External and On-stream Inspection Intervals for Vessels in Sour and Wet H2S Service
API 510, 11th edition, sets one interval scheme for every service: external visual at the lesser of five years or the internal/on-stream interval, and internal or on-stream at the lesser of half the remaining life or ten years. Sour service adds no separate interval. It removes your right to substitute on-stream inspection for internal inspection, because 6.5.2.1 b) 6) excludes vessels subject to environmental cracking or hydrogen damage.
The interval arithmetic is service-blind. Corrosion rate comes from thickness readings at the same condition monitoring locations, remaining life is actual thickness minus required thickness divided by that rate, and the ceiling is half of it or ten years. Wet H2S damage does not thin the wall, so that arithmetic returns a comfortable number while hydrogen-induced cracking propagates between the readings. API 510 handles this in two places. Clause 5.4.1 lists wet H2S damage three separate times, as surface-connected sulfide stress cracking, as subsurface HIC and SOHIC, and as blistering, and requires the inspection plan to carry an examination method able to find each. Clause 6.5.2.1 b) 6) then blocks the shortcut most operators want, refusing on-stream inspection in lieu of internal inspection for any vessel subject to environmental cracking or hydrogen damage. The date moves only through a risk-based assessment that proves the external technique can actually detect the mechanism.
Source: Verified against API 510, Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair, and Alteration, 11th edition, October 2022, with Errata 1 (March 2023) and Errata 2 (2025) — clauses 4.1.6, 5.1, 5.4.1, 5.5, 6.3, 6.4, 6.5, 6.7, 7.1, 7.2 and Section 9; API RP 571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, 3rd edition, March 2020, paragraph 3.67 Wet H2S Damage (Blistering/HIC/SOHIC/SSC), 3.58 Sour Water Corrosion and 3.35 High-temperature H2/H2S Corrosion; NACE/AMPP SP0296-2020 and NACE SP0472. Editions confirmed against API's ICP Publications Effectivity Sheet for the September 2026, January 2027 and May 2027 API 510 exam administrations.
| Damage mechanism | Thickness data detects it? | What sets the date under API 510 | Examination that finds it |
|---|---|---|---|
| Sour water corrosion, acidic (API RP 571, 3.58) | Yes | Half remaining life or 10 years, whichever is less (6.5.1.1 and 6.5.1.2) | UT thickness at CMLs, taken on-stream |
| High-temperature H2/H2S corrosion (3.35) | Yes | Half remaining life or 10 years, whichever is less | UT thickness, profile radiography on small bore |
| Hydrogen blistering (3.67) | No | Inspection plan under 5.1; on-stream in lieu of internal barred by 6.5.2.1 b) 6) | Internal and external visual for bulges, UT to find laminations |
| Hydrogen-induced cracking, HIC (3.67) | No | Inspection plan under 5.1; internal inspection unless RBI proves external NDE effectiveness | Shear-wave UT, TOFD, C-scan mapping |
| Stress-oriented HIC, SOHIC (3.67) | No | Inspection plan under 5.1; weld and heat-affected zone focused | SWUT, TOFD and ACFM at weld toes |
| Sulfide stress cracking, SSC (3.67) | No | Inspection plan under 5.1; hardness survey sets priority | WFMT after surface preparation, ACFM |
The interval rule in API 510, stated once, for every service
Every interval in API 510 lives in Section 6. Clause 6.4.1 requires each aboveground vessel to receive a visual external inspection at an interval not exceeding the lesser of five years or the required internal/on-stream inspection interval, and states a preference for performing it while the vessel is in operation. Clause 6.5.1.1 caps internal or on-stream inspection at one-half the remaining life or ten years, whichever is less, and where remaining life falls below four years the interval may be the full remaining life up to a maximum of two years.
