Turnaround Inspection Planning 2026 — Shutdown Scope + Schedule Decoded

Scoping NDE before the shutdown: the short answer

Turnaround NDE scope comes from the owner's inspection plans. Pull every item whose inspection due date falls before the next planned window. Run on-stream NDE in the months before shutdown so that known conditions are not treated as discovery work. For each item that must be opened, write down the technique, extent, surface preparation, access and acceptance owner. Then staff qualified examiners against that list and agree how results will reach the inspector for disposition each day.

This section covers the NDE side of turnaround planning: how inspection-plan due dates become a worklist, what on-stream inspection can and cannot replace, how to specify each examination so it can be priced and executed, and how results flow back into the plan afterwards. Code references are to API 510 (11th edition, 2022), API 570 (current 5th edition, 2024) and OSHA 29 CFR 1910.119. Confirm details against your licensed copies and your jurisdiction. Interval and scope decisions belong to the owner's inspector and engineer, not to the NDE contractor.

From inspection-plan due dates to the turnaround worklist

Direct answer: The worklist starts with every item whose internal, on-stream or thickness inspection falls due before the next window. That date is set by the owner's inspection plan under API 510 or API 570. Items that cannot wait need to be in this outage. Items that could wait need a documented deferral. Items that can be inspected on-stream may leave the outage scope altogether.

Under API 510 (11th edition), unless an RBI assessment justifies otherwise, the period between internal or on-stream inspections must not exceed the lesser of half the remaining life or 10 years. The external visual interval is the lesser of five years or the internal/on-stream interval. API 570 sets piping intervals by service class and remaining life. So the first planning task is arithmetic. Compare each item's due date with the planned shutdown date and with the date of the shutdown after that. An item due eighteen months after this turnaround but two years before the next one is due in this turnaround.

That arithmetic depends on the inspection plan being current. API 510 and API 570 both require plans to be reviewed and amended as needed. API 510 now lists operating deviations, MOCs and integrity operating window (IOW) exceedances among the minimum plan contents. Before freezing the NDE list, check whether any unit has had IOW exceedances, feed changes or MOCs since the last inspection. Those circuits may need wider coverage or a different technique, not just the same readings repeated. See our guide to what an API 510 / API 570 inspection plan must contain and our API RP 584 integrity operating windows page.

Turnaround dates slip, so deferrals are part of planning. API 510 (11th edition) says equipment may not run past its due date without a valid deferral. A simplified deferral is allowed only under tight conditions: it must be the first deferral, the extension must be limited, the operating history must have been reviewed, and both the inspector and operations management must consent. Any other deferral needs a documented process that includes a risk assessment. If the turnaround moves, every item on the due list needs a valid deferral, or must be inspected on-stream, before the original date passes. Write that check into the schedule-change procedure. If you leave it to memory, it gets missed.

Pre-turnaround on-stream NDE: shrinking the discovery list

Direct answer: On-stream NDE in the 6 to 18 months before shutdown tells you which items will need repair while there is still time to order material and plan the work. It cannot replace every internal inspection. API 510 limits when on-stream inspection can stand in for an internal one, and external techniques have real limits in finding internal damage.

Most turnaround overruns start when work found during the outage was not in the plan. Some of that discovery is unavoidable: you cannot see inside a reactor until it is open. But much of it involves conditions that could have been measured from outside months earlier. Examples include wall loss in piping circuits, localized thinning at vessel nozzles, CUI on insulated lines and erosion at elbows downstream of control valves. Measuring these on-stream turns them from discovery into planned work with material on order.

Typical pre-turnaround on-stream techniques include:

• UT thickness surveys at CMLs to update corrosion rates, so remaining-life calculations reflect current conditions rather than the last turnaround's data.
• Corrosion mapping and PAUT over areas where spot readings showed localized loss, to size the area and depth of thinning for engineering assessment and repair planning.
• Profile radiography on insulated small-bore piping, to look for wall loss and deposits without removing insulation. See our profile radiography guide.
• Guided-wave screening on long runs and inaccessible sections, to prioritize where follow-up UT is needed. Guided wave is a screening tool, not a thickness measurement.
• Pulsed eddy current for CUI screening through insulation, with follow-up on indications.
• TOFD and PAUT weld examinations where cracking mechanisms are suspected and the geometry and temperature allow external examination.

