Pressure Vessel Inspection (API 510): Interval Calculation Explained

API 510's RL/2 formula sets the inspection interval, but corrosion rate selection and RBI scoring change the real answer for a working vessel.

By Anoop Rayavarapu, ASNT NDT Level III ·

The Formula Everyone Knows, the Judgment Calls Nobody Teaches

Ask any API 510 candidate to write the remaining-life formula on a whiteboard and they'll get it right within seconds: RL = (tactual − tmin) / CR. Ask the same person to defend which corrosion rate to use, which CML data to trust, and why the calculated interval isn't automatically the scheduled interval, and the confidence usually drops. That gap — between knowing the formula and knowing how to apply it to a real vessel with messy inspection history — is where API 510, the Pressure Vessel Inspection Code, actually lives. The code covers in-service inspection, rating, repair, and alteration of pressure vessels and the pressure-relieving devices protecting them, and its interval calculation is the backbone of every mechanical integrity program built around fixed equipment.

This post walks through the interval calculation the way it actually gets applied in the field: the governing formula, the half-life rule and its ceiling, how corrosion rate selection changes the answer, how external and internal intervals diverge, and where risk-based inspection reshapes the whole conversation.

Remaining Life: The Core Calculation

API 510 Section 7 ties the maximum inspection interval to the calculated remaining life of the vessel's controlling component — usually the shell course, head, or nozzle with the least corrosion allowance remaining, not necessarily the thickest or thinnest point in absolute terms. The formula:

RL = (tactual − tmin) / CR

tactual comes from the most recent UT thickness reading at an established CML. tmin is the minimum required thickness calculated per the original construction code (most commonly ASME Section VIII, Division 1) using the vessel's design pressure, temperature, material allowable stress, and joint efficiency — not a generic wall thickness assumption. CR is the corrosion rate, expressed in mils per year (mpy) or inches per year, derived from comparing thickness readings across time.

Take a real example: a carbon steel separator vessel, ASME Section VIII Division 1 construction, design pressure 285 psig at 400°F, calculated tmin of 0.312 in on the shell. Original nominal thickness was 0.500 in. The most recent UT survey reads 0.365 in at the governing CML, and the previous survey five years earlier read 0.398 in. Corrosion rate = (0.398 − 0.365) / 5 = 0.0066 in/yr = 6.6 mpy. Remaining life = (0.365 − 0.312) / 0.0066 = 8.0 years.

The Half-Life Rule and the 10-Year Ceiling

API 510 sets the maximum internal or on-stream inspection interval at the lesser of half the remaining life or 10 years, mirroring the logic used in API 570 for piping. Applied to the separator example above, RL/2 = 4.0 years, which becomes the governing interval since it's well under the 10-year cap. Note that the 10-year ceiling applies specifically to internal and on-stream inspection; external visual inspection intervals follow a separate rule (the lesser of 5 years or the required internal/on-stream interval, discussed below), and the two schedules frequently run on different clocks for the same vessel.

A subtlety that trips up less experienced inspectors: RL/2 is a ceiling, not a target. Nothing in API 510 requires you to push the interval out to the full calculated value. A vessel with intermittent, upset-prone service — batch reactors, vessels downstream of a unit with a history of process excursions — often warrants a shorter interval than the math strictly requires, and API 510 explicitly allows the inspector of record and the owner-user's inspection program to apply engineering judgment to shorten (never lengthen beyond the calculated maximum) the interval based on service severity, inspection history, and confidence in the data.

External Inspection: A Different Clock Entirely

External visual inspection under API 510 runs on the lesser of 5 years or the required internal/on-stream interval, and its purpose is different from the internal/on-stream program: it's looking for external corrosion, coating and insulation condition, CUI indicators at penetrations and supports, foundation settlement, and nozzle/attachment weld condition — the things that indicate a vessel problem long before an internal inspection would otherwise be scheduled. For the separator example above, the internal/on-stream interval is 4.0 years, so the external interval can be no longer than 4 years; many owners schedule externals more often than the code maximum, especially for insulated vessels with CUI risk. Running two intervals in parallel, on different clocks, for the same vessel is normal and expected — and it's exactly the kind of detail that gets lost when a facility tracks inspection due dates in a spreadsheet maintained by whoever had time that quarter rather than a system built for it.

