{"slug":"/standards/asme-b31-4","title":"ASME B31.4: Liquid Pipeline Design, Welding and NDE Limits","description":"ASME B31.4 caps hoop stress at 0.72 SMYS, requires 10% of each day's girth welds examined, and holds a 4-hour hydrotest at 1.25x design pressure.","h1":"ASME B31.4 for Liquid and Slurry Pipelines: What the Code Actually Requires","answer":"ASME B31.4 governs pipelines carrying liquids and slurries between production, storage and delivery points. It caps hoop stress at 0.72 SMYS with no class-location system, ties weld acceptance to API 1104 rather than ASME Section V, requires at least 10% of each day's girth welds examined, and holds a hydrostatic test at 1.25 times design pressure for four hours.","expansion":"The code's authority is narrower than most people assume. B31.4 is a design and construction code for liquid transportation piping, and it stops at the fence of the facilities it connects: refinery and gas plant process piping belongs to B31.3, gas transmission to B31.8, and ammonia refrigeration to B31.5. It provides allowable stresses only between minus 20F and 250F, so heated heavy crude and asphalt lines running hotter fall outside it. Within scope, three things drive most of the engineering: a single 0.72 design factor applied uniformly rather than B31.8 class locations, a restrained versus unrestrained distinction that decides whether thermal strain is carried as stress in buried pipe or as displacement in station piping, and a welding chapter that adopts API 1104 wholesale. In the United States the code is not the top of the stack, because 49 CFR Part 195 incorporates it and then adds requirements the code never states.","source":"Written against ASME B31.4 Pipeline Transportation Systems for Liquids and Slurries; API Standard 1104 Welding of Pipelines and Related Facilities; 49 CFR Part 195; AMPP/NACE SP0169; ASME B31.8; ASME BPVC Section IX; ASME B31G; and API 579-1/ASME FFS-1.","table":{"caption":"ASME B31.4 requirements that most often decide a design review or an audit","columns":["Requirement","B31.4 basis","Criterion","Where it goes wrong"],"rows":[["Hoop stress design factor","Internal design pressure, Chapter II Part 2","Design factor 0.72 applied to SMYS, uniform onshore, with a longitudinal joint factor set by the pipe manufacturing process","Engineers import B31.8 class locations and derate to 0.60 or 0.50, or apply a joint factor of 1.00 to vintage furnace butt welded pipe that does not rate it"],["Restrained pipe longitudinal stress","Chapter II flexibility and stress provisions","Net longitudinal stress and the equivalent combined stress limited to 0.90 times SMYS in restrained pipe","Buried line modelled as unrestrained, which hides the thermal term and passes a design that will yield at an overbend or an anchor"],["Weld acceptance criteria","Chapter V adoption of API 1104","API 1104 Section 9 workmanship criteria, or Appendix A alternative acceptance where the fracture mechanics has been done","ASME Section VIII or Section V acceptance clauses cited on a pipeline girth weld, giving the wrong slag, porosity and undercut limits"],["Girth weld examination extent","Chapter V examination provisions","At least 10% of the girth welds completed each day over their full circumference, and 100% at crossings, populated areas, station and tank farm limits and tie-ins","The 10% daily sample is treated as the whole obligation and the 100% categories are never separated on the weld map before construction"],["Pressure test","Chapter VI testing provisions","At least 1.25 times internal design pressure at every point for a minimum of four hours, plus a further four hours at not less than 1.10 times design pressure where the line is not visually inspected","A buried line tested for a single four hour hold, so the eight hour obligation is unmet and the record cannot be reconstructed later"],["Temperature limits","Chapter I scope and the allowable stress basis","Metal temperature from minus 20F to 250F, roughly minus 29C to 121C","Heated crude, asphalt or steam traced product lines above 250F carried through detailed design with no supplementary analysis"],["External corrosion control","Chapter VIII corrosion control","External coating plus cathodic protection meeting the criteria of AMPP/NACE SP0169","Compliance claimed from a raw on-potential reading that still contains IR drop, with no instant-off or otherwise corrected polarised potential"]],"note":"Paragraph numbering shifts between editions of B31.4; always verify against the edition named in the project specification."},"facets":[{"q":"Does ASME B31.4 use class locations like B31.8?","a":"No. B31.4 applies a single design factor of 0.72 times specified minimum yield strength to onshore liquid pipeline, regardless of how many dwellings sit near the right of way. B31.8 varies its factor by class location because it carries compressible gas whose stored energy on rupture scales with population exposure. Importing class locations into a liquid design is not conservative practice, it is the wrong code open on the desk, and design review will find it."