External and On-stream Inspection Intervals for Vessels in Sour and Wet H2S Service

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.

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