Which Corrosion Rate Governs: LTCR vs. STCR

API 510 recognizes two corrosion rate calculations and requires the inspector to select the one that best represents current and anticipated future conditions:

  • Long-Term Corrosion Rate (LTCR): calculated from the original as-built thickness (or earliest reliable baseline) to the most recent reading, averaged over the full service life. This smooths out short-term noise and single-reading anomalies but can understate an accelerating degradation mechanism.
  • Short-Term Corrosion Rate (STCR): calculated from the two most recent inspection readings only. This captures recent trend changes — a process shift, a new corrosive contaminant, upstream equipment changes — but is more sensitive to measurement uncertainty from a single reading pair.

The governing principle is conservatism: when STCR and LTCR diverge meaningfully, and STCR indicates faster corrosion, API 510 practice is to use STCR unless the inspector has specific technical justification (a known, corrected upset condition, for instance) to discount it. In the separator example, if the two most recent readings actually showed 0.398 in to 0.365 in over 5 years (6.6 mpy) but the original-to-current LTCR calculated out to only 4.1 mpy, a competent inspector uses 6.6 mpy — the more conservative, recent-trend number — because using the lower LTCR would understate risk and overstate the safe interval.

When CML Data Is Thin or Unreliable

Not every vessel has a clean two-point thickness history. Vessels that changed hands, vessels where CML locations weren't consistently re-measured at the same spot, or vessels coming off a long shutdown with no interim monitoring all present a data problem before they present a calculation problem. API 510 doesn't have a shortcut for missing data — the conservative default is to treat unverifiable remaining life as effectively unknown, which forces either a fresh full UT thickness survey to re-establish a defensible baseline, or a corrosion rate assumption pulled from API RP 571 damage mechanism guidance for the specific service (sour water, amine, caustic, etc.) until real data exists. This is a common finding when Atlantis NDT's ASNT Level III consulting team audits an inherited mechanical integrity program: the calculations on file are mathematically correct, but they're built on CML data that was never verified as measuring the same location twice.

Risk-Based Inspection: Reshaping the Interval, Not Replacing the Code

Many facilities layer API 580/581 Risk-Based Inspection (RBI) methodology on top of the base API 510 calculation. API 510 does allow an RBI assessment per API RP 580 to set intervals in place of the half-remaining-life-or-10-year limits, including intervals longer than 10 years, provided the RBI assessment is reviewed and approved by the engineer and inspector at intervals not exceeding 10 years. Just as importantly, RBI lets facilities justify shorter intervals for high-consequence vessels (large inventory, toxic or flammable service, high population exposure) even when the corrosion-rate math alone would allow a longer wait, and it lets low-risk vessels (utility air receivers, low-pressure low-consequence vessels) get inspection resources prioritized elsewhere within the code-allowed maximum. RBI is a risk-prioritization layer, and API 510 remains the floor beneath it.

Vessels in cyclic or fatigue-prone service — think amine contactors, hydrocracker reactors with hydrogen embrittlement exposure, or vessels subject to frequent startup/shutdown thermal cycling — often carry RBI scores that push their interval well below what RL/2 alone would calculate, because the governing damage mechanism (fatigue cracking, hydrogen-induced cracking, stress corrosion cracking) doesn't behave like uniform wall-thinning corrosion and isn't fully captured by a UT thickness trend at all. For these vessels, the interval calculation is only the starting point; the real inspection scope typically adds wet fluorescent magnetic particle testing (WFMT) at nozzle welds, phased array UT for crack detection, or hardness surveys per NACE MR0175/ISO 15156 for sour service vessels.

Rerating and Alteration: When the tmin Itself Changes

The remaining-life calculation assumes a fixed tmin, but tmin isn't permanently fixed — it changes if the vessel is rerated (typically de-rated to a lower MAWP to extend service life on a thinning vessel) per API 510 Section 9, or if it undergoes a repair or alteration per API 510 Section 8 that changes the pressure boundary. A vessel approaching the end of its economically viable remaining life at its nameplate MAWP is sometimes rerated downward — recalculating tmin at a lower design pressure using the actual current thickness — which mathematically extends remaining life and resets the interval clock, without any metal being added. This is a legitimate, code-sanctioned path, but it requires a full engineering rerate calculation, not just a inspector's field judgment, and it needs to be documented and, where required, reviewed by the jurisdictional authority having jurisdiction (many US states require notification or approval for rerates on registered vessels).

