ASME B31.4 Liquid Pipeline 2026 — Inspection Requirements Decoded

ASME B31.4 for inspectors: the short answer

ASME B31.4, Pipeline Transportation Systems for Liquids and Slurries, sets requirements for the design, materials, construction, assembly, inspection, testing, operation and maintenance of liquid pipelines. These are pipelines carrying crude oil, refined products, liquid alcohols, liquid ammonia and carbon dioxide between facilities, plus piping carrying aqueous slurries of non-hazardous materials. The latest edition is 2025. For US hazardous liquid and CO2 pipelines the enforceable rules are in 49 CFR Part 195. Part 195 sets its own weld inspection, NDT, records, integrity management and breakout tank requirements, and incorporates B31.4 only for a narrow purpose.

This section adds to the overview above. It corrects statements that carry plant-piping practice onto liquid pipelines, and it maps what actually gets inspected, by which method, and under which rule.

Corrections to the overview above

• Weld acceptance is not "ASME V Article 9 plus AWS D1.1". For pipelines regulated under Part 195, 195.228 requires each weld to be inspected, with visual inspection supplemented by NDT. Acceptability is judged by Section 9 or Appendix A of API Std 1104, and Appendix A may not be used to accept cracks. AWS D1.1 is the structural steel code.
• Welder qualification is not "per ASME Section IX" alone. 195.222 allows qualification under API 1104 or ASME Section IX. It also bars a welder from using a process unless, within the preceding 6 calendar months, the welder has welded with that process and had a weld tested and found acceptable under API 1104.
• "In-service inspection follows PIM per 49 CFR 192/195". Part 192 is gas. Liquid pipeline integrity management is 195.452. B31.4 itself also has an operation and maintenance chapter (Chapter VII), so it does more than set "construction and initial inspection requirements".
• "Inspector qualifications: ASNT Level II plus API 510/570/653". API 510 and API 570 do not govern liquid line pipe. API 653 does apply to atmospheric breakout tanks under 195.432, and API 510 to pressure breakout tanks built to API 2510. For weld NDT, Part 195 requires written procedures and personnel trained in those procedures and the equipment used. Operator Qualification (Part 195 Subpart G) applies to tasks the operator has designated as covered tasks.
• "B31.4-qualified inspectors" and "3-6 month qualification". No such credential exists, and the timeline in the earlier FAQ has no basis.
• Disposition "per BS 7910 / API 579 / NB-23". For liquid pipelines, girth weld engineering critical assessment uses API 1104 Appendix A within its limits. Corroded pipe remaining strength is commonly evaluated with ASME B31G-type methods, which Part 195 references. Repairs follow 195 and the operator's procedures. NB-23 covers boilers and pressure vessels.

Code versus regulation: how little of B31.4 Part 195 adopts

Many people assume a US liquid pipeline is "built and inspected to B31.4". Engineering practice often is. The regulation works differently. 49 CFR 195.3 lists the documents incorporated by reference and the sections each applies to. In the current eCFR:

• ASME B31.4 (2019 edition) is incorporated only for 195.110(a), a design provision on external loads.
• API Std 1104 (21st edition, 2013, with errata and addenda) is incorporated for welding procedures, welder qualification and weld acceptance.
• ASME B31G (1991, reaffirmed 2004) is incorporated for remaining-strength evaluation of corroded pipe in the integrity management and corrosion sections.
• API Std 653 (3rd edition, December 2001, with addenda and errata) is incorporated for breakout tank provisions, including the inspection requirement in 195.432(b).
• NACE SP0502 (2010) is incorporated for external corrosion direct assessment.

Two consequences follow for inspectors. First, Part 195's own text, not B31.4, sets the minimum weld NDT, records and integrity assessment requirements. Second, the editions the regulation incorporates can be well behind the latest published. B31.4 is now at 2025, while the API 653 edition incorporated for breakout tanks dates from 2001. Operators often specify newer editions in their own procedures. Check 195.3 on the eCFR on the date of your work.

What B31.4 covers, and where it stops

ASME describes B31.4 as covering liquid pipeline systems between production fields or facilities, tank farms, above- or below-ground storage, gas processing plants, refineries, pump stations, ammonia plants, terminals (marine, rail and truck) and other delivery and receiving points. It also covers piping within pump stations, tank farms and terminals. Components in scope include pipe, flanges, bolting, gaskets, valves, relief devices, fittings and the pressure-containing parts of other piping components, along with hangers and supports. Building frames, stanchions and foundations are excluded.

Recent editions are organised in chapters, including inspection and testing (Chapter VI), operation and maintenance procedures (Chapter VII), and dedicated chapters for offshore pipelines (IX), carbon dioxide pipelines (X) and slurry and process water pipelines (XI). ASME notes that recent revisions updated the allowable-repairs content in Chapter VI. Confirm chapter content against your licensed copy of the current edition.

The boundary with plant piping matters in practice. Inside a refinery or chemical plant, process piping is normally designed to ASME B31.3 and inspected in service under API 570 (see our B31.3 explainer). Where the pipeline ends and plant piping begins is set by the code scope, by Part 195's applicability and exceptions in 195.1, and by the operator's documented boundary. Inspectors should confirm the boundary on drawings before assigning acceptance criteria to a weld near a terminal or plant fence.

A frequent search is about B31.4 requirements for pumps on crude oil pipelines. B31.4 covers the piping and pressure-containing components in pump stations. The pump itself is usually bought to the pump standard the operator specifies. Check the current B31.4 text for exactly what it requires of pump-station equipment rather than relying on a summary.

