RAGAGEP: How API 510, 570 and 653 Satisfy OSHA PSM

Short answer: OSHA's Process Safety Management standard (29 CFR 1910.119) does not name API codes. It requires mechanical-integrity inspections and tests to follow recognized and generally accepted good engineering practices (RAGAGEP), at frequencies consistent with good engineering practice. For pressure vessels, piping and atmospheric storage tanks, most owners select API 510, API 570 and API 653 as that RAGAGEP. Once selected, their mandatory "shall" provisions become the yardstick OSHA measures your programme against.

This guide explains how that works in practice for mechanical-integrity managers, PSM coordinators and inspection supervisors: which code covers which equipment class, how OSHA treats "shall" and "should", what happens with older equipment and new code editions, what records an auditor expects, and how EPA's Risk Management Program and state rules sit alongside. It complements our deeper look at the NDT documentation side, OSHA PSM mechanical integrity and NDT.

What RAGAGEP means under OSHA PSM

RAGAGEP stands for recognized and generally accepted good engineering practices. OSHA's enforcement memorandum on the subject (issued in June 2015 and replaced by a clarified version dated 11 May 2016, without a substantive policy change) identifies three PSM provisions that directly reference or imply RAGAGEP:

• 1910.119(d)(3)(ii): the employer must document that equipment complies with RAGAGEP.
• 1910.119(j)(4)(ii): inspection and testing procedures must follow RAGAGEP.
• 1910.119(j)(4)(iii): inspection and test frequency must be consistent with applicable manufacturers' recommendations and good engineering practices, and more frequent if prior operating experience shows it is necessary.

OSHA describes RAGAGEP as practices based on established codes, standards, published technical reports, recommended practices or similar documents. The memo groups the sources into widely adopted codes, consensus documents developed under recognised procedures, non-consensus documents such as industry association guidance, and manufacturers' recommendations. Employers may also write internal standards, provided they represent recognised and generally accepted practice and meet or exceed the protection of any published RAGAGEP that exists.

The mechanical-integrity element, 1910.119(j), applies to pressure vessels and storage tanks, piping systems (including piping components such as valves), relief and vent systems and devices, emergency shutdown systems, controls (including monitoring devices and sensors, alarms and interlocks) and pumps. For the first three classes, API's in-service inspection codes are the practices most US refiners, chemical plants and gas processors choose.

Mapping PSM equipment classes to the usual RAGAGEP

The table below shows the practices owners most commonly cite for each equipment class. It is not a list OSHA publishes; it is what you will typically find in a PSM mechanical-integrity programme. Your programme may select others, and must document what it selects.

Each of these documents is published by its standards body; buy and control current copies rather than relying on summaries.

Why API 510, 570 and 653 work as RAGAGEP

An in-service inspection code is useful as RAGAGEP because it answers the three questions PSM asks: what to inspect, how, and how often, and it requires records that can be audited.

API 510 covers pressure vessels and pressure-relieving devices after they are placed in service. In the 11th edition it requires external visual inspection at an interval not exceeding the lesser of five years or the required internal or on-stream interval, and sets the internal or on-stream interval at no more than the lesser of one-half the remaining life or 10 years, unless a risk-based inspection (RBI) assessment is applied. It also sets inspection intervals for pressure-relieving devices, with typical process services and clean, non-corrosive services treated differently.

API 570 covers in-service piping. It classifies piping by consequence of failure, sets maximum thickness-measurement and external visual intervals by class, and links intervals to corrosion rate and remaining life. The 5th edition was published in February 2024; check its tables directly rather than relying on figures quoted from older editions.

API 653 covers aboveground storage tanks built to API 650 or its predecessor. The 5th edition, with addenda through 2023, requires routine in-service visual inspection by owner-operator personnel at intervals not exceeding one month, and a formal external inspection by an authorized inspector at least every five years or RCA/4N years (based on the shell corrosion allowance and rate), whichever is less. Internal inspection intervals are tied to bottom corrosion rates, with maximum limits that depend on tank features. Addendum 4 (July 2025) revised the tank-bottom thickness measurement text, so confirm the current wording before relying on it.

Each code also requires inspectors with defined qualifications (API certification for the authorized inspector), inspection plans, corrosion-rate calculations, and permanent records. That is why an OSHA compliance officer reviewing a refinery will normally ask which edition of API 510, 570 and 653 the site has adopted and then test the file against it.

"Shall" versus "should": what you inherit when you choose a code

OSHA's 2016 memorandum treats the language of the selected RAGAGEP carefully:

• "Shall" or "must" provisions are treated as mandatory minimum requirements. Deviating from one in a RAGAGEP the employer has selected creates a presumed violation, although the employer can explain its rationale.
• "Should" provisions describe acceptable and preferred practice. Not following one does not create a presumed violation, but the employer must be able to show that its alternative approach still represents good engineering practice.
• "Should not" provisions describe disfavoured practices; the compliance officer evaluates whether the employer's approach is still sound.