A Worked Example: Amine Contactor Interval Recalculation

To see how these rules interact on a real vessel rather than a textbook shell course, consider a lean amine contactor at a gas processing facility — a common and instructive case because amine service combines uniform corrosion with localized attack at specific geometry, and because it's exactly the kind of vessel where a mechanical interval calculation alone is insufficient. The vessel is ASME Section VIII Division 1, carbon steel, design pressure 1,200 psig at 150°F, calculated tmin on the shell of 0.687 in against a nominal 1.000 in wall. Thickness surveys at the governing CML — located at the rich amine outlet nozzle, a known high-turbulence, high-corrosion location in amine service — show 0.795 in five years ago and 0.762 in at the most recent turnaround.

STCR = (0.795 − 0.762)/5 = 6.6 mpy. The vessel's original construction-to-current LTCR calculates to 4.3 mpy, noticeably lower. Per API RP 571's guidance on amine corrosion, localized attack at high-velocity points like nozzles and elbows is a recognized damage mechanism that tends to accelerate rather than plateau, so the inspector uses the more conservative STCR. RL = (0.762 − 0.687)/0.0066 = 11.4 years. RL/2 = 5.7 years, comfortably under the 10-year cap, so the mechanical interval calculation alone would allow nearly six years before the next internal or on-stream inspection.

But amine service also carries recognized susceptibility to amine stress corrosion cracking (SCC) at and adjacent to non-stress-relieved welds, a mechanism that thickness readings do not detect at all — cracking doesn't show up as wall loss on a UT thickness grid. An RBI assessment for this vessel, weighting both the consequence of a rich amine release (flammable, toxic H2S content, personnel exposure in a processing area) and the likelihood factor tied to weld stress-relief history, frequently drives the practical inspection scope well past what RL/2 alone would suggest: wet fluorescent magnetic particle testing at heat-affected zones, and in some programs, a shortened interval independent of the corrosion-rate-driven maximum. This is the scenario every API 510 inspector needs to internalize — the interval calculation answers "how much wall thickness margin do we have," but it never answers "is wall thickness the only thing that can fail this vessel." Treating RL/2 as sufficient justification to skip a targeted cracking inspection on a vessel with documented SCC susceptibility is a common and expensive mistake, and it's precisely the gap a competent RBI program, correctly integrated with the base API 510 schedule, is designed to close.

Documentation and the Audit Trail

Every interval decision needs to be reconstructable years later, by someone other than the inspector who made the original call. That means the file should show: the governing CML location and why it's the controlling point, the tmin calculation with its code edition/addenda basis, both LTCR and STCR figures with a stated reason for which one governed, the resulting RL and RL/2 (and the resulting external interval), any RBI adjustment applied and its basis, and the inspector of record's API 510 certification number and signature. Facilities running dozens or hundreds of vessels across multiple units lose track of this not because anyone is careless, but because the data lives in disconnected places — UT reports in one folder, corrosion rate spreadsheets in another, RBI scores in a third system that doesn't talk to either. Atlantis NDT's NDT inspection management ERP was built to close exactly that gap: CML history, calculated remaining life, interval due dates, and RBI flags in one system, so a turnaround planner can pull "everything due in the next outage window" instead of reconstructing it vessel by vessel from PDFs.

Building the Capability In-House

The interval calculation itself is arithmetic. The judgment behind corrosion rate selection, CML placement, RBI weighting, and when to override the calculated maximum with a shorter, more conservative interval is what separates a program that catches problems early from one that discovers them during a shutdown inspection nobody expected to find anything. That judgment is built through structured API-code training, supervised inspection experience, and — for facilities without a Level III on staff — access to one who can review the program periodically. Atlantis NDT's NDT training and certification programs and ASNT Level III consulting services support both paths: training internal Level II inspectors to apply the code correctly and consistently, or serving as the outside Level III of record reviewing interval calculations, procedure adequacy, and CML program design for facilities that need that oversight without carrying it as a full-time headcount.