Clause 6.5.1.2 applies the same ceiling to thickness measurement inspections. These numbers are maxima. The inspector or engineer sets the actual interval inside the owner-operator's quality assurance system, which means the code ceiling and your due date are two different things. Clause 6.5.1.1 also carries a carve-out worth reading closely: when the extent of thinning can be detected or effectively monitored externally, an internal inspection is not required at one-half remaining life. That sentence is about thinning, and it grants nothing for cracking.
Remaining life itself is built in Section 7. Clause 7.1.1.1 derives corrosion rate from the difference between two thickness readings at the same condition monitoring location divided by the elapsed time, distinguishing short-term from long-term rates, and 7.2 divides the margin above required thickness by that rate. Every input is a wall-loss measurement. A documented API 510 program audit usually finds the interval file is arithmetically perfect and mechanistically empty.
The word sour never appears in the code
API 510, 11th edition, uses the term H2S in exactly four places, and all four sit inside the damage mechanism list in 5.4.1. Sulfidation and high-temperature H2S/H2 corrosion appear under general and localized metal loss. Wet H2S damage appears under surface-connected cracking as sulfide stress cracking, under subsurface cracking as HIC and SOHIC, and under blistering as hydrogen blistering. Each entry points the reader to API RP 571.
What is absent matters more. There is no interval table keyed to service, no sour classification, no reduced ceiling for hydrogen-charging environments and no requirement to shorten an interval because the stream contains H2S. An engineer searching the code for a sour-service rule finds a taxonomy, not a schedule.
That structure is deliberate. API 510 puts the mechanism into the plan and the ceiling into Section 6, then makes the plan carry the technical argument. Clause 5.4.3 sends the reader to API RP 571 for critical factors, appearance and typical monitoring techniques, and to API RP 572 for inspection practice. The interval you can defend comes out of that reading, checked against the API 510 compliance requirements your program is measured on.
Where sour service actually changes the answer: 6.5.2.1 b) 6)
Clause 6.5.2.1 lets the inspector substitute an on-stream inspection for the internal inspection in two situations: where size or configuration makes entry physically impossible, or where entry is possible and all seven listed conditions are met. Those seven cover a general corrosion rate below 0.125 mm (0.005 in.) per year, remaining life over ten years, corrosive character established by at least five years of the same or similar service, no questionable condition found externally, shell temperature below the creep rupture range, absence of a non-integrally bonded liner, and condition 6.
Condition 6 states that the vessel is not subject to environmental cracking or hydrogen damage from the fluid being handled. A wet H2S drum fails that condition on the day the water phase meets the API RP 571 thresholds. The substitution is gone, and the failure is binary rather than graded: it does not matter that the corrosion rate is negligible or the remaining life is forty years.
Clause 6.5.2.2 sets out what follows. If the 6.5.2.1 b) conditions are not met, the next inspection shall be an internal inspection. The single alternative is an RBI assessment under 6.3 that establishes both that the risk is acceptable to the owner-operator and that the effectiveness of the external NDE technique is adequate for the expected damage mechanism. That second half is where most files fail, because probability of detection for SOHIC from the outside is a technique argument, not a risk score.
API RP 571 does treat sour service as its own mechanism, four times over
Paragraph 3.67 of API RP 571, 3rd edition, is titled Wet H2S Damage (Blistering/HIC/SOHIC/SSC) and covers four distinct forms of damage to carbon and low alloy steels. Blisters form where atomic hydrogen produced by the sulfide corrosion reaction collects at inclusions or laminations. HIC links neighboring blisters at different depths into stepwise cracking. SOHIC stacks arrays of cracks through the thickness under residual or applied stress, adjacent to weld heat-affected zones. SSC cracks hard zones under combined tensile stress and corrosion.
The environment is defined by the water phase, not by the feed assay. API RP 571 identifies conditions that promote all four forms as free liquid water plus any one of: more than 50 wppm dissolved H2S in that water, pH below 4 with some dissolved H2S, pH above 7.6 with 20 wppm dissolved hydrogen cyanide and some H2S, or H2S partial pressure above 0.0003 MPa (0.05 psia) in the gas phase. It notes that 50 wppm is an arbitrary defining value and that as little as 1 wppm in the water is sufficient to charge steel with hydrogen.