API 510 (11th edition) allows the inspector, at their discretion, to substitute an on-stream inspection for an internal one. This applies when entry is physically impossible, or when every one of a defined set of conditions is met. The conditions include a low and known general corrosion rate, remaining life above 10 years, an established service history, no questionable external findings, operation below the creep range, no environmental cracking or hydrogen damage, and no non-integrally bonded liner. An RBI assessment can provide an alternative route. When on-stream inspection is used, the code requires the type and extent of NDE to be specified in the inspection plan. The inspector also needs enough access to assess the heads, shell and nozzles.

The code also lists factors that limit what external NDE can find. These include the alloy, product form, welds, nozzles and reinforcing pads, internal attachments, linings or cladding, access and metal temperature, the technique's own limits, and surface condition. Treat that list as a checklist for each on-stream substitution. If a vessel has internal cladding or attachments where damage is expected, external UT will not see it. That vessel stays in the outage scope.

Specifying each examination so it can be priced and executed

Direct answer: For every item on the frozen list, the NDE line should name the damage mechanism, technique, procedure, locations and extent, surface preparation, access, temperature limits, examiner qualification, and who accepts the result. Vague lines such as "UT as required" are where contractors price contingency and where field crews make choices the inspector later disputes.

This table describes typical practice. It is not a substitute for the unit's corrosion control document and the inspector's plan. The point is the right-hand column: every examination needs those details settled before the contractor prices it. Our NDE method selection by damage mechanism guide covers the technique choices in more detail.

Acceptance criteria and disposition authority are often left implicit. Under API 510, the examiner performs NDE to the job requirements and procedures, and the inspector evaluates and accepts all NDE results. The work order should say which code or owner standard the examiner reports against, which indications are to be reported (for example, all thickness readings below a stated value, or all linear indications), and who receives them. The contractor reports. The owner's inspector decides.

Access, surface preparation and sequencing

Direct answer: More NDE time is lost to access, cleaning and permits than to the examinations themselves. Tie every examination point to a scaffold, insulation-removal and cleaning requirement in the planning tool, and sequence radiography around other work so that exclusion zones do not stop the job.

Surface preparation is a code-level planning item. Both API 510 and API 570 list cleaning requirements among the inspection plan contents. In the field, this means the work order should state the cleaning standard for each technique. WFMT on welds in cracking service needs a much cleaner surface than spot UT through sound coating. Corrosion mapping needs a surface the probe can track. Tube ET needs clean tubes. If cleaning is under-specified, the examiner either rejects the surface and waits, or examines a poor surface and reports reduced sensitivity. Both outcomes cost schedule.

Radiography needs its own sequencing. Industrial radiography with gamma sources requires a licence from the NRC or, in Agreement States, the state radiation control programme. It also requires controlled exclusion zones. On a crowded turnaround site, radiography is usually scheduled on nights or in planned windows. Profile RT that can be done on-stream before the outage takes pressure off that schedule. Confirm with your contractor that the radiography crew is licensed where the work is done and that source logistics are planned.

Crew qualification and the documents to check before mobilisation

Direct answer: Every examiner must be qualified for the method and technique assigned, under the employer's written practice and any owner requirements. Certifications must be valid through the last day of the window. Procedures need owner approval before mobilisation, and Level III review of technique procedures should be finished before the scope is frozen.

API 510 says NDE examiners do not need API inspector certification. They must be trained and competent in the procedures used, and owners may require certifications such as ASNT SNT-TC-1A or CP-189. The examiner's employer keeps the certification records, and the inspector checks that examiners are qualified. Many owners add their own requirements for specific techniques. For example, some require API's ultrasonic examiner performance qualifications for UT flaw detection, sizing or thickness work. Read the owner's specification early. A crew sized on SNT-TC-1A Level II technicians alone may not meet it.

Check these documents before mobilisation:

• The written practice under which the technicians are certified, and certification records showing method, level and expiry dates.
• Eye examination records current through the window.
• NDE procedures for each technique, reviewed by a Level III and approved by the owner, with technique sheets for PAUT and TOFD where used.
• Instrument and probe calibration certificates, and reference blocks representative of the materials and thicknesses.
• Radiography licence, source documentation and radiation safety programme, where RT is in scope.
• Reporting templates that use the owner's equipment and CML identifiers.

For the contractor-side view of these checks, see what a US refinery turnaround demands from an NDT contractor. For the owner-side scope build, see building a refinery turnaround inspection scope.

Reporting during the outage so findings reach disposition

Direct answer: Report daily, by equipment and location, in a format the inspector can act on. OSHA PSM requires each inspection or test record to show the date, the performer, the equipment identifier, a description of the inspection and the result. Build those fields into every NDE report from day one.