For an asset-heavy facility, tying the API 510 interval calculation into a live digital twin of the unit — where every vessel's next-due date, corrosion trend, and RBI score is visible on the 3D model rather than buried in a spreadsheet — turns interval management from a periodic audit exercise into something the whole reliability team can see and act on continuously. Whether the entry point is a training gap, a program audit, or a technology upgrade, the underlying goal is the same: make sure the interval a vessel is actually inspected on matches the interval the code — and the data — says it should be.

Atlantis NDT Products & Services

Atlantis NDT pairs field expertise with software: NDT inspection management software — Atlantis ERP, a digital twin platform for asset integrity, and NDT reporting software. Build your team with NDT training & certification (ASNT SNT-TC-1A) and ASNT certification pathways, or bring in ASNT Level III consulting. Affordable, accessible, fully customizable — book a free consultation.

Running this as a programme, not a one-off

If you are responsible for an inspection programme rather than a single job, the recurring problem is rarely the code — it is keeping measured thickness, damage-mechanism assignment and next-inspection dates in one defensible place. Asset integrity management software covers keeping measured thickness readings per CML in one place, so the RBI (API 580/581) and fitness-for-service (API 579) work your integrity team or its specialists carry out starts from measured data rather than default rates. Atlantis supplies the NDT data and the software to hold it; it does not perform RBI or FFS assessments.

Atlantis NDT Products & Services

Atlantis NDT pairs field expertise with software: NDT inspection management software — Atlantis ERP (certification tracking, work orders, method-specific reporting on every business app you need), a digital twin platform for asset integrity (3D corrosion mapping and inspection-data overlay), and NDT reporting software. Build your team with NDT training & certification (ASNT SNT-TC-1A) and ASNT certification pathways, or bring in ASNT Level III consulting for written practices, procedures and audits — plus independent inspection data review on API 510/570/653-governed assets. Capture as-built reality with 3D laser scanning services. Affordable, accessible, fully customizable — book a free consultation.

Internal versus on-stream inspection: what the current edition actually says

Short answer: in API 510, eleventh edition (October 2022, with errata in 2023 and 2025), the interval between internal or on-stream inspections may not exceed the lesser of half the vessel's remaining life or 10 years, unless an RBI assessment justifies something else. Where remaining life is under four years, the interval may be the full remaining life, up to two years. An on-stream inspection can replace the internal inspection only in defined cases, and only at the inspector's discretion.

The calculation earlier in this article gives you the maximum interval. This section covers the next question: when that inspection comes due, does someone have to go inside the vessel, or can the inspection be done from outside while it runs? It is a paraphrase of API 510's current edition with attribution. The code is copyrighted, so check the details against your licensed copy, and check API's API 510 announcement page for the current edition and errata.

Two points earlier in this article need tightening against the eleventh edition. First, the default external visual inspection interval is the lesser of five years or the required internal/on-stream interval. It is not a fraction of remaining life. Second, the code does let an RBI assessment carried out under API RP 580 exceed both the 10-year and the half-life limits for internal and on-stream inspection, and the 5-year external limit. There are conditions. An RBI interval for internal or on-stream inspection that goes past 10 years must have its RBI assessment reviewed and approved by the engineer and inspector at least every 10 years, or sooner if the process, equipment or consequences change. RBI-based external intervals may not exceed 10 years. RBI is an owner-commissioned engineering programme. If your plan uses it, those are the rules it must follow. Our guide to time-based versus risk-based intervals explains the difference.

Definitions: three inspections that are often confused

API 510 separates inspection types that plant schedules often lump together:

  • Internal inspection is done from inside the vessel using visual and/or NDE techniques. An inspector performs it under the inspection plan. Other people acceptable to the owner, such as an NDE examiner, can assist but cannot replace the inspector. If a vessel is too small to enter safely, or if remote visual tools (borescopes, drones, robotic crawlers) can see the areas at risk, inspection through a manway or port can stand in for entry. That needs the inspector's and owner-operator's approval, the inspector present to review and accept the data, and a record of how much of the surface was actually seen.
  • On-stream inspection is done from outside while the vessel is on-stream, meaning not prepared for internal inspection. It uses NDE to establish whether the pressure boundary is fit to keep operating. It can be done by an inspector or an examiner under the inspection plan. Any on-stream work by an examiner must be authorized and approved by the inspector. Where on-stream inspection is acceptable in place of internal inspection, the code says it can be done with the vessel depressurized or pressurized.
  • External inspection is a visual inspection from outside, looking for conditions that threaten pressure integrity or the supporting structures. It can be done at the same time as an on-stream inspection, but it is a separate requirement with its own interval.