This matters because API documents come in two kinds. API 510, 570 and 653 are codes and standards written largely in "shall" language. API 572, 574, 575, 576, 571 and 583 are recommended practices, written largely in "should" language. Writing "API 510" into your mechanical-integrity procedure commits you to its "shall" provisions, including those on interval limits, inspector qualifications, repair authorization and records. Citing an RP gives more room, but you still have to show your departures are reasonable.

The memo also cautions against mixing and matching. Standards are written as packages, and selectively applying provisions from several RAGAGEP can leave a hazard inadequately controlled. If your programme combines a code with an internal standard or an RBI methodology, document how the pieces fit and why the result is at least as protective.

Where more than one RAGAGEP applies, OSHA accepts either. The memo's example is relief device sizing, where API RP 520 and ISO 4126-9 are both treated as acceptable.

Inspection frequency, risk-based inspection and prior experience

1910.119(j)(4)(iii) has two halves. The first makes frequency follow manufacturers' recommendations and good engineering practice; for most owners that means the intervals in API 510, 570 and 653. The second requires more frequent inspection if prior operating experience shows it is needed. An NDE survey that finds faster corrosion than predicted is exactly that kind of experience, and leaving the interval unchanged becomes a decision you have to justify.

All three API codes allow an owner to set intervals using risk-based inspection under API RP 580 (and quantitative methods such as API RP 581), within limits the codes define. RBI does not remove the RAGAGEP obligation; it changes how the interval is derived. The RBI study, its assumptions and the inspection data behind it become part of the evidence an auditor will review. RBI and fitness-for-service assessments (API 579-1/ASME FFS-1) are engineering studies the owner commissions from qualified specialists; Atlantis does not provide them. Our time-based vs risk-based intervals guide explains the difference.

Whatever the basis, the interval rests on measured data: thickness readings at condition-monitoring locations, corrosion rates calculated as the codes describe, and damage-mechanism assignments. See long-term vs short-term corrosion rates for how the codes expect those numbers to be produced.

Older equipment and new code editions

Two PSM questions come up in every audit of an older site.

Equipment built to codes no longer in use. 1910.119(d)(3)(iii) requires the employer, for existing equipment designed and constructed to codes, standards or practices no longer in general use, to determine and document that the equipment is designed, maintained, inspected, tested and operating in a safe manner. In-service inspection to API 510, 570 or 653 is usually central to that demonstration, because those codes are written for equipment of any construction vintage.

New editions. OSHA's memo says a newer edition of a RAGAGEP is not retroactively mandatory unless it says so explicitly. If an update is not retroactive, PSM does not compel you to upgrade the equipment, but you must still show safe operation and address any hazard the update identifies through tools such as process hazard analysis revalidation and management of change. For inspection codes, the practical approach is to adopt each new edition through a documented change: review what changed (for example API 570's 5th edition in 2024 or API 653 Addendum 4 in 2025), decide the effective date for your programme, update procedures and inspection plans, and train inspectors. Recording which edition each inspection was performed to avoids confusion when intervals or acceptance rules change.

API's codes are copyrighted. Buy current copies from API or an authorised distributor, keep a controlled set, and do not rely on old editions that circulate online.

Internal standards

Many owners write corporate inspection standards that translate API codes into site practice, set tighter rules for specific services, or cover equipment the codes do not address. OSHA's memo accepts internal standards as RAGAGEP when they represent recognised and generally accepted practice, and lists legitimate purposes such as translating published requirements into procedures, addressing unique hazards, supplementing inadequate guidance and dealing with outdated codes. Two cautions apply. Internal standards must meet or exceed the protection of published RAGAGEP where it exists. And an internal standard that is more stringent than API still binds the employer that wrote it, so do not write a requirement you do not intend to meet.

Records: what an auditor checks against the code

1910.119(j)(4)(iv) requires each inspection and test to be documented with five elements: the date, the name of the person who performed it, the serial number or other identifier of the equipment, a description of the inspection or test, and the results. API 510, 570 and 653 add their own record requirements, such as calculated corrosion rates, remaining life, next inspection dates and repair records. A practical audit trail links all of them.

Under API 510 the inspector evaluates and accepts all NDE results. An NDE report is evidence; the inspector's evaluation and recommendations are what close the loop. Under 1910.119(j)(5), deficiencies outside acceptable limits defined in the process safety information must be corrected before further use or in a safe and timely manner with necessary safeguards.

EPA RMP, state plans and boiler laws: the other layers

EPA Risk Management Program. For Program 3 processes, 40 CFR 68.73 mirrors OSHA's mechanical-integrity element almost word for word: the same equipment list, inspections following RAGAGEP, frequency consistent with manufacturers' recommendations and good engineering practice, and the same documentation elements. A programme built on API 510, 570 and 653 normally serves both rules.

