What an API 510 / API 570 Inspection Plan Must Contain

Short answer: API 510 and API 570 both require a documented inspection plan for every pressure vessel, piping system or circuit, and pressure-relieving device in scope. The inspector and/or engineer writes it, with a corrosion specialist consulted on damage mechanisms. At minimum it states the inspection types, the next due date for each, the inspection and NDE techniques, the extent and locations (CMLs), surface preparation, any pressure test, planned repairs, and the operating changes or IOW exceedances since the last inspection.

This guide sets out those contents in plain language, explains where API 510 and API 570 differ, and shows how the NDE section of a plan should be written so that a field crew can execute it without guessing. We paraphrase the codes rather than reproduce them. API 510 is in its 11th edition (October 2022) and API 570 is in its 5th edition (February 2024); some of the wording referred to below comes from the API 570 4th edition, so check every item against your licensed copy of the current edition and any addenda. Official product pages are on api.org.

Who must have an inspection plan, and who writes it

Direct answer: The owner-operator must have a plan for every item within the scope of the code. The inspector and/or engineer develops it. A corrosion specialist must be consulted to identify credible damage mechanisms and the locations where localized corrosion, cracking or metallurgical damage is likely. The plan belongs to the owner's inspection organization, not to the contractor who performs the NDE.

API 510 (11th edition, section 5.1) applies the plan requirement to all pressure vessels and pressure-relieving devices (PRDs) in scope. API 570 applies the same requirement to piping systems and/or circuits and their associated relief devices. In both codes, writing and keeping inspection plans is listed as one of the duties of the owner-operator's quality assurance inspection/repair management system. The other duties include setting intervals, recording results and controlling the qualification of NDE personnel. This is why an auditor asks for the plan before asking for any thickness data. Without a plan there is no stated basis for the data.

The corrosion specialist requirement is often handled badly. Both codes require that a corrosion specialist is consulted, not merely available. API 570 (4th edition text) goes further. It requires consultation for piping that operates at elevated temperature (it gives a threshold; check the current edition) and for piping that operates below the ductile-to-brittle transition temperature. In practice the specialist's input is captured in the unit's corrosion control document (CCD), developed under API RP 970 or an equivalent method. The plan then points to that document circuit by circuit. If your plan cannot show where the damage mechanism assignment came from, that is the first gap to close.

The NDE examiner is a separate role. API 510 says the examiner does not need API inspector certification and need not be an owner employee. The examiner must be trained and competent in the procedures used. The owner may require certifications such as ASNT SNT-TC-1A or CP-189. The examiner's employer keeps the certification records, and the inspector confirms that every examiner is qualified. The plan tells the examiner what to do. It does not turn the examiner into the decision-maker. All NDE results are evaluated and accepted by the inspector.

The minimum contents, item by item

Direct answer: Both codes say the plan must contain the inspection tasks and schedule needed to monitor damage mechanisms and assure integrity. It should then define the inspection types, next due dates, techniques, extent and locations, cleaning requirements, pressure-test requirements and planned repairs. API 510 adds operating deviations since the last inspection. API 570 also lists damage types, damage locations and access needs.

Both codes let you start from a generic plan based on industry practice. Both expect it to be developed until it gives enough detail to direct the inspector to every area of concern. Neither code requires a single document. The plan can live across the inspection data system, the CCD and the CML register, as long as the contents are readily accessible from inspection data systems. "Readily accessible" is the test an auditor applies. If it takes three people and a shared drive to answer "what is the next due date for this vessel and why", the plan is not readily accessible.

How the plan is developed: the inputs the codes name

Direct answer: The plan is built from data, not from a template. Both codes say examinations are scheduled after considering the type of damage, how fast it progresses, how tolerant the equipment is to it, how well the NDE method can detect it, code maximum intervals, the extent of previous examinations, recent operating history including IOW exceedances, MOC records and any RBI assessment.