The code states the purpose of internal inspection plainly: to find damage that regular monitoring of external condition-monitoring locations (CMLs) during on-stream inspections cannot find. Every on-stream substitution has to show that this purpose is still met for that vessel and service.

The interval rules that govern both

In summary, API 510's eleventh edition sets these rules for internal, on-stream and thickness-measurement inspections:

  • Ceiling. Unless RBI justifies otherwise, the period between internal or on-stream inspections may not exceed half the remaining life or 10 years, whichever is less. Thickness measurement inspections follow the same ceiling.
  • Short remaining life. When remaining life is under four years, the interval may be the full remaining life, but no more than two years. This rule is easy to get wrong. A vessel with three years left does not get 1.5 years by the half-life rule. It can go up to two years, and only because the code says so for this case.
  • External monitoring. When the extent of thinning can be detected or effectively monitored from outside, an internal inspection is not required at half the remaining life. This is the link between the interval rule and the on-stream substitution.
  • Who sets it. The inspector or engineer sets the interval under the owner-operator's QA system.
  • Non-continuous service. For vessels that are not in continuous service, the interval counts years of actual operation, not calendar years. This applies only if the idle vessel is isolated from process fluids and not exposed to corrosive internal conditions, for example inert-gas purged or filled with noncorrosive hydrocarbon. If it is not protected, corrosion while idle has to be reviewed before setting the interval. External intervals do not get this allowance, because the outside environment does not change when the vessel is idle.
  • Projected MAWP alternative. The interval can also be set by projecting each component's MAWP forward over a trial interval and checking that the limiting component stays at or above the nameplate or rerated MAWP plus static head. Without RBI, this method is also capped at 10 years.
  • No credible internal damage. A vessel can be exempted from internal inspection and corrosion monitoring if a qualified corrosion specialist documents that no credible internal degradation mechanisms exist. Vessels that by design cannot be inspected internally or on-stream for credible mechanisms (the code gives an aluminum core exchanger as an example) need analysis, monitoring and maintenance strategies instead. External inspection is still required in both cases.

The code also asks for action when corrosion rates accelerate or become unstable. It calls for an investigation in line with API RP 585 and for the operations group to alert inspection and corrosion specialists. It notes that relying on ever-shorter intervals can be a higher-risk strategy than replacing the vessel, upgrading the material or installing permanently mounted monitoring sensors. For how the rate itself is chosen, see long-term versus short-term corrosion rates.

When on-stream inspection can replace internal inspection

This is the heart of the on-stream question. Under the eleventh edition, the substitution is at the inspector's discretion and is available in two situations.

Situation A, entry is physically impossible. The vessel's size or configuration makes entering it for internal inspection physically impossible.

Situation B, entry is possible but every condition is met. All of the following must be true:

Condition (paraphrased from API 510, 11th ed.)What evidence usually supports itTypical reason it fails
General corrosion rate known to be below 0.005 in. (0.125 mm) per yearTrended CML thickness data over several inspections; corrosion mapping baselinesToo few data points to say the rate is "known"; localized loss not shown by spot UT
Remaining life greater than 10 yearsRemaining-life calculation at the governing componentThin governing nozzle or head, not the shell
Corrosive character of the contents, including trace components, established by at least five years in the same or similar serviceService history, process and corrosion records, integrity operating window dataRecent feed or process change; new contaminant; vessel recently moved to new service
No questionable condition found at the external inspectionCurrent external inspection reportCUI indications, bulging, leaks, support or nozzle distress
Steel shell operating below the lower temperature limit of the material's creep-rupture range (as referenced in API 579-1/ASME FFS-1)Operating temperature records against material dataHigh-temperature reactors and heater-adjacent vessels
Not subject to environmental cracking or hydrogen damage from the process fluidDamage-mechanism review (API RP 571) and corrosion control documentationWet H2S, amine, caustic, HTHA-susceptible services
No non-integrally bonded liner, such as strip or plate liningConstruction records and drawingsStrip-lined or plate-lined vessels