Temperature separates the forms. Blistering, HIC and SOHIC occur between ambient and 300 F (150 C) or higher. SSC occurs below about 180 F (82 C), with the trap that steel charged at higher temperature can crack during an excursion to lower temperature, including a shutdown. Hardness matters only for SSC: NACE SP0472 controls weld hardness below 200 HB, and API RP 571 notes that susceptibility rises where localized zones exceed 237 HB.
Why a corrosion rate cannot date a cracking mechanism
Remaining life is a thinning model, and three of the four wet H2S forms remove no metal. A vessel can return identical UT readings at every condition monitoring location across three inspection cycles while stepwise cracking advances through the plate. The interval that arithmetic produces is real for sour water corrosion and meaningless for HIC.
API RP 571 records the specific trap: improving steel cleanliness to resist blistering and HIC can still leave the steel susceptible to SOHIC, and the absence of visible blisters gives a false sense of security while subsurface damage develops. Blistering and HIC also develop without applied or residual stress, so a PWHT record removes the SSC argument and leaves the HIC argument untouched.
This is why the examination column of the table above matters more than the interval column. Crack detection is done by WFMT after grit or high-pressure water blasting, by ACFM without that surface preparation, by eddy current or radiography, and volumetrically by shear-wave UT, which is also the technique that sizes what is found. API RP 571 states plainly that penetrant testing cannot find tight cracks and should not be relied on. Once a flaw is characterized, the decision moves to a fitness-for-service assessment under API 579.
Building an interval that survives an audit: the 5.1 inspection plan
Clause 5.1.1 requires an inspection plan for every vessel in scope, covering all credible damage mechanisms as well as code and jurisdictional requirements. Clause 5.1.2.1 requires the plan to be developed by the inspector or the engineer, and requires a corrosion specialist to be consulted to identify credible damage mechanisms and susceptible areas for localized corrosion, cracking, corrosion under insulation and metallurgical damage. That consultation is a shall, not a recommendation.
Clause 5.1.2.2 lists what the schedule must weigh: type of damage mechanism, rate of damage progression, tolerance of the equipment to that type of damage, probability of the NDE method to identify the damage, maximum intervals defined in codes and standards, extent of previous examination, recent operating history including integrity operating window exceedances, management-of-change records, and RBI assessments where available. Probability of detection appears in the code as a scheduling input, which is exactly the argument a sour-service interval needs.
The supporting documents sit in Section 4. Clause 4.1.6 allows the owner-operator to develop a corrosion control document per API RP 970 identifying every mechanism a unit is susceptible to, and requires it to reach the inspectors, mechanical engineers and process engineers who have a role in fixed equipment integrity. Integrity operating windows follow API RP 584, and incident investigation follows API RP 585. Where those documents are missing, a program gap assessment is faster than rebuilding intervals one vessel at a time.
RBI is the only lawful route past ten years
Clause 6.3.1 permits an RBI assessment in compliance with API RP 580 to establish intervals for internal, on-stream and external inspections, and to exceed the limits in 6.4 and 6.5, including the ten-year and one-half remaining life limits and the five-year external limit. The 11th edition adds one hard stop: RBI intervals on external inspections shall not exceed ten years.
Clause 6.3.2 requires that where an RBI interval for internal or on-stream inspection exceeds the ten-year limit, the assessment is reviewed and approved by the engineer and the inspector at intervals not exceeding ten years, or sooner where process, equipment or consequence changes warrant it. Clause 6.3.3 asks that the assessment also review inspection history and potential fouling of the vessel's pressure-relieving devices.