Each input changes something concrete in the plan:

• Damage type and rate drive the choice between thickness monitoring and crack-detection techniques, and drive the interval. General thinning at a stable rate suits UT thickness at CMLs. Localized pitting or under-deposit attack needs scanning or corrosion mapping, not spot readings.
• Tolerance to damage is the remaining margin above required thickness, or the flaw size the component can carry. A thin-walled, high-pressure circuit tolerates less wall loss before action.
• Probability of detection is a code input in its own right. API 510 says the methods and extent of NDE must be evaluated to make sure the technique can find the damage mechanism and show its extent and severity. A plan that specifies spot UT for a cracking mechanism fails this test, however many readings it collects.
• Maximum intervals are the code limits. In API 510 (11th edition) the internal or on-stream interval is the lesser of half the remaining life or 10 years, and the external interval is the lesser of five years or the internal/on-stream interval, unless an RBI assessment justifies otherwise. API 570 sets intervals by piping class and remaining life. See our API 570 piping service classes guide.
• Operating history, IOWs and MOCs are the early-warning inputs. API 510 says future plans and intervals have historically relied on past corrosion rates, and that without an IOW programme there is often no warning that conditions have changed. Our page on API RP 584 integrity operating windows explains the link.
• RBI, where the owner uses it, can set intervals and extent under API RP 580. It is an owner engineering assessment. The plan records its outputs; it does not replace the plan.

Both codes also require that plans are reviewed and amended as needed. API 570's wording ties the review to new information about damage mechanisms or deterioration rates, such as inspection findings or MOC documents. A plan written once at commissioning and never revised does not meet that requirement, even if every due date has been met.

Writing the NDE section so it can be executed

Direct answer: The NDE section must name the technique, the procedure, the locations and the coverage. It must also state the surface condition, the temperature limits and the reporting format. If a qualified examiner who has never seen the unit cannot do the work from the plan alone, the plan is incomplete.

Many plan failures seen from the field side are not missing items. They are items written too vaguely to execute. Compare "UT thickness, shell and heads" with "UT thickness at CMLs V-101-01 to V-101-24 per the attached sketch, 4-point readings at each CML, plus a 300 mm square corrosion-mapping grid at each of the two nozzles below the liquid level, coating left in place where sound, metal temperature below the probe limit". The second version can be priced, staffed, executed and audited. The first produces a report that nobody can compare with the last one.

A workable NDE line in a plan covers:

1. Technique and why: for example straight-beam UT for general thinning, PAUT or automated UT mapping for localized loss, wet fluorescent MT for surface-breaking cracks in sour service, shear-wave or PAUT for embedded weld flaws, profile radiography for insulated small-bore piping. Our NDE method selection by damage mechanism guide sets out the matches.
2. Procedure reference: the owner-approved or contractor procedure that the examiner will follow, qualified to the referencing code where one applies.
3. Locations: CML or TML identifiers, weld numbers, nozzle marks, with a sketch or isometric reference. API 570 asks for extent and locations at CMLs, so the CML register is part of the plan. See our guide to building a CML register that lasts.
4. Extent: number of readings per CML, grid spacing, percentage of welds, length of circumferential scans.
5. Surface preparation: what removal of coating, scale or insulation is needed. Both codes list cleaning requirements as a plan item because surface condition changes what a technique can detect.
6. Conditions: on-stream or shutdown, maximum metal temperature for the probe and couplant, access method.
7. Personnel qualification: the level and method certification required under the owner's or contractor's written practice.
8. Reporting: data format, so readings can be trended against previous results at the same CML.

On-stream inspection needs particular care. API 510 lets the inspector substitute an on-stream inspection for an internal one, either when entry is physically impossible or when a defined set of conditions is met. When on-stream inspection is used, the code requires the type and extent of NDE to be specified in the plan. It also lists limitations of external NDE that the plan should address, including cladding, internal attachments, weldments, temperature and surface condition. For CUI-exposed equipment, read our guide to CUI in API 570 and API 510 inspection plans.

API 510 versus API 570: how the plans differ in practice

Direct answer: A vessel plan is item-based: one asset, a set of components, internal and external inspection types. A piping plan is circuit-based. Systems are broken into circuits with a common damage mechanism, material and damage rate, and the plan works through many CMLs. It also covers features such as injection points, deadlegs, soil-to-air interfaces and small-bore connections.