Under 29 CFR 1910.119(j)(4)(iv), each inspection and test on covered equipment must be documented with those five items. Under (j)(4)(iii), inspection frequency must be consistent with manufacturers' recommendations and good engineering practice, and more frequent where prior operating experience calls for it. Under (j)(5), deficiencies outside acceptable limits must be corrected before further use, or in a safe and timely manner while safe operation is assured. Report daily by equipment tag and CML or weld identifier, flag readings that meet the owner's reporting threshold in the daily summary, record any location that could not be examined as a deviation for the inspector to approve, and close every report, including re-examinations after repair, before demobilisation.

After the shutdown: closing the loop into the inspection plan

Direct answer: The turnaround is not finished until the results are back in the inspection plans. That means updated corrosion rates and remaining life, new next-due dates, CMLs added where damage was found, technique changes where the old one missed something, and records of every deferral and deviation.

The data collected in the outage drives the next cycle's due list. If thickness data is not entered against the right CMLs, the next corrosion-rate calculation will be wrong. If new damage was found outside existing CMLs, the plan needs new CMLs or a wider scanning scope. If a technique could not detect what the inspector expected, the plan needs a different technique. API 510 and API 570 both require plans to be reviewed and amended when new information about damage or deterioration rates comes in, and a turnaround produces more of that information than anything else. Our long-term and short-term corrosion rate guide explains the calculations that depend on this data.

Canada note

In Alberta, ABSA's AB-506 (Edition 4, Revision 0, issued October 2025) requires inspection plans for pressure equipment under an owner's integrity management system. The plans must cover damage mechanisms, the type and extent of NDE, preparation for examination, and intervals with next due dates. They must be approved and endorsed by an In-service Inspector (ISI). Turnaround NDE in Alberta, including the oil-sands and Industrial Heartland plants, is planned against those plans. Ontario (TSSA) and other provinces have their own regimes. In every province, confirm which regulator and code apply to the equipment before the scope is frozen. For Canadian personnel certification, NRCan's NDT Certification Body continues to certify technicians. The Canadian General Standards Board itself ceased operations on 1 April 2026; CAN/CGSB-48.9712 remains valid and NRCan's certification services continue.

How Atlantis supports turnaround NDE

Atlantis NDT performs pre-turnaround on-stream NDE and in-outage examinations. This includes UT thickness and CML surveys, corrosion mapping and PAUT, TOFD, MT/WFMT, PT, VT, eddy current tube inspection, MFL tank floor scanning 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 review of procedures and technique selection. Atlantis has supported 1,500+ inspection activities. Your API-certified inspector sets the scope, evaluates the results and remains inspector of record. Atlantis does not set intervals, approve deferrals or perform RBI or fitness-for-service assessments. See our inspection services and phased array inspection services. Send us your turnaround NDE list for a quote.

Turnaround NDE planning: frequently asked questions

How far ahead should turnaround NDE scope be defined?

Early enough to run on-stream surveys and order repair material. Many owners build the inspection due list well over a year before the window, freeze scope several months out, and run pre-turnaround on-stream NDE in between. Your own turnaround milestone procedure governs.

Can on-stream inspection replace an internal inspection during a turnaround?

Sometimes. API 510 allows the inspector to substitute on-stream inspection when entry is impossible, or when a defined set of conditions is met. An RBI assessment can provide an alternative route. The type and extent of NDE must then be specified in the inspection plan.

What happens if the turnaround is postponed past an inspection due date?

Under API 510 (11th edition), the equipment needs a valid documented deferral before it runs past the due date. Otherwise it must be inspected, for example on-stream if the code allows. Simplified deferrals have strict limits. Other deferrals need a documented risk assessment.

What records does OSHA PSM require for turnaround inspections?

For each inspection or test on covered equipment: the date, the person who performed it, the equipment serial number or identifier, a description of the inspection or test, and the results, under 29 CFR 1910.119(j)(4)(iv).

How can we reduce discovery work during the turnaround?

Run on-stream surveys of known damage before shutdown: CML thickness updates, mapping at hot spots, profile RT and CUI screening. Then order material and plan repairs for what you find. Inspect first the items most likely to need repair.

Planning the next outage? Ask about pre-turnaround on-stream NDE or request PAUT and corrosion mapping support for the shutdown. To build in-house capability, see ASNT Level II training.