},{"q":"Which acceptance criteria apply to B31.4 girth welds?","a":"API 1104. The construction chapter of B31.4 adopts API 1104 for welding procedure qualification, welder qualification and weld acceptance, so radiographic and ultrasonic acceptance limits come from API 1104 Section 9 workmanship criteria or, where the project has done the fracture mechanics, from its Appendix A alternative acceptance standards. ASME Section VIII limits do not apply, and mixing the two produces reject calls that cannot be defended and accept calls that cannot be justified."},{"q":"How much girth weld NDE does B31.4 actually require?","a":"At least ten percent of the girth welds completed each day must be examined over their entire circumference, and specified locations require one hundred percent: road, railroad and water crossings, populated and industrial areas, pump station and tank farm limits, and tie-in welds. The daily ten percent is a floor for ordinary line pipe only. Weld maps that do not separate the hundred percent categories from the sampled population are the most common documentation failure on a spread."},{"q":"What does a B31.4 pressure test have to demonstrate?","a":"Strength and tightness together. The completed system is tested to at least 1.25 times the internal design pressure at every point for a minimum of four hours. Where the pipe is buried or otherwise not visually inspected for leakage during that hold, a further four hours at not less than 1.10 times design pressure is required. Gauge calibration, continuous pressure and temperature recording, and the elevation profile proving the pressure at the high point are all part of the record."},{"q":"Is ASME B31.4 the same thing as 49 CFR Part 195?","a":"No, and the distinction has commercial consequences. B31.4 is a consensus design and construction code. In the United States hazardous liquid pipelines are regulated under 49 CFR Part 195, which incorporates portions of B31.4 by reference and then adds obligations the code never states, including operator qualification, integrity management for high consequence areas, pressure limits tied to test pressure, and reporting. A contract specifying only B31.4 on a regulated line has under-scoped the work."},{"q":"Where does B31.4 stop and B31.3 begin at a terminal?","a":"At the facility boundary defined in the scope. Piping within pump stations, terminals and tank farms that forms part of the liquid transportation system stays with B31.4, while refinery, gas processing plant and bulk plant process piping is B31.3. On a project touching both, the drawing set must carry an explicit code break at a designated tie-in, because the two codes differ in allowable stress basis, weld examination extent, testing regime and record requirements."}],"sections":[{"heading":"What B31.4 covers, and the exclusions that catch projects","paragraphs":["ASME B31.4 applies to piping that transports liquids and slurries between the points where product is produced, stored, processed and delivered: lease facilities, tank farms, terminals, pump stations, marine, rail and truck loading racks, and the plants at either end of the line. Crude, condensate, natural gas liquids, LPG, liquid anhydrous ammonia, liquid alcohols, dense phase carbon dioxide and refined products all fall inside it. The code is a design and construction document with an operations and maintenance chapter attached. It is not a fitness-for-service standard and it certifies no one.","The exclusions are where projects go wrong. Refinery, gas processing and bulk plant process piping is ASME B31.3. Gas transmission and distribution is ASME B31.8. Ammonia refrigeration systems are B31.5. Well casing, tubing, wellhead assemblies and separators sit outside entirely. So do auxiliary services such as water, air, steam, lube oil and fuel gas, even when they run in the same trench as the mainline. Pumps, meters, exchangers and vessels are covered by their own codes, and B31.4 picks up at the connection. A terminal expansion typically touches at least two of these codes at once.","The temperature window is the exclusion most often missed. B31.4 provides allowable stresses for metal temperatures between roughly minus 20F and 250F. Heated heavy crude, asphalt and steam traced product lines that run above 250F sit outside the code's stress basis, and continuing to design them to B31.4 without supplementary analysis is a genuine finding rather than a technicality."]