API 570 starts the planning process with systemization and circuitization. Piping is grouped into systems, usually at process-flow-diagram level. Systems are then split into circuits, usually at P&ID level, where the damage mechanism, material and expected rate are the same. That step is what makes a piping plan manageable. One circuit plan can direct readings at dozens of CMLs because they share a basis. API 574 gives more detail on building systems and circuits and is the companion reference for piping plans. See our API 574 page and piping circuit and CML inspection service.

Piping plans also have special locations that vessel plans rarely need. These include injection points and mix points, deadlegs, soil-to-air interfaces, small-bore and auxiliary piping, and locations susceptible to CUI. Each needs its own extent and technique, because general circuit readings will not show what is happening there. Our injection point inspection guide shows what that looks like for one of the most demanding of these locations.

Keeping the plan alive: MOC, IOWs, findings and deferrals

Direct answer: A plan must change when the equipment's damage picture changes. API 510 makes the inspection group part of the MOC approval process when integrity may be affected. It also expects operations staff to tell the inspector about operation outside IOWs, feed changes, failures and unusual conditions. Inspection findings and deferrals must also be written back into the plan.

The current API 510 sets out four routes by which new information should reach the plan:

• Management of change: the inspection group takes part in approving changes that may affect integrity, so it can foresee new damage and update the plan and records.
• Integrity operating windows: deviations from IOW limits, and changing trends within them, should be brought to inspection or engineering staff. They then decide whether to modify the plan or create a new one, depending on how serious the exceedance is.
• Notification by other personnel: operations, maintenance and engineering staff must tell the inspector about MOC actions, operation outside IOWs, feedstock changes, failures and repairs, cleaning methods, experience at other plants, unusual conditions such as leaks or vibration, and engineering evaluations that require future action.
• Incident investigations and the CCD: lessons from pressure-equipment incidents and near-misses (API RP 585) and revisions to the CCD (API RP 970) feed back into the plan.

Deferrals are the other trigger. API 510 (11th edition) says equipment may not run past its due date without a valid deferral. It allows a simplified short-term deferral under tight conditions: no earlier deferral, a limited extension, a documented review, and consent from the inspector and operations management. Anything else needs a documented deferral process that includes a risk assessment. Either way, the new due date and its basis belong in the plan. Turnaround slippage is the usual cause. The turnaround inspection planning guide covers how plan due dates become shutdown scope.

Regulatory overlay: OSHA PSM, state jurisdictions and Canada

Direct answer: In the USA, OSHA PSM (29 CFR 1910.119(j)) requires inspection and testing that follows recognized and generally accepted good engineering practice (RAGAGEP), at a frequency consistent with that practice and prior operating experience. API 510 and API 570 are the usual RAGAGEP for vessels and piping, so the inspection plan is the evidence of that frequency. In Alberta, ABSA's AB-506 sets its own plan requirements.

OSHA's mechanical integrity element requires each inspection or test to be documented with the date, the name of the person who performed it, the equipment identifier, a description of the work and the result. It also requires deficiencies outside acceptable limits to be corrected before further use, or in a safe and timely manner. The plan defines what will be done and when. The PSM record proves it was done. Investigators compare the two, which is why the plan's equipment identifiers must match the identifiers on NDE reports. Our OSHA PSM 1910.119 page covers this in more depth. EPA's Risk Management Program has a parallel mechanical integrity requirement at Program 3 facilities.

State boiler and pressure vessel laws add their own layer. Many states adopt the National Board Inspection Code (NBIC) for in-service inspection. Some also recognize owner-user inspection organizations working under API 510. Requirements vary by state, so confirm with your jurisdiction which code governs in-service inspection, and who may inspect, before you treat an API 510 plan as meeting the legal requirement.

Canada note. In Alberta, ABSA's AB-506 (Edition 4, Revision 0, issued October 2025) requires inspection plans for all pressure equipment under an integrity management system. The listed contents include credible damage mechanisms, primary degradation areas and rates, type and extent of NDE, protective devices and safety-critical equipment, cyclic service, corrosion and process-variable monitoring, preparation, and intervals with next due dates. AB-506 also requires plans to be finalized and validated within 12 months of the installation inspection, and approved and endorsed by an In-service Inspector (ISI). Other provinces, including Ontario under TSSA and British Columbia, have their own regimes. Confirm with the provincial regulator.