State OSHA plans. States that run their own occupational safety plans may add requirements. California's Process Safety Management for Petroleum Refineries regulation (Title 8 section 5189.1), effective 1 October 2017, added elements such as documented damage mechanism reviews for refinery processes, which lean heavily on API RP 571 knowledge.

State boiler and pressure vessel laws. Separately from PSM, some states register pressure vessels, require certificate inspections and decide who may sign them, sometimes adopting API 510 by reference. See who has authority over pressure equipment in the US and owner-user inspection organizations (NB-371).

Canada. PSM is a US rule. Canadian owners work under provincial pressure equipment regulations (for example ABSA in Alberta and TSSA in Ontario), which accept owner integrity management systems and commonly reference the same API codes.

A worked example: an audit finding avoided

A gas processing plant's mechanical-integrity procedure states that vessels are inspected "per API 510". During a compliance audit, the reviewer samples an amine contactor. The file shows a thickness survey five years earlier, but no evidence of an external visual inspection since then, and the internal inspection is due on a 10-year cycle even though the calculated remaining life is only 14 years.

Against API 510's "shall" provisions, two problems appear: the internal interval exceeds one-half of the remaining life, and the external visual interval has been exceeded. Neither is a "should" that the plant can argue around; it selected the code. The plant corrects the plan, schedules external visual and UT thickness inspection, and records the corrected due dates. The NDE contractor's report lists the date, the named examiner, the vessel tag, the method and procedure, and the readings at each CML, so the (j)(4)(iv) elements are met. The inspector recalculates corrosion rate and remaining life and signs the evaluation. Had the plant instead documented an RBI assessment supporting a different interval within API 510's limits, the evidence trail would have been the RBI study plus the data behind it.

Common mistakes

• Citing "API 510/570/653" in the PSM procedure without stating the edition or how new editions are adopted.
• Treating recommended-practice "should" language as optional without documenting why the alternative is sound.
• Mixing provisions from different codes or editions without showing the result is at least as protective.
• Keeping intervals unchanged after NDE shows corrosion faster than assumed.
• NDE reports signed by a company rather than a named, certified examiner.
• Relying on old, unofficial copies of API codes instead of a controlled current set.

How Atlantis supports API-based PSM programmes

Atlantis NDT performs the NDE your RAGAGEP calls for: UT thickness and CML surveys, corrosion mapping, PAUT, TOFD, radiography by crews licensed where the work is done, MT, PT, VT, ET, tank-floor MFL and guided-wave screening, by ASNT-certified technicians under ASNT Level III oversight. Each report carries the five PSM record elements and is delivered to your API-certified inspector, who remains the inspector of record and evaluates the results. Atlantis does not set intervals or perform RBI or fitness-for-service studies. See inspection services, pressure vessel inspection and storage tank inspection, or request a quote within 24 hours.

Frequently asked questions

What is RAGAGEP in OSHA PSM?

Recognized and generally accepted good engineering practices: the codes, standards, recommended practices, manufacturers' recommendations and acceptable internal standards an employer selects to design, inspect and test covered equipment.

Is API 510 RAGAGEP?

Yes, it is widely recognised and generally accepted for in-service pressure vessel inspection and is the practice most PSM-covered owners select for vessels. OSHA does not mandate it by name.

Does OSHA require API 570 for piping?

No standard is required by name. PSM requires inspections to follow RAGAGEP; API 570 is the practice most owners select for in-service process piping.

Is API 653 required for storage tanks under PSM?

PSM requires RAGAGEP for covered storage tanks. API 653 is the usual choice for field-erected aboveground tanks; smaller shop-built tanks are often inspected to STI SP001.

What does RAGAGEP mean for mechanical integrity inspection frequency?

1910.119(j)(4)(iii) requires frequency consistent with manufacturers' recommendations and good engineering practice, and more often if operating experience shows it is needed.

What is the difference between "shall" and "should" in RAGAGEP?

Deviating from a "shall" in your selected RAGAGEP creates a presumed violation. A "should" is a preferred practice; alternatives are acceptable if they are good engineering practice.

Do I have to upgrade equipment when a new API edition is published?

Not unless the edition is explicitly retroactive. You must still show the equipment is operating safely and manage identified hazards through PHA and management of change.

What records does 1910.119(j)(4)(iv) require?

The date, the name of the person who performed the inspection or test, the equipment identifier, a description of the inspection or test, and the results.

Can an internal company standard be RAGAGEP?

Yes, if it represents recognised and generally accepted practice and meets or exceeds any applicable published RAGAGEP.

Does EPA RMP use RAGAGEP too?

Yes. 40 CFR 68.73 contains equivalent mechanical-integrity requirements for Program 3 processes.

Is risk-based inspection acceptable as RAGAGEP?

API 510, 570 and 653 allow RBI-based intervals within their limits, using API RP 580 methods. The RBI study and data become part of your RAGAGEP evidence.

Need NDE that holds up in a PSM audit? Send us your inspection scope or book a call with our Level III, and review our OSHA PSM compliance overview.