What a refinery operator audits before your crew reaches the gate

The first hour of a contractor audit never touches a flaw

An operator's contractor audit at a Gulf Coast refinery starts at a table, not on a scaffold. The auditor asks for the written practice, the technician roster for the job, the certification file behind three names picked off that roster, and the procedure the crew will run. Nothing in that sequence tests whether your Level II can size a crack. It tests whether the employer can produce, on demand, the documents that make the crew's results defensible six years later during a fitness-for-service review.

Findings concentrate in the same four records across almost every audit: a written practice that names no responsible Level III, on-the-job training hours asserted but never logged, near-vision examinations that lapsed, and examination papers destroyed after grading. None of those is a technical failure. All of them are disqualifying, because the operator cannot then show its own insurer, its jurisdiction or a future incident investigator that the numbers in its inspection history came from qualified people.

The consequence lands at the gate. A contractor removed from an approved vendor list mid-turnaround does not get reinstated before the unit comes back up, and the operator absorbs the schedule loss by extending the outage. Building the records pack is a two-week exercise done once and maintained. Rebuilding it under audit pressure, with technicians already on site burning per diem and a critical path slipping, is a different job entirely.

Where the Level III's authority stops in the API world

An API 510, 570 or 653 authorized inspector is certified by API's Individual Certification Programs. Your Level III does not certify them, cannot certify them, and gains nothing by implying otherwise in a proposal. What the Level III owns is the NDT personnel side: the written practice, the training and experience requirements, the examinations, and the certification decisions for Level I, II and III technicians under that employer. The boundary is set out in full on our page covering what an outside Level III can and cannot do.

API 570 draws the same line from the other direction. The NDE examiner need not be qualified in accordance with API 570, and need not be an employee of the owner or user, but must be trained and qualified in the applicable procedures. The examiner's employer maintains the certification records and makes them available to the inspector. That single provision is what converts your internal filing habits into a contractual deliverable on every piping job.

Atlantis does not deliver API 510, 570 or 653 inspector training, and says so in the first meeting. The work we take is upstream of that: the written practice, the method procedures, the examination bank, the certification files and the audit representation that let your examiners stand behind the readings an API inspector then interprets. Keeping that boundary explicit is itself a piece of audit protection, because a contractor who blurs it invites scrutiny of everything else in the file.

The examiner file the authorized inspector asks for on the deck

A defensible examiner file is short and complete: the certification record itself, the education and training evidence behind it, the signed experience log, the current near-vision and colour results, the graded examination papers, and the Level III signature that issued the certification. Six items. An auditor who receives all six for the first name asked usually stops asking, because the sample tells him the system works. An auditor who receives three of six for the first name will work through the entire roster.

The recurring structural failure is location. Certification files sit in a head office HR folder while the technician works a plant two time zones away, and the site copy is a laminated wallet card with a name, a level and an expiry date. The wallet card proves nothing. API's requirement is that records be available to the inspector, and an inspector on a deck at 06:00 during a turnaround does not accept a promise to email something after the weekend.

The fix is a controlled field pack, issued per job and per technician, carrying the six items in a fixed order with a revision date on the cover. It is regenerated when the roster changes, which during a turnaround means daily. Building that pack is mechanical once the underlying records exist. It exposes, ruthlessly and early, every technician whose file has a hole in it, which is the point.

Vision, hours and examination papers decide most audits

SNT-TC-1A sets an annual near-vision examination, Jaeger No. 1 or equivalent read at not less than 12 inches in at least one eye with natural or corrected vision, and colour contrast differentiation at initial certification and at five-year intervals thereafter. The failure is never the test. It is the calendar. A roster of forty technicians hired at different dates produces forty separate annual due dates, and without a tracker two or three lapse every quarter while their certificates read as current.

Experience hours are the second cluster. Table 6.3.1A of SNT-TC-1A sets minimum training and experience hours per method and level, and the note structure makes those minimums binding on the employer's programme. Auditors ask for the log, not the total. A certificate stating 2,400 hours of ultrasonic experience with no dated log behind it, no supervisor signature and no method breakdown is treated as an unsupported assertion, and the certification falls with it.

Examination papers are the third. SNT-TC-1A requires in-house certification examination questions to be approved by the NDT Level III, and prohibits an examination being administered by the candidate or by a subordinate of the candidate. Both provisions generate records: an approved question bank with a revision history, and an administration record naming who invigilated. Employers keep the score and shred the paper. Our page on exam authorship and retention sets out what an examination file must contain to survive a challenge years later.