If any Situation B condition is not met, the code says the next inspection must be an internal inspection. The alternative route is RBI. An on-stream inspection can be used if an RBI assessment finds the vessel's risk acceptable to the owner-operator and finds the external NDE techniques effective enough for the expected damage mechanism. The assessment should consider past and likely future process conditions.

The cracking condition is the one most often argued about. Under Situation B, a vessel in a service prone to environmental cracking or hydrogen damage cannot use on-stream substitution. Our deep dive on API 510 intervals in sour and wet H2S service covers that case in detail.

What the on-stream inspection itself must contain

Substitution only works if the on-stream inspection is good enough to stand in for going inside. API 510 sets three expectations:

  1. The NDE type and extent are specified in the inspection plan. This could be ultrasonic thickness measurement, radiography or other NDE suited to measuring metal thickness and assessing the pressure boundary, including the shell and the welds. When on-stream inspection of the pressure boundary is specified, the NDE techniques must be chosen to detect the damage mechanisms and flaw types identified in the plan.
  2. The inspector has enough access to all parts of the vessel, heads, shell and nozzles, to make an accurate assessment. Scaffolding, insulation removal and permits are part of the scope, not optional extras.
  3. Technique limits are understood. The code lists factors that limit external NDE when looking for internal damage. They include the alloy, plate versus pipe versus casting, weldments, nozzles, saddles and reinforcing pads, internal attachments, linings or cladding, access and metal temperature, the technique's inherent limits for the mechanism, and surface condition such as heavy pitting or poor preparation.
On-stream NDE techniqueWhat it showsMain limitation
Spot UT thickness at CMLsWall thickness trend at fixed points for corrosion-rate calculationMisses localized loss between points; needs temperature correction above about 150°F
Automated or phased array UT corrosion mapping (C-scan)Area thickness maps; localized and pitting loss; repeatable baselinesNeeds surface access and preparation; coverage limited by nozzles and attachments
Profile radiographyWall loss through insulation on smaller diameters and nozzlesRadiation controls; sizing accuracy lower than UT; limited on large shells
PAUT and TOFD weld examinationEmbedded and ID-connected flaws in welds from outsideNot a substitute where the code bars on-stream for cracking service; procedure must be demonstrated
Guided-wave or other screeningScreening of nozzles or attached piping for areas needing follow-upScreening only; findings need quantitative follow-up

The code also points out that where surfaces are pitted or there is doubt about remaining thickness, ultrasonic scanning or profile radiography is preferred over spot readings. That is directly relevant to the "known corrosion rate" condition. A low rate based on a handful of spot readings is weaker evidence than one based on repeat corrosion mapping of the same areas.

Same-service vessels, multizone vessels and E&P vessels

Same or similar service. The results of an internal inspection of one vessel can support on-stream substitution for a similar vessel in the same or similar service and conditions. For vessels in series, inspecting one, preferably the worst case, can represent the whole train. Three conditions apply: no corrosive contaminants enter at an intermediate point, operating conditions are the same throughout, and enough corrosion history exists. The code adds an important exception. If the vessel is subject to environmental cracking or hydrogen damage, another vessel's internal inspection cannot be used to justify on-stream substitution.

Multizone vessels. A large vessel with two or more zones corroding at different rates, such as a fractionator with a corrosive overhead and a benign bottom, can have each zone treated separately for interval setting and for substitution. Each zone is then inspected on its own interval.

Exploration and production. Vessels in E&P service can follow the alternative rules in API 510 Section 9 instead of Section 6. Under those rules, on-stream and internal inspections may be used interchangeably, but an internal inspection is required when on-stream inspection cannot establish integrity. Remaining life is determined at every inspection.