},{"heading":"The 0.72 design factor, and why there are no class locations","paragraphs":["Internal design pressure under B31.4 comes from the familiar thin-wall form with a design factor of 0.72 applied to specified minimum yield strength and a longitudinal joint factor taken from the pipe manufacturing process. The factor does not change with population density. This is the largest structural difference between B31.4 and B31.8, and it exists for a physical reason: a liquid line does not store the decompression energy a gas line does, so the code does not scale the factor to exposure.","Two errors recur. The first is importing B31.8 class locations into a liquid design and derating to 0.60 or 0.50, which looks conservative but signals that the designer has the wrong code open, and it will be challenged. The second is the joint factor. Modern seamless, electric resistance welded, electric flash welded and submerged arc welded pipe carries a factor of 1.00, but vintage furnace butt welded pipe does not, and reusing an old line or a length pulled from the pipe yard without confirming the manufacturing process silently inflates the allowable pressure.","Where a wall thickness calculation has to be defended in front of a client or a regulator, the mill certificate, the manufacturing process, the yield strength and the design factor all have to trace to the same document set. Our [ASNT Level III consulting](/consulting) work on pipeline projects normally starts here, because a pressure calculation whose inputs cannot be traced is not a calculation, it is an assertion."]},{"heading":"Restrained versus unrestrained: the distinction that decides buried pipeline stress","paragraphs":["B31.4 treats buried and otherwise restrained pipe differently from aboveground station piping. Restrained pipe cannot expand, so the thermal differential between installation and operating temperature appears as longitudinal stress rather than as movement. The code limits the net longitudinal stress and the equivalent combined stress in restrained pipe to 0.90 times specified minimum yield strength, and it is usually the thermal term rather than the pressure term that consumes the margin.","Unrestrained piping is checked on a different basis, with sustained longitudinal stresses limited relative to the basic allowable and the expansion stress range checked separately. The practical consequence is that the same physical line changes category where it comes out of the ground and again where it enters a station. Anchors, aboveground bends and the transition at a cased road crossing are where the two regimes meet, and where a model built entirely as unrestrained will quietly pass a design that yields in service.","Overbend and sidebend elastic bending stress, soil friction assumptions and depth of cover all feed this calculation. If the as-built profile differs from the design profile, and after a wet construction season it usually does, then the stress case that was analysed is no longer the stress case that exists in the ground."]},{"heading":"Welding and NDE: B31.4 hands the work to API 1104","paragraphs":["B31.4 does not write its own welding rules. It adopts API Standard 1104 for procedure qualification, welder qualification and weld acceptance on pipeline girth welds, with ASME Section IX picking up components that API 1104 does not address. That single delegation causes more misapplied acceptance criteria than any other provision in the code.","Acceptance limits for slag, porosity, incomplete penetration, incomplete fusion and undercut on a B31.4 girth weld come from API 1104 Section 9 workmanship criteria, or from the Appendix A alternative acceptance standards where the project has done the fracture mechanics and qualified the tolerable flaw sizes. They are not the ASME Section VIII limits, and radiographic interpreters who move between plant and pipeline work apply the wrong set routinely. An interpretation made against the wrong standard is wrong in both directions: it rejects welds that are acceptable and passes welds that are not.","Examination extent is prescriptive rather than risk-based. At least ten percent of each day's girth welds must be examined over the full circumference, with one hundred percent at road, railroad and water crossings, in populated and industrial areas, within pump station and tank farm limits, and at tie-ins. Crews also need RT and UT personnel qualified under an employer written practice, which is what our [NDT training](/training) programmes are built to support. Where interpretation quality is in doubt on a completed spread, [independent report validation](/report-validation) on a sampled set of radiographs costs far less than a re-shoot and immeasurably less than a leak."]