For a wet H2S vessel, the RBI file has to do something narrower than reduce risk to an acceptable number. It has to establish that the external technique detects the specific mechanism at the specific location, because that is the test 6.5.2.2 imposes on the substitution. Building that argument once, properly, is the cheapest part of an RBI program design; rebuilding it under regulator questioning is the expensive part.
Upstream vessels run on a different section entirely
Clause 9.1.1 sets minimum inspection rules for pressure vessels in E&P services, covering drilling, production, gathering, transportation and treatment of liquid petroleum, natural gas, natural gas liquids and associated brine, and states that these vessels follow all sections of API 510 except Section 6. Every interval discussed above is therefore inapplicable to a sour separator on a production pad.
Clause 9.2.2 states that on-stream and internal inspections may be used interchangeably to satisfy inspection requirements, with internal inspection required when integrity cannot be established on-stream. Clause 9.2.5.3 sets the ceilings by risk class: lower-risk vessels at fifteen years or three-quarters remaining life, whichever is less, and higher-risk vessels at ten years or one-half remaining life, with the same under-four-years provision that caps at two years. Clause 9.2.6 d) requires portable vessels used for testing wells during completion to be inspected at least once in each three-year period of use, and more frequently in severe corrosive environments.
The sour-service control in Section 9 is 9.2.3.3, which requires other failure mechanisms including stress corrosion, brittle fracture and blistering to be taken into account when determining remaining life. Upstream, in other words, the code keeps the flexibility and moves the cracking argument into the remaining-life determination instead of the substitution test. Neither route lets a thinning number stand alone.
When the date arrives and the unit cannot come down
Clause 6.7.1 states that operating a vessel beyond its due date without a valid deferral is not permitted by the code, that deferrals should be the occasional exception, and that all deferrals shall be documented. A vessel granted a deferral is not treated as overdue until the new date.
Clause 6.7.2 defines a simplified deferral, available only where the current due date has not previously been deferred, the new date extends the interval by no more than 10 percent or six months, whichever is less, a review of current operating conditions and vessel history supports it, the inspector and an appropriate operations management representative consent, and the records are updated before the vessel runs past the original date.
Anything beyond that runs through 6.7.3, which requires a documented risk assessment against the owner-operator's risk threshold, drawing on fitness-for-service results, consequence of failure, damage mechanism susceptibilities and rates, calculated remaining life, and the extent or probability of detection of previous examinations together with the time elapsed since they were performed. It also requires a check on whether integrity operating windows need changing and whether the inspection plan needs modification. Facilities running an OSHA PSM mechanical integrity program should expect the deferral file to be sampled during audits.
What the report has to show for the interval to hold
An interval is only as defensible as the examination record behind it. For a wet H2S vessel, that record needs the mechanism named, the technique matched to the mechanism, the surface preparation stated, the coverage expressed as a percentage of the weld length or shell area actually examined, and the hardness survey results where SSC is credible. A report that says UT thickness taken, no significant loss supports nothing about HIC.
The same record has to close the loop back to 5.1.2.2 by explaining why the next date is what it is: which mechanism governs, how fast it progresses, and what the probability of detection was for the technique used. That is the paragraph auditors read first and inspectors write last. Our note on what makes an NDT report defensible sets out the elements that survive challenge.
Atlantis does not sell API certifications. We provide outsourced ASNT Level III support, method-specific procedure and technique review, and independent validation of the inspection records that carry your intervals. If you are holding a sour-service vessel with a due date and a thin technical file, talk to a Level III or request a review of the reports before the deferral clock starts.
Does API 510 set a shorter inspection interval for vessels in sour service?
No. API 510, 11th edition, states its intervals once, in Section 6, and applies them to every vessel: external at the lesser of five years or the internal/on-stream interval, internal or on-stream at the lesser of half remaining life or ten years. There is no sour-service table, no service class and no reduced ceiling. Sour service changes which inspection you owe, not the ceiling.
Can on-stream UT replace the internal inspection on a wet H2S vessel?
