Editor’s note: The API inspection standards are revised on multi-year cycles, with periodic addenda and errata, and specific provisions can change between editions. The governing edition for any given asset is the one adopted by your jurisdiction and written into your owner-user inspection program. Editions, addenda, and errata are updated on independent schedules; verify the current set against API’s current publication listings and your local regulatory requirements before acting.
The short version: Three API standards set in-service inspection intervals for the main categories of fixed equipment in refining and processing. API 510 covers pressure vessels, API 570 covers piping, and API 653 covers aboveground storage tanks. Each sets maximum inspection intervals, and each provides risk-based inspection (RBI) as an alternative pathway. The default maximums are, broadly: 10 years internal and 5 years external for vessels (API 510), 5 to 10 years by piping class for piping (API 570), and for tanks (API 653) a 5-year external maximum with an internal inspection normally starting at a 10-year baseline and capped at 20 or 30 years depending on release-prevention features. The three standards do not all share one interval formula; this page summarizes each separately and points to the standards for authoritative detail.
Two ideas that recur (and one that does not apply everywhere)
The three standards are related but not identical in how they set intervals, so it helps to separate what they share from what they do not.
Two ideas recur. First, every standard sets a fixed maximum interval in calendar years as a ceiling. Second, all three permit risk-based inspection (RBI) conducted in accordance with API RP 580 as an alternative to the default intervals, which can establish different (often longer) intervals when a documented assessment supports it. API RP 581 provides a quantitative RBI methodology that can be used to implement API RP 580, though it is not universally required alongside it.
The idea that does not apply everywhere is the “half remaining life” rule. In API 510 and in API 570’s thickness-measurement intervals, the interval is the lesser of a fixed maximum or one-half of the component’s calculated remaining life, so a faster-corroding component is inspected sooner. That half-life structure is central to those two standards. API 653 works differently, using tank-specific rules built around bottom corrosion and minimum remaining thickness rather than a general half-life formula. Treating all three as one formula is a common oversimplification, and it is wrong for tanks. Each standard is summarized on its own terms below.
The intervals here are the default, non-RBI maximums. They are the substance of copyrighted API standards; the summaries are paraphrased, and the standards are the authoritative source for exact wording, formulas, and conditions.
API 510: pressure vessels
API 510 governs in-service inspection of pressure vessels. It defines the interval separately for two inspection types.
| Inspection type | Maximum interval (default, non-RBI) |
|---|---|
| Internal or on-stream | The lesser of half the remaining life or 10 years |
| External (visual) | The lesser of 5 years or the required internal/on-stream interval |
Table 1: API 510 default maximum inspection intervals. The two intervals are set separately. Under-4-year remaining life and RBI provisions modify these. Refer to API 510 for authoritative requirements.
A few points that matter in practice. The external visual and the internal/on-stream inspection are treated as separate activities with separate clocks, even when scheduled together. The external interval is the lesser of 5 years or the required internal/on-stream interval, so it can be shorter than 5 years when the internal interval is shorter, though 5 years is its ceiling. An on-stream inspection may substitute for the internal inspection when specific conditions are met (for example, a low and known general corrosion rate, remaining life above 10 years, and established service history). When remaining life is under 4 years, the interval may be set to the full remaining life up to a 2-year maximum. Pressure-relieving devices carry their own inspection intervals.
API 570: piping
API 570 governs in-service inspection of piping systems, and it is the most differentiated of the three because it sorts piping into risk classes, each with its own maximum intervals. Class 1 is the highest-consequence category, descending to Class 3 and an optional Class 4.
| Piping class | Thickness measurement (max) | External visual (max) |
|---|---|---|
| Class 1 (highest consequence) | 5 years | 5 years |
| Class 2 (moderate) | 10 years | 5 years |
| Class 3 (lower) | 10 years | 10 years |
| Class 4 (lowest) | Optional | Optional |
Table 2: API 570 default maximum inspection intervals by piping class. The thickness-measurement interval is also capped at the lesser of the figure shown or half the remaining life. Class assignment is based on the consequence of a leak. Refer to API 570 for authoritative requirements.