},{"heading":"Pressure testing under Chapter VI","paragraphs":["The strength and tightness test is where pipeline documentation most often falls apart years later. B31.4 requires the completed system to be tested to at least 1.25 times the internal design pressure at every point for a minimum of four hours. Where the pipe is buried, or otherwise not visually inspected for leakage during that hold, a further four hours at not less than 1.10 times internal design pressure is required. Eight hours, not four.","Because the requirement is expressed at every point, the elevation profile governs. The low point sets the maximum pressure the pipe and fittings will see, and the high point decides whether the minimum has actually been reached. A test record reporting only the pressure at the test head, with no profile and no calculation of the pressure at the high elevation, does not prove compliance even when the test itself was properly run.","The remainder of the record is mechanical: dead weight and gauge calibration in date and in the correct range, a continuous pressure and temperature chart, water quality and chloride limits where stainless is in the circuit, and a documented account of every excursion. Where hydrotest, NDE and dimensional records are being assembled across a long spread, tracking them in an [inspection management system](/erp) rather than a spreadsheet is what makes the package reconstructable at handover and at the first integrity review."]},{"heading":"Corrosion control and the coating to cathodic protection interface","paragraphs":["Chapter VIII requires buried and submerged pipeline to be externally coated and cathodically protected, and requires the two to be designed as one system. Coating disbondment does not merely expose steel. It can shield the exposed steel from protective current, which is why disbonded tape and shrink sleeve at girth welds produce corrosion in stretches where the close interval survey reads perfectly clean.","The protection criteria B31.4 points to come from AMPP/NACE SP0169. A raw on-potential of minus 850 mV to a copper/copper sulphate reference does not satisfy the criterion on its own, because it still contains IR drop; the instant-off or otherwise corrected polarised potential is what the criterion is written against. Survey reports quoting on-potentials as evidence of compliance are among the most common integrity documentation defects, and they survive for years because nobody re-reads them until an in-line inspection contradicts them.","Internal corrosion is handled separately through product quality control, cleaning and inhibition where appropriate, and monitoring. On liquid lines the low points and water dropout locations govern, and those locations are geometric, which is why the same three low spots reappear in run after run of in-line inspection data."]},{"heading":"Where B31.4 sits underneath 49 CFR Part 195","paragraphs":["In the United States, B31.4 is not the top of the regulatory stack. Hazardous liquid pipelines are regulated under 49 CFR Part 195, which incorporates portions of B31.4 by reference and then imposes requirements the code does not contain: operator qualification for covered tasks, integrity management for pipelines that could affect high consequence areas, maximum operating pressure tied to the test pressure achieved, corrosion control intervals, and incident reporting obligations.","The commercial consequence is straightforward. A construction contract specifying compliance with ASME B31.4 and nothing else has under-scoped the work for a regulated line, and the gap surfaces during commissioning when the operator's compliance group asks for records that were never contracted, never budgeted and in some cases can no longer be created. Specifications for regulated pipelines should name the regulation and the code, in that order.","Outside the United States the referencing instrument changes, with CSA Z662 in Canada and national regulation elsewhere, but the pattern holds. B31.4 supplies the engineering. Something above it supplies the legal obligation, the record retention period and the reporting duty."]},{"heading":"Findings that recur on B31.4 projects","paragraphs":["The recurring findings are not exotic. Weld maps that never identified the hundred percent examination locations before construction started. A single four hour hydrotest hold on a buried line. Radiographic interpretation reports citing an ASME acceptance clause on an API 1104 job. Procedure revisions issued after the welds they govern were already made. Coating repairs at tie-ins with no holiday detection record. Each is trivial to prevent and expensive to close.","Two more deserve naming because they cost the most. The first is a design temperature above 250F carried all the way through detailed design without anyone noticing that the code no longer supplies allowable stresses. The second is a change in pipe supply mid-project, to a different mill with a different manufacturing process and a different joint factor, with the wall thickness calculation never revisited and the mill certificates filed without comparison.","None of these are caught by a documentation review at handover, because by then the evidence they depend on is buried, painted or backfilled. They are caught by someone holding the code open at the moment the work is done. That is the argument for technical authority on the spread rather than at close-out, and if you want to discuss how that is staffed on a specific project, [talk to us](/contact)."]