Not under the standard route. Clause 6.5.2.1 b) lists seven conditions that must all be met for on-stream inspection in lieu of internal, and condition 6 requires that the vessel is not subject to environmental cracking or hydrogen damage from the fluid handled. Wet H2S service fails that condition. Clause 6.5.2.2 then requires the next inspection to be internal, unless an RBI assessment shows the external technique is effective for the expected mechanism.
What concentration of H2S makes a service wet H2S?
API RP 571 gives four alternative triggers, any one of which is enough where free liquid water is present: more than 50 wppm dissolved H2S in the free water; free water below pH 4 with some dissolved H2S; free water above pH 7.6 with 20 wppm dissolved hydrogen cyanide and some H2S; or H2S partial pressure above 0.0003 MPa (0.05 psia) in the gas phase. NACE SP0296 uses 50 ppmw in the aqueous phase.
Does post-weld heat treatment let me lengthen the interval?
PWHT changes susceptibility, not the code ceiling. API RP 571 records that PWHT is highly effective at preventing sulfide stress cracking by reducing hardness and residual stress, and somewhat effective against SOHIC. It states that blistering and HIC develop without applied or residual stress, so PWHT will not prevent them. A PWHT record supports an RBI case; it does not by itself satisfy 6.5.2.1 b) 6).
How do upstream E&P vessels differ from refinery vessels here?
They sit under a different section. Clause 9.1.1 states that pressure vessels in E&P services follow all of API 510 except Section 6. Clause 9.2.2 allows on-stream and internal inspections to be used interchangeably, and 9.2.5.3 sets fifteen years or three-quarters remaining life for lower-risk vessels and ten years or half remaining life for higher-risk vessels. Clause 9.2.3.3 requires cracking and blistering to be taken into account in remaining life.
How long can an overdue wet H2S inspection be deferred?
A simplified deferral under 6.7.2 is capped at 10 percent of the interval or six months, whichever is less, and only where the due date has not been deferred before, the history review supports it, and the inspector and an operations management representative both consent. Anything longer runs through 6.7.3, which requires a documented risk assessment covering damage mechanism susceptibility, remaining life and the effectiveness of prior examinations.
Clause 6.3 versus 6.4: answering the "which clause" question
If a procedure or an assistant answer cites "clause 6.3" for external intervals in sour service, check the edition. In API 510, eleventh edition, 6.3 is the RBI clause and the default external interval rule is 6.4.1. Neither clause contains a sour-specific number. The question usually comes from mixing up the RBI route with the default ceilings.
The distinction matters in an audit. A plan that says "external every five years per 6.3" is citing the wrong clause, because 6.3 is what lets an owner move away from the five-year default, not what sets it. Under the eleventh edition, an RBI-based external interval may exceed five years but is capped at ten. A plan that relies on 6.3 should show the RBI assessment, its API RP 580 basis, and the engineer and inspector approval cycle. If your site still works to an older edition through a jurisdictional adoption, numbering may differ; confirm against the edition your program cites.
Similar-service and multizone shortcuts that sour service also closes
Beyond 6.5.2.1 b) 6), the eleventh edition closes a second shortcut that operators of vessel trains often rely on. Under 6.5.3, the results of an internal inspection on one vessel can normally support on-stream substitution on a similar vessel in the same or similar service. The same clause says that if the vessel is subject to environmental cracking or hydrogen damage, those similar-service results cannot be used that way.
In practice, this hits trains of sour water drums, amine contactors, flash drums and overhead accumulators that are identical in design and service. Internally inspecting the worst-case vessel and crediting the others is a common and legitimate practice for thinning mechanisms. For wet H2S vessels, each vessel needs its own internal inspection or its own RBI case under 6.5.2.2. Cracking depends heavily on local factors such as weld hardness, residual stress, plate cleanliness and local water chemistry, which can differ between vessels that look identical on paper.