The class-based structure is the key feature: the higher the consequence of a failure, the shorter the maximum interval. The half-remaining-life limit applies to the thickness-measurement interval (it is the lesser of the class maximum or half the remaining life); the external visual interval is governed by the class maximum shown. The same under-4-year rule applies to thickness intervals (full remaining life up to a 2-year maximum). Class 4 piping inspection is optional and is established by the owner-operator based on reliability and business considerations. Two piping-specific points matter here. First, on corrosion rate: long- and short-term corrosion rates are compared to identify which produces the shortest remaining life, and the authorized inspector, in consultation with a corrosion specialist, selects the corrosion rate that best reflects the current process. Second, corrosion under insulation (CUI) receives specific attention, because the damage is hidden beneath the insulation and not visible in a standard external walk-down.
API 653: aboveground storage tanks
API 653 governs in-service inspection of aboveground storage tanks. Its interval structure is tank-specific and is the one most often misstated, so it is worth laying out carefully.
| Inspection type | Maximum interval (default, non-RBI) |
|---|---|
| Routine in-service (by owner personnel) | At intervals appropriate to site conditions, but not exceeding one month |
| External (visual, by authorized inspector) | 5 years, or per shell corrosion-rate calculation, whichever is less |
| Internal (out-of-service, bottom), initial | Normally 10 years as a baseline, plus permitted safeguard credits |
| Internal, outer ceiling | 20 years (no release prevention barrier) or 30 years (with one) |
Table 3: API 653 default maximum inspection intervals. The internal inspection is governed by tank-specific rules (bottom corrosion and minimum remaining thickness), not a general half-life formula. Refer to API 653 for authoritative requirements, including the safeguard-credit tables.
Here is how the tank rules actually work. First, the 5-year external inspection is the formal external inspection performed by an authorized inspector. It is distinct from the routine in-service inspection that API 653 also requires (Section 6.3.1), a more frequent visual check of the tank while in operation, generally carried out by owner personnel at an interval that must not exceed one month (Section 6.3.1.2). The 5-year figure is therefore the formal-inspection interval that sits on top of routine monthly monitoring.
The formal external inspection is generally every 5 years, or shorter if the shell corrosion-rate calculation requires it. A separate external ultrasonic thickness inspection of the shell has its own corrosion-rate-based limits. For the internal (out-of-service) inspection, which examines the tank bottom, the initial interval normally starts from a 10-year baseline. API 653 then permits additive credits that extend that baseline for protective features such as a thicker bottom, a thin-film lining, cathodic protection, or a release prevention barrier, and these credits stack. Subsequent internal inspections are based on the measured bottom corrosion rate and the minimum remaining thickness of the floor. Overlaying all of it is an outer ceiling that no internal interval may exceed: 20 years for a tank without a release prevention barrier, and 30 years for a tank with one. RBI in accordance with API RP 580 offers an alternative to these defaults where permitted. The distinction to keep straight is that the 10-year figure is the baseline for the initial internal inspection, while the 20 or 30 years is the outer ceiling; they are different limits, which is the source of most confusion about API 653.
How the three standards fit together
For a facility running all three asset types, the standards form a consistent inspection framework. API 510 (vessels), API 570 (piping), and API 653 (tanks) are complemented by API RP 580 (the RBI methodology that can modify intervals across all three, with API RP 581 available as a quantitative implementation) and reference ASME and other codes for the underlying design and NDE requirements. The owner-user is responsible for the inspection program, the interval basis, and the qualified inspectors and examiners who carry it out. The through-line is that the default intervals are ceilings, not schedules: measured corrosion, remaining-thickness calculations, and RBI assessments all work to set the actual interval at or below the maximum the standard allows.
For the corrosion and fouling processes that drive these intervals, see our coverage of the cost of corrosion and heat exchanger fouling costs, which quantify the wall-loss and fouling that determine remaining life in the first place.
Frequently Asked Questions
What is the inspection interval for pressure vessels under API 510?
API 510 sets the internal or on-stream inspection interval at the lesser of half the vessel’s remaining life or 10 years, and the external visual inspection at the lesser of 5 years or the required internal interval. These are default maximums; RBI conducted in accordance with API RP 580 can modify them, and a special rule applies when remaining life is under 4 years.
How often does API 570 require piping inspection?