},{"heading":"Where B31.4 pipelines meet plant piping at the fence line","paragraphs":["The transition from a B31.4 pipeline to B31.3 plant piping at a pump station or terminal fence line is a recurring point of confusion, because the pipe itself does not change at the boundary — only the code governing it does, and the boundary is a matter of engineering definition rather than a visible feature in the field. B31.4 governs the pipeline up to the first block valve or manifold inside the facility; B31.3 governs from there into the process unit. A weld sitting exactly at that boundary can be inspected, documented and accepted under the wrong code if the boundary was never fixed in writing before construction.","The consequence is not cosmetic. B31.4 and B31.3 differ in design factor, in required NDE extent, and in acceptance criteria for the same nominal defect, so a girth weld inspected to the wrong code's acceptance table can be accepted under one standard while it would have been rejected under the other. Once the facility is operating, tracing which code actually governs a specific weld near the fence line — for a repair, a fitness-for-service assessment, or an incident investigation — depends entirely on whether the boundary was documented at the time.","The control is simple and is skipped often enough to be worth stating: the piping class boundary between pipeline and plant jurisdiction belongs on the isometric drawings and in the inspection and test plan before the first weld at that boundary is made, not reconstructed afterward from memory or from whichever code the inspector on shift that day happened to default to."]}],"faq":[{"q":"Does ASME B31.4 cover slurry pipelines?","a":"Yes. The code is titled Pipeline Transportation Systems for Liquids and Slurries and carries provisions for slurry service, including wear allowance and the velocity considerations needed to keep solids in suspension without accelerating erosion. Slurry lines take the same 0.72 design factor and the same welding and testing regime; what changes is the erosion allowance added to the calculated wall thickness and the attention paid to bends, tees and reducers where directional change concentrates wear."},{"q":"Can B31.4 be used to assess corrosion metal loss on an in-service line?","a":"No. B31.4 is a design and construction code with operations and maintenance provisions; it contains no remaining strength assessment method. Metal loss is assessed to ASME B31G and its modified and effective area forms, or to API 579-1/ASME FFS-1 for the general case, and crack-like flaws are assessed under the fracture mechanics parts of API 579. B31.4 tells you the pressure the pipe was designed for. A fitness-for-service assessment tells you what it can still safely hold."},{"q":"What weld joint factor applies to reused or vintage pipe?","a":"It depends on the manufacturing process rather than the age. Seamless, electric resistance welded, electric flash welded and submerged arc welded pipe carry a joint factor of 1.00 in the code's table. Furnace butt welded pipe carries a substantially lower factor. Reused pipe with no traceable mill certificate has no defensible joint factor at all, and the only honest routes forward are documented material verification, including chemistry and mechanical testing, or designing on the lowest factor in the table."},{"q":"Does B31.4 require certified NDT personnel?","a":"Indirectly, and firmly. Because the code adopts API 1104 for welding and weld examination, personnel performing radiographic and ultrasonic examination of girth welds must be qualified under an employer written practice, normally built on ASNT SNT-TC-1A, with documented training, experience, examination and vision records. The written practice belongs to the pipeline contractor or the NDT subcontractor, not to the code, and it is the first document an auditor will ask to see."},{"q":"How does B31.4 treat offshore liquid pipeline?","a":"Offshore liquid pipeline systems are handled in a dedicated chapter that modifies the onshore rules for the marine environment. Design factors differ for risers and platform piping, additional stress checks apply for the installation condition during laying, and there are specific provisions for on-bottom stability and hydrostatic collapse under external pressure. Applying the onshore 0.72 factor to a riser without opening that chapter is a design error, not a simplification."}]}