Clause 6.5.4 lets a large vessel with zones of different corrosion rates treat each zone separately for intervals and for on-stream substitution. For sour service, the logic runs the same way. If only the lower section of a column sees free water with dissolved H2S, the inspection plan can concentrate crack-capable examination there. The damage-mechanism review must justify the zone boundary, and the boundary should be revisited whenever process conditions change. A zone that is "dry" in normal operation can see condensation during start-up, shutdown or upsets.
Wet hydrogen versus high-temperature hydrogen: two different questions
One common phrasing asks about "wet hydrogen service" and whether API 510 treats hydrogen damage as a separate mechanism. API 510 lists hydrogen-related damage in several separate places in 5.4.1. Wet H2S damage (blistering, HIC, SOHIC, SSC) is low-temperature damage driven by aqueous corrosion. High-temperature hydrogen attack sits elsewhere in the list, with reference to API RP 941, and hydrogen embrittlement is listed as a metallurgical change.
The inspection consequences differ:
| Damage | Driver | Reference the code points to | Inspection implication |
|---|---|---|---|
| Wet H2S damage (blistering, HIC, SOHIC, SSC) | Atomic hydrogen from sulfide corrosion in free water, at low to moderate temperature | API RP 571 | Crack-capable surface and volumetric NDE; on-stream substitution normally lost |
| High-temperature hydrogen attack (HTHA) | Hydrogen at elevated temperature and partial pressure reacting with carbides in steel | API RP 571 and API RP 941 | Specialised advanced UT techniques; susceptibility screening against the operating envelope |
| Hydrogen embrittlement | Loss of ductility from absorbed hydrogen, often seen during cool-down or in high-strength materials | API RP 571 | Managed through materials, start-up and shutdown practice, and crack detection at susceptible locations |
All three count as "hydrogen damage" for the purposes of condition 6 in 6.5.2.1 b). A hydroprocessing reactor effluent drum may face both HTHA and wet H2S damage in different zones. Its inspection plan must name both and match a technique to each. See the companion guide to high temperature hydrogen attack and API RP 941 for the high-temperature side.
Regulatory overlay: OSHA PSM and offshore 30 CFR 250
API 510 becomes mandatory when a regulator or jurisdiction adopts it, and two federal regimes matter most for sour vessels. OSHA's process safety management standard requires mechanical integrity inspections that follow recognised and generally accepted good engineering practice. BSEE's offshore production safety rule requires pressure vessels on Outer Continental Shelf production facilities to be repaired, maintained and inspected in accordance with API 510.
OSHA 29 CFR 1910.119(j)(4). For covered processes, inspection and testing procedures must follow recognised and generally accepted good engineering practices (RAGAGEP). Their frequency must be consistent with manufacturers' recommendations and good engineering practice, and more frequent if prior operating experience shows it is needed. For refinery and gas-plant pressure vessels, API 510 is the usual RAGAGEP. The "more frequent" language matters in sour service. A documented history of HIC or SSC findings in a unit is the kind of operating experience that can require shorter intervals than the API 510 ceiling, and auditors look for evidence that the program responded to its own findings. See OSHA PSM mechanical integrity programs and the background on HIC and SOHIC sour cracking.
30 CFR 250.851 (offshore and offshore-adjacent assets). BSEE's requirements table for pressure and fired vessels supporting production operations requires them to be designed, fabricated and code stamped to the applicable ASME sections, and to be repaired, maintained and inspected in accordance with API 510. This is where questions about "30 CFR alignment for offshore-adjacent assets" usually land. For a vessel inside BSEE jurisdiction, API 510 is not optional, and the environmental-cracking condition on on-stream substitution comes along with it. Two practical points follow:
- API 510 Section 9 gives alternative rules for exploration and production vessels, as the guide above explains. Whether a given offshore vessel is inspected under Section 6 or Section 9 should be stated in the operator's inspection program and confirmed with BSEE for that facility. Do not assume one or the other.