API 570 sets maximum intervals by piping class. Class 1 (highest consequence) allows thickness measurement and external visual inspection up to every 5 years; Class 2 allows thickness measurement up to 10 years with external visual up to 5 years; Class 3 allows both up to 10 years; Class 4 is optional, set by the owner-operator. The thickness-measurement interval is also capped at half the remaining life, whichever is less.
What is the API 653 tank inspection interval?
API 653 requires a formal external inspection by an authorized inspector at a maximum of 5 years (or shorter per the shell corrosion-rate calculation), on top of a more frequent routine in-service inspection by owner personnel at an interval not exceeding one month. The internal (out-of-service) inspection normally starts from a 10-year baseline, extendable with additive credits for protective features such as linings, cathodic protection, or a release prevention barrier, and is subject to an outer ceiling of 20 years without a release prevention barrier or 30 years with one. Subsequent internal intervals are based on bottom corrosion rate and minimum remaining thickness. RBI offers an alternative where permitted.
Does API 653 use the “half remaining life” rule?
No, not in the way API 510 and API 570 do. API 510 and API 570’s thickness-measurement intervals use the lesser of a fixed maximum or half the remaining life. API 653 uses tank-specific rules built around bottom corrosion rate and minimum remaining floor thickness, with a 10-year initial-inspection baseline and a 20- or 30-year outer ceiling. Applying a single half-life formula across all three standards is a common but incorrect simplification.
Can RBI change the default inspection intervals?
Yes. All three standards permit risk-based inspection (RBI) conducted in accordance with API RP 580 as an alternative to the default intervals, and it can establish different intervals when a documented risk assessment supports it. Some outer limits and program-specific constraints still apply, and approval and documentation requirements vary among the three codes and among owner-user programs, so the specific requirements should be taken from the applicable standard.
What is the difference between external and internal API inspections?
External inspections are visual examinations of the outside of the equipment, performed on a fixed maximum interval (up to 5 years for vessels and tanks, and by class for piping) because they address the external environment. Internal or on-stream inspections examine the inside and are driven by internal corrosion and remaining life or, for tanks, bottom condition. The two have separate intervals and separate clocks, even when scheduled together.
Sources and References
- API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, 11th Edition (October 2022), including Errata 1 (2023) and Errata 2 (2025), American Petroleum Institute. Authoritative source for pressure vessel inspection intervals (internal/on-stream: lesser of half remaining life or 10 years; external: lesser of 5 years or the internal interval), the under-4-year rule, and on-stream substitution conditions. Intervals paraphrased; consult the standard.
- API 570, Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems, 5th Edition (February 2024), including Addendum 1 (2025), American Petroleum Institute. Authoritative source for piping inspection intervals by class, the half-life cap on thickness intervals, corrosion-rate determination (long- and short-term rates compared, with the authorized inspector and a corrosion specialist selecting the rate that best reflects the current process), and corrosion-under-insulation provisions.
- API 653, Tank Inspection, Repair, Alteration, and Reconstruction, 5th Edition (November 2014), including Addendum 1 (2018), Addendum 2 (2020), Addendum 3 (2023), Addendum 4 (2025), Errata 1 (2020), and Errata 2 (2025), American Petroleum Institute. Authoritative source for aboveground storage tank inspection intervals (routine in-service inspection per Section 6.3.1, at an interval not exceeding one month; formal external: 5-year maximum; internal: 10-year baseline with additive safeguard credits; outer ceiling: 20 years without a release prevention barrier, 30 years with one) and the safeguard-credit tables.
- API RP 580, Elements of a Risk-Based Inspection Program, 4th Edition (August 2023), including Addendum 1 (2025), American Petroleum Institute. The RBI methodology referenced by all three inspection standards as an alternative pathway for establishing intervals.
- API RP 581, Risk-Based Inspection Methodology, 4th Edition (January 2025), American Petroleum Institute. Provides a quantitative RBI methodology that can be used to support implementation of API RP 580.
- Note on editions and addenda: API standards are updated by addenda and errata on independent cycles, and the complete current set for each standard changes over time. The editions, addenda, and errata above were verified against API publication listings as of this writing; confirm them against API’s published listings and the edition adopted by your jurisdiction and owner-user program before relying on any interval. The API Individual Certification Program effectivity sheets and Bodies of Knowledge indicate which editions are tested but are not themselves the authority for the requirements, and they can lag the current published edition.