Turnaround mobilisation: the records gate before the gate

A refinery turnaround compresses a year of inspection into weeks, and it compresses the records problem with it. Headcount triples, agency travellers arrive on 48 hours notice, three subcontractors run methods you do not directly employ, and the operator's contractor coordinator issues badges against a list you supplied under time pressure. Every one of those conditions creates a certification file that nobody has read.

Agency and traveller technicians carry a specific trap. SNT-TC-1A treats employer certification as revoked on termination of employment where the individual does not hold third-party certification. A traveller who was certified by a previous employer arrives at your gate holding a card that no longer certifies anything under your written practice. The individual may be excellent. The record is void, and an auditor sampling the roster will find it faster than you will.

The countermeasure is a mobilisation gate run seventy-two hours before the first badge: roster locked, each name matched to a complete file, vision dates checked against the outage end date rather than the start date, subcontractor written practices collected and reviewed, and instrument calibration certificates pulled for the specific serial numbers being shipped. Names that fail the gate do not get badged. That single rule is worth more than any amount of on-site remediation.

Corrosion under insulation is a technique decision that must be written down

CUI is the mechanism most likely to expose a scope written without a damage-mechanism basis. API RP 583 addresses corrosion under insulation and fireproofing directly, API RP 571 describes the mechanism and its susceptible temperature ranges, and API 570 drives the extent of CUI examination through class and insulation condition. The scope line that fails an audit reads "UT thickness survey, insulated lines" and stops there.

What an operator wants recorded is the reasoning: which circuits sit in the susceptible temperature band, where water ingress is credible at supports, penetrations, terminations and damaged jacketing, and why the chosen technique detects wall loss at those specific locations. Profile radiography, pulsed eddy current and guided wave each answer a different question, and each has a stated limitation. A record that names the technique without naming the mechanism it targets is not an inspection plan.

The same logic governs data capture. Readings must land on identified condition monitoring locations so the operator can trend them into a corrosion rate and set the next interval within the maxima in API 570's interval table. A campaign that produces a thousand readings and no CML identifiers has generated cost, exposure and no integrity information. This is the most common commercially fatal defect in contractor-supplied piping data.

Radiography on a live unit: the licence file the operator opens

Industrial radiography is regulated separately from every other method on a US site, and operators audit it separately. 10 CFR 34.43 requires radiographers to be trained in specified topics, complete a minimum period of on-the-job training, and receive verification that they can work independently as a radiographer, with understanding demonstrated through a written or oral examination. Certification is not a matter of the employer's written practice alone.

10 CFR 34.79 then fixes what must be kept and for how long: training records for each radiographer and assistant retained three years after the record is made, certification documents and verification of certification status, copies of written tests, dates of oral and practical examinations, the names of those conducting and receiving them, annual refresher safety training with topics, dates and instructors, and semi-annual inspections of job performance.

Two defects recur. The first is subcontracted RT: the shots are logged under your job number while the radiographer's records sit with an agency you never audited. The second is night shift, where source utilisation logs and survey records are signed by whoever was awake rather than the certified radiographer named on the permit. Both are visible in a records review inside ten minutes, and both reach the operator's radiation safety officer rather than its inspection group.

What outsourced Level III cover looks like on a US oil and gas contract

A retained Level III for an oil and gas contractor carries a defined list: authorship and annual review of the written practice, approval of every method procedure against ASME Section V and the applicable construction code, authorship and control of the examination bank, review and signature of certification decisions, technical judgement on technique selection against API RP 571 mechanisms, and attendance at operator audits as the technical authority. Our outsourced Level III scope and retainer page sets out how that is structured.

The retained model exists because the alternative is worse in both directions. A contractor employing a full-time Level III in each of five methods carries a cost base its bid rates cannot support. A contractor with no Level III at all fails the first record an operator asks for. A retainer buys the signature, the responsibility and the availability without buying the headcount, and it survives audit precisely because the responsibility is named and documented rather than implied.

Aerospace and defence work runs on a different rulebook, and mixing them in one written practice is a reliable way to fail both. If your business also holds Nadcap accreditation, the AC7114 audit readiness page covers that checklist separately, and the NAS 410 responsible Level 3 page covers the aerospace role. For a purely oil and gas contractor, keep the written practice single-purpose and keep it approved.

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