- Onshore facilities next to offshore operations (receiving terminals, gas plants and shore bases) usually fall under OSHA PSM and state rules rather than BSEE. Mapping each vessel to its regulator is part of the inspection program, and the answer can differ for vessels on the same site.
State boiler and pressure vessel programs add a third layer for some vessels. Many states reference the National Board Inspection Code and some accept owner-user inspection programs. Confirm with your jurisdiction. See API 510 vs the NBIC commissioned inspector and the NBIC (NB-23) overview.
Canada: sour service under provincial programs
Sour gas processing is common in Alberta and northeast British Columbia, and pressure vessels there are regulated provincially, not by API 510 alone. In Alberta, ABSA administers the pressure equipment regulations and approves owner-user inspection programs. API 510 is widely used within those programs for refinery and gas-plant vessels, but the regulator and the approved quality management system set intervals, inspector qualifications and reporting. Ontario's TSSA and other provincial authorities work on similar principles, generally adopting CSA B51.
The engineering logic in the guide above still applies. Sour vessels need crack-capable NDE, and thickness-based remaining life does not date cracking. The compliance route, though, is provincial. Confirm with the provincial regulator and your approved program.
A worked example: planning the internal inspection of a sour drum
Take a carbon steel sour water stripper feed drum with a negligible general corrosion rate and a long remaining life. Thinning arithmetic gives a comfortable ceiling, so the ten-year cap governs. Because the drum handles wet H2S, the next inspection is internal unless an RBI case under 6.5.2.2 supports on-stream inspection. The questions that matter are what the internal inspection must cover and how to stage it within the turnaround.
A qualitative planning sequence that inspection teams commonly use:
- Confirm the damage mechanism review. Which wet H2S forms are credible, where free water collects, the vessel's PWHT history and any hardness data. If the review is older than the last process change, update it first; 6.2.2.1 requires intervals to be re-established when service conditions change.
- Set examination scope by mechanism. SSC and surface-breaking SOHIC: WFMT on internal welds and heat-affected zones after abrasive or water-jet cleaning, at the coverage the plan specifies. HIC and blistering: visual for bulges plus straight-beam UT or phased array scanning of shell and head plate in wetted zones. Subsurface SOHIC at welds: angle-beam UT, phased array or TOFD.
- Plan surface preparation and access. WFMT sensitivity depends on cleaning. Scaffolding, blasting and lighting have to be scheduled before the NDE crew arrives, and the plan should say who verifies surface condition before examination.
- Decide in advance what happens if cracking is found. Clause 5.10.3 requires crack-like flaws and environmental cracking to be assessed by the inspector together with an engineer or corrosion specialist, referring to API 579-1/ASME FFS-1. Have the sizing method (depth and length) agreed beforehand so the data is usable for that assessment.
- Record coverage, not just results. The next interval depends on what was examined. A report that states the percentage of weld length and wetted area examined, by method, supports the next decision; "no relevant indications" without coverage does not.
Any change to the interval after the inspection, whether shorter because of findings or longer through RBI, is the owner's decision under the code, made by the inspector and engineer within the owner-operator's quality assurance system.
Examiner qualification and procedure control
API 510 is specific about who performs NDE and what records the inspector needs. Clause 4.5 says the examiner does not need API 510 certification or to be the owner's employee, but must be trained and competent in the procedures used. The owner may require certifications such as ASNT SNT-TC-1A, ASNT CP-189, CGSB or AWS QC1. The examiner's employer must keep certification records and make them available to the inspector.