A worked example, described qualitatively

Take a carbon steel reflux drum in a light-hydrocarbon service with stable operation. It has eight years of thickness history from fixed CMLs on the shell, heads and nozzles. The long-term and short-term rates agree and are well below the 0.005 in./yr threshold. The governing component, a head, has more than 10 years of remaining life. The damage-mechanism review finds no wet H2S, amine or caustic exposure. The drum runs far below the creep range and has no strip lining. The latest external inspection found no questionable condition.

Every Situation B condition is met, so the inspector may decide the next due inspection will be on-stream. The inspection plan then sets the scope: CML re-measurement, encoded corrosion mapping on the lower shell and around the inlet nozzle where turbulence is most likely, and profile radiography of small-bore nozzles through insulation. Insulation windows are cut, and scaffold gives access to both heads. Once the survey is done, the inspector evaluates the data, recalculates the rates and remaining life, and sets the next interval. If the mapping shows localized loss that changes the rate picture, the next inspection reverts to internal.

Now change one fact. Suppose the drum handled wet sour water. Situation B fails on the cracking condition. On-stream is then only available through an RBI assessment that finds the risk acceptable and the external techniques effective for the cracking mechanism. That is a decision for the owner's engineer and inspector, not for the examination contractor.

Documentation the inspector will expect

  • A written basis for each Situation B condition, or the RBI assessment and its technique-effectiveness finding.
  • An inspection plan that names the NDE techniques, coverage and locations, tied to the damage mechanisms.
  • Calibration, procedure and examiner qualification records for each technique, including temperature correction where readings were taken hot.
  • A coverage statement showing what was and was not examined, and why.
  • Updated corrosion rates, remaining life and the next internal, on-stream and external due dates, each with its own basis.

Jurisdictions add their own layer. Some US states and cities regulate process vessels under boiler and pressure vessel laws that accept API 510 owner-user programmes. Others apply the National Board Inspection Code. Under OSHA PSM, the mechanical integrity element expects inspections to follow recognized and generally accepted good engineering practice, and API 510 is the usual reference for process vessels. In Canada, Alberta's ABSA sets owner-user inspection requirements in AB-506, and other provinces regulate through their own authorities. Confirm the on-stream and interval rules with your jurisdiction.

Where Atlantis fits

Atlantis NDT performs the on-stream NDE that an API 510 inspection plan specifies. That covers CML thickness surveys, encoded phased array and AUT corrosion mapping, profile radiography by crews licensed where the work is, and PAUT/TOFD weld examination, carried out by ASNT-certified technicians under ASNT Level III oversight. Data goes to your API-certified Authorized Inspector, who stays inspector of record and decides whether on-stream inspection can replace an internal one. Atlantis does not set intervals or perform RBI. See pressure vessel inspection services. Ask us to scope an on-stream inspection. Quotes within 24 hours.

More questions on internal and on-stream inspection

When can on-stream inspection be used in lieu of internal inspection under API 510?

At the inspector's discretion, when entry is physically impossible, or when all seven conditions are met: corrosion rate below 0.005 in./yr, remaining life over 10 years, five years of established service, a clean external inspection, operation below the creep range, no environmental cracking or hydrogen damage, and no non-integrally bonded liner. An RBI assessment is the alternative route.

Is the API 510 internal inspection interval half the remaining life or 10 years?

Whichever is less, unless RBI justifies otherwise. With under four years of remaining life, the interval may be the full remaining life, up to two years.

What is the API 510 external inspection interval?

The lesser of five years or the required internal/on-stream interval, unless RBI justifies otherwise. RBI-based external intervals may not exceed 10 years.

Can RBI extend an internal inspection beyond 10 years?

Yes, under the eleventh edition, provided the engineer and inspector review and approve the RBI assessment at least every 10 years.

Who can perform an on-stream inspection?

An inspector or an examiner, following the inspection plan. Examiner work must be authorized and approved by the inspector, who evaluates the results.

Does idle time count toward the interval?

Not for internal and on-stream intervals, if the idle vessel was isolated and protected from corrosive conditions. External intervals still run on calendar time.

Have a vessel coming due? Request corrosion mapping to support an on-stream decision.

Next step

Atlantis performs the NDE this work needs and reports to your inspector of record. To go further, request an inspection quote. We reply within 24 hours.