safety Regulation, and owners with an integrity management system follow ABSA's requirements for in-service inspection. In Ontario, TSSA administers the boilers and pressure vessels regulation, which adopts CSA B51 for pressure piping. Provincial rules can affect registration, repairs and inspection authority, so confirm the requirements with the regulator in your province.

How Atlantis supports small-bore piping inspection

Atlantis performs the NDE that an API 570 program calls for on small-bore and auxiliary piping: profile radiography of small lines and threaded connections (by crews licensed where the work is done), small-footprint UT thickness surveys, PAUT and MT or PT at fatigue-sensitive branch welds, and visual examination of bracing and supports. Work is done by ASNT-certified technicians under ASNT Level III oversight, to procedures written for the geometry. We deliver the results to the owner's API-certified inspector, who remains the inspector of record and decides scope, intervals and repairs. See piping circuit and CML inspection. Request a quote for small-bore NDE; we respond within 24 hours.

Frequently asked questions

What's the standard acceptance criteria for visual inspection of socket weld root fusion in hydrocarbon piping service?

There is no visual criterion that can verify socket-weld root fusion, because the root is hidden inside the socket. Visual acceptance of new socket welds in process plants normally follows the ASME B31.3 table of acceptance criteria for the applicable fluid service, covering surface imperfections and fillet size. Root condition and the pre-weld gap are controlled at fit-up and, where specified, confirmed by radiography.

Does API 570 apply to small-bore piping?

Yes. Small-bore primary process piping is inspected to all applicable requirements, and secondary small-bore piping in Classes 1 and 2 is inspected like primary piping where RBI is not used. Lower-class secondary and auxiliary lines are at the owner-user's discretion.

What size is small-bore piping in API 570?

The fourth edition defined small-bore piping as NPS 2 and smaller. Confirm the definition in the fifth edition (2024) against your licensed copy.

Is auxiliary piping inspection mandatory under API 570?

Under the fourth edition, inspection of auxiliary small-bore piping is optional and is typically set by a risk assessment that considers piping class, fatigue on unbraced connections, corrosion experience, CUI and thermowell damage. Optional decisions should be documented.

How should threaded connections be inspected?

Threaded connections follow the rules for the small-bore or auxiliary line they are on. Profile radiography is the usual way to assess thread-root corrosion and engagement, and threaded connections that can be radiographed are good candidates for CMLs.

What is the best NDE method for insulated small-bore piping?

The fourth edition named insulation stripping and radiography as preferred methods. Profile radiography can image wall loss through insulation on small lines without stripping, with follow-up where indications are found.

Can UT thickness readings find vibration fatigue on small-bore connections?

No. Fatigue cracks grow in full-thickness material. Visual checks of bracing, surface examination at weld toes and PAUT are the usual tools.

Does API 570 give the acceptance criteria for new piping welds?

No. API 570 is an in-service code. Acceptance criteria for new construction welds come from the construction code, such as ASME B31.3.

Who decides whether an optional small-bore line is inspected?

The owner-user, through its inspection program and its API-certified piping inspector. Contractors such as Atlantis perform the NDE once the scope is set.

What changed in the fifth edition of API 570?

API's announcement lists a defined role for an Inspection Supervisor, stronger requirements for pressure-relief devices, and new requirements on reviewing and deferring inspection repair recommendations. Check the edition directly for small-bore wording.

Ready to scope a small-bore survey? Ask for a quote or discuss profile radiography of socket and threaded connections. Related: API RP 574 inspection practices.

Sources: API 570 Piping Inspection Code, 4th edition (2016) and 5th edition announcement (api.org); ASME B31.3 Process Piping (asme.org); OSHA 29 CFR 1910.119. This page summarizes; it does not reproduce code text. Confirm requirements against the current edition and your jurisdiction.