For sour service this goes beyond paperwork. WFMT on prepared welds, phased array scanning for HIC and SOHIC, and TOFD sizing are all technique-sensitive. Before the turnaround, the inspector should be able to see:
- written procedures for each method, reviewed by a Level III, stating surface preparation, equipment, calibration, scan plans and reporting thresholds;
- certifications for each technician in the method and level used, issued under the contractor's written practice;
- for advanced UT, a scan plan or technique sheet showing coverage of the welds and zones the inspection plan names;
- a clear statement of what each technique can and cannot detect in that geometry, which is the "effectiveness" evidence 6.5.2.2 asks for when RBI is used to justify on-stream inspection.
Common mistakes that undermine a sour vessel interval
- Crediting similar-service results across a train of sour vessels. Clause 6.5.3 does not allow this for vessels subject to environmental cracking or hydrogen damage.
- Treating a "dry" zone as permanently dry. Start-up, shutdown and upset conditions can wet zones that are dry in normal operation. Multizone treatment under 6.5.4 needs that justification.
- Citing 6.3 as the source of a five-year external interval. The default rule is 6.4.1; 6.3 is the RBI route.
- Specifying "MT" without saying wet fluorescent or stating surface preparation. The method description in the plan should match the sensitivity the mechanism needs.
- Reporting findings without coverage. The next interval depends on what was examined as much as on what was found.
- Not re-running the review after a feed or process change. New crudes, added wash water or changes in cyanide levels can change wet H2S severity. Clause 6.2.2.1 and the site's management-of-change process both apply.
How Atlantis supports sour-service vessel programs
Atlantis performs the NDE that API 510 inspection plans require for wet H2S vessels and delivers results to the owner's API 510 authorized inspector, who remains inspector of record and sets intervals. Our ASNT-certified technicians work under ASNT Level III oversight. The work covers WFMT on prepared welds, UT and phased array inspection for HIC, SOHIC and blistering, TOFD for weld cracking and sizing, and corrosion mapping and thickness surveys, with procedures and scan plans reviewed by our Level III. We do not perform RBI or fitness-for-service assessments. See pressure vessel inspection services. Send your vessel list and turnaround window and we will reply with a quote: request a quote for sour-service vessel NDE.
Further questions on sour-service intervals
How does API 510 interact with 30 CFR 250 for offshore-adjacent assets?
For production facilities on the Outer Continental Shelf, 30 CFR 250.851 requires pressure and fired vessels to be repaired, maintained and inspected in accordance with API 510, which brings its intervals and on-stream conditions into the federal requirement. Onshore vessels next to offshore operations usually fall under OSHA PSM and state rules instead. Confirm each vessel's regulator.
Can one internal inspection cover a train of identical sour drums?
Not for on-stream substitution. API 510 6.5.3 says similar-service results cannot be used to substitute on-stream for internal inspection when the vessel is subject to environmental cracking or hydrogen damage.
Does OSHA PSM require shorter intervals for sour vessels?
OSHA 1910.119(j)(4) requires inspection frequency consistent with good engineering practice and more frequent inspection if prior operating experience shows it is necessary. Documented cracking history in sour service can be that kind of experience.
Is HTHA treated the same way as wet H2S damage in API 510?
Both count as hydrogen damage for the on-stream substitution condition, but they are separate mechanisms in 5.4.1 with different references (API RP 941 for HTHA) and different inspection techniques.
Who performs the NDE on a sour vessel, and who decides the interval?
Qualified examiners perform the NDE under the owner's specifications. API 510 does not require them to hold API 510 certification. The interval is set by the inspector or engineer under the owner-operator's quality assurance system.
Have a sour vessel coming due? Ask for an NDE scope and quote or ask about PAUT and TOFD for HIC and SOHIC.
Next step: UT Level 1 course
The corrosion rates and remaining-life figures that API 510 works from come from ultrasonic thickness readings. The UT Level 1 course covers straight-beam thickness measurement, calibration on reference blocks and recording readings to a written procedure. Completing a course is not certification: under an employer-based scheme such as SNT-TC-1A, your employer certifies you after its own examinations.
For employers: ASNT Level III consulting covers procedures, the written practice, qualification examinations and audit support for your technicians.