Common mistakes that show up in audits

Direct answer: The recurring faults are generic plans that were never site-specific, techniques that cannot detect the assigned damage mechanism, CML locations with no sketch, no record of the corrosion specialist's input, plans not updated after MOCs or IOW exceedances, missing relief devices, and undocumented deferrals.

• Generic plan never tailored. The codes allow a generic start but expect enough detail to direct the inspector to every area of concern. A vessel plan that reads like every other vessel plan in the unit is a red flag.
• Technique-mechanism mismatch. Thickness readings assigned to a cracking mechanism, or spot UT assigned to pitting. The code's probability-of-detection input exists to prevent this.
• No traceable damage mechanism basis. No CCD reference, no named corrosion specialist, no date.
• Locations without geometry. CML numbers that cannot be found in the field, so readings drift between surveys and corrosion rates become noise.
• Static plans. No revision after a feed change, an MOC or an IOW exceedance, even though both codes require review and amendment.
• Undocumented deviations and deferrals. Field crews skip inaccessible CMLs, or due dates slip at turnaround, with no approval recorded.

If you are building or reviewing the owner-side programme, our guide to the owner-user inspection organization covers the structure around the plan.

How Atlantis supports this

Atlantis NDT performs the NDE that your inspection plan specifies. That includes UT thickness and CML surveys, corrosion mapping, PAUT, TOFD, MT, PT, VT, ET and radiography through crews licensed where the work is done. Technicians are certified under an ASNT SNT-TC-1A written practice, with ASNT Level III oversight of procedures and technique selection. We report data keyed to your equipment and CML identifiers so it can be trended against previous surveys. Your API-certified Authorized Inspector develops and owns the plan, evaluates and accepts the results, and remains inspector of record. Atlantis does not write inspection plans as an Authorized Inspection Agency, set intervals, or perform RBI or fitness-for-service assessments. See pressure vessel inspection services and piping circuit and CML inspection. Send us your plan's NDE scope and we will return a quote within 24 hours.

Frequently asked questions

What are the minimum contents of an inspection plan under API 510?

The plan must contain the tasks and schedule needed to monitor damage mechanisms. It should define the inspection types, the next date for each, the inspection and NDE techniques, the extent and locations, surface cleaning, any pressure test, previously planned repairs, and considerations from MOCs, IOW exceedances and other deviations since the last inspection. Check the wording in your licensed copy of the 11th edition.

What does API 570 require in a piping inspection plan?

The same core items, framed around circuits and CMLs, plus the damage types anticipated or found, where the damage is expected, and any special access or preparation. The plan should be built on systemization and circuitization of the piping. Confirm the current list in the 5th edition (2024).

Who develops the inspection plan under API 510?

The inspector and/or engineer, with a corrosion specialist consulted on credible damage mechanisms and susceptible locations. The plan sits within the owner-operator's QA inspection/repair management system.

How often must an inspection plan be reviewed?

The codes do not set a calendar period. They require plans to be reviewed and amended as needed. In practice that means after inspections, MOCs, IOW exceedances, failures, or changes in corrosion rate or damage mechanism. Many owners also review plans on a fixed cycle.

Does an NDE technician need API 510 certification to execute the plan?

No. API 510 says the examiner does not need API inspector certification. The examiner must be trained and competent in the procedures used, and the owner may require certification such as ASNT SNT-TC-1A or CP-189. The inspector evaluates and accepts all NDE results.

Where do IOW exceedances fit in the inspection plan?

They are an input to scheduling and, in API 510 11th edition, a minimum plan item. Exceedances should be reported to inspection or engineering staff, who decide whether the plan needs changing. See our API RP 584 page.

What must the plan say for an on-stream inspection in lieu of internal?

API 510 requires the type and extent of NDE to be specified in the plan. The inspector must also have enough access to all parts of the vessel to assess its condition. The substitution is at the inspector's discretion, under conditions set in the code.

Are inspection plans required under OSHA PSM?

PSM does not use the term "inspection plan". It requires inspection and testing that follows RAGAGEP at an appropriate frequency, with documented results. Where API 510 or API 570 is your RAGAGEP, its plan requirement becomes part of how you show compliance.

Ready to execute the NDE in your plan? Request a quote for vessel NDE or ask about a piping CML survey. For in-house technicians, see our ASNT Level II training.