Construction weld NDT under Part 195

• Every weld is inspected, and visual inspection is supplemented by NDT (195.228).
• Any NDT process that clearly indicates defects that may affect weld integrity may be used, under written procedures, by personnel trained in those procedures and in the equipment used (195.234).
• Minimum sampling: at least 10% of the girth welds made by each welder or welding operator during each welding day, selected at random.
• 100% NDT, where practicable, of girth welds in locations listed in 195.234. These include certain waterway, railroad and road crossings, overhead and tunnel locations, and populated areas such as incorporated subdivisions. All tie-in welds and old girth welds in used pipe also require 100% NDT. Check the full list in the current rule.
• Construction records kept for the life of the facility (195.266): the total number of girth welds and the number examined by NDT, the number rejected and the disposition of each rejection, plus pipe, crossing, valve and test-station location information.

Integrity management: 195.452

Operators of hazardous liquid pipelines that could affect high consequence areas must run an integrity management programme under 195.452. The inspection-relevant points are:

• Assessment methods: in-line inspection tools able to detect corrosion and deformation anomalies (including dents, gouges and grooves), pressure testing under Subpart E, external corrosion direct assessment, or other technology the operator shows gives an equivalent understanding of pipe condition. The operator must consider the uncertainties in reported results, such as tool tolerance, when using ILI.
• Continual assessment at intervals of no more than five years, not to exceed 68 months, based on the operator's risk factors.
• Discovery of conditions: the operator must obtain enough information about a condition to decide whether it is a threat, generally within 180 days of an assessment unless that is impracticable and the operator notifies PHMSA. Anomalies are then sorted into the repair categories and timeframes the rule sets.

As on gas lines, most field NDE happens at excavations. Once the operator exposes and cleans the pipe at an ILI call, technicians measure remaining wall, map corrosion over the feature, record dimensions and examine for cracking with magnetic particle testing where cracking is possible. The measurements are referenced to the ILI feature, girth weld number and station or odometer position, so the operator can compare field results with the tool call. Remaining-strength calculations, repair category decisions and tool performance conclusions belong to the operator's integrity team.

Breakout tanks: where API 653 enters a liquid pipeline system

Breakout tanks relieve surges or receive and store liquid transported by a pipeline. Part 195 brings them into the inspection picture directly. Under 195.432(a), each in-service breakout tank must be inspected at intervals not exceeding 15 months, but at least once each calendar year. For atmospheric and low-pressure steel breakout tanks, 195.432(b) requires physical integrity to be assessed under API 653. It specifically excludes API 653's risk-based alternative to the standard internal inspection interval. Breakout tanks built to API 2510 are inspected under API 510.

That exclusion matters. An interval that would be acceptable for a refinery tank under API 653's risk-based provisions is not acceptable for a breakout tank under Part 195. For background on the tank side, see API 653 tank inspection and API 653 inspection intervals.

Canada: CSA Z662

Canadian liquid and gas pipelines are governed by CSA Z662, enforced by the Canada Energy Regulator for federally regulated lines and by provincial regulators for provincial ones. A Canadian scope that cites B31.4 should be checked against Z662 and the regulator's requirements before acceptance criteria are fixed.

Common mistakes on B31.4 inspection scopes

• Applying B31.3 or ASME Section VIII acceptance criteria to pipeline girth welds instead of API 1104 as Part 195 adopts it.
• Assuming the latest B31.4, API 1104 or API 653 edition is what Part 195 enforces, without checking 195.3.
• Using API 653's risk-based interval provisions on a breakout tank.
• Dig reports with no reference to the ILI feature, girth weld or station, which makes them useless for ILI validation.
• Missing the boundary between pipeline and plant piping at terminals and refineries.

How Atlantis supports B31.4 and Part 195 work

Atlantis performs field NDE for liquid pipeline operators and their contractors. We examine construction girth welds to API 1104 using radiography or encoded PAUT where the project allows, plus surface methods. At excavations we perform pipe-body thickness measurement, corrosion mapping and MT. On breakout tanks we perform tank NDE including floor MFL, with results going to the operator's API 653 inspector. ASNT-certified technicians work under ASNT Level III oversight. Atlantis does not run in-line inspection and does not make integrity, remaining-strength or repair decisions. See pipeline inspection services.

Request a scope for B31.4 girth weld NDT, with a quote response within 24 hours.

ASME B31.4 questions

What is the scope of ASME B31.4?

Liquid pipeline systems for crude oil, products, liquid alcohols, liquid ammonia and CO2, plus aqueous slurries of non-hazardous materials. This includes piping within pump stations, tank farms and terminals, from design through operation and maintenance.

What is the latest edition of B31.4?

The 2025 edition. 49 CFR 195.3 incorporates the 2019 edition, and only for 195.110(a).

What are the B31.4 inspection requirements for welds?

For US-regulated lines, Part 195 sets them: visual inspection supplemented by NDT, at least 10% of each welder's daily girth welds, 100% at listed locations and tie-ins, and acceptance to API 1104 Section 9 or Appendix A.

B31.4 vs 49 CFR 195: which applies?

Both, in different ways. Part 195 is the enforceable federal rule. B31.4 is the engineering code, used where the regulation or the operator's specification adopts it.

How often are breakout tanks inspected?

At intervals not exceeding 15 months, at least once each calendar year, with physical integrity assessed under API 653 (or API 510 for API 2510 tanks).

How often must liquid pipelines in HCAs be assessed?

Under 195.452, at intervals of no more than five years, not to exceed 68 months.

Does Atlantis run in-line inspection?

No. Atlantis performs NDE on welds, at excavations, on station piping and on breakout tanks.

Book dig-site NDE on a liquid line · Scope breakout tank NDE