The Written Practice Is the Only Certificate That Matters Offshore

Recommended practice, standard or contract: decide which one binds you

SNT-TC-1A is published by ASNT as a recommended practice. Its recurring verb is "should". It binds nobody until an employer adopts it inside a written practice, at which point the employer's own wording becomes the auditable requirement. ANSI/ASNT CP-189 is a different animal: written in mandatory language, it sets minimum requirements rather than guidelines and constrains what an employer is free to write. Choosing between them is the first decision on any upstream or offshore programme, and in practice the choice is made by the client contract rather than by the QA manager.

Gulf of Mexico operators and drilling contractors increasingly specify CP-189 outright, or specify SNT-TC-1A and then bolt on a supplement that imports CP-189 behaviour: central certification for Level III, fixed experience floors with no employer discretion, and tight limits on restricted or limited certifications. Non-US flag units and class-surveyed floating systems bring ISO 9712 into the same programme through ABS, DNV or Lloyd's rules. A service company running work across a fleet can end up owing three certification regimes simultaneously, and a practice that acknowledges only one of them fails the first fleet-wide audit it meets.

The document must therefore state which standard it implements, which edition, and how a conflict with a client supplement is resolved. "Latest edition" is not an answer, it is a finding. Editions change experience tables and examination rules, and an auditor holding a certificate written under one edition against a contract that names another will raise the nonconformance whether or not the technician is competent. Name the edition, date the adoption, keep superseded revisions on file, and write a conflict clause that says the more stringent requirement governs.

What the document must actually contain

At minimum: scope and the organisational structure showing who reports to the Level III; every method and every level the company actually uses, including limited or restricted certifications named explicitly; training requirements by level and method with the topical outlines identified; experience requirements expressed in hours with a stated method of accrual; examination requirements covering general, specific and practical parts; grading rules; physical requirements; certification, recertification and interrupted-service provisions; records; and the approval signature. Anything the company does in the field and does not appear in that list is unauthorised work by definition.

The examination section is where most practices are thinnest and where auditors spend the most time. It has to describe how questions are drawn, how the banks are secured, who may proctor, how the practical examination is set up, what specimens are used, and how the practical is scored. A practical examination with no retained specimen record, no answer key and no scoring sheet cannot be re-verified, so it is treated as not having happened. Composite grading is a second trap: the practice must state the composite rule and how the parts are weighted, and the arithmetic in the files has to match it exactly.

The administrative clauses carry the same weight as the technical ones. Vision requirements need a stated acuity criterion, a colour-contrast criterion, an interval and an examiner definition. Recertification needs an interval per level and a stated basis, whether by examination, by documented technical performance evaluation, or by a combination. Interrupted service needs a threshold expressed in consecutive days, not a vague reference to a break in employment. Records retention needs a period defined against the asset, not against convenience. Revision control needs a numbered revision block and a distribution list.

Who owns the document, and whose signature carries it

The employer owns the written practice and the employer certifies its own personnel. That is not a formality. It means the company, not the consultant, holds the liability for a certificate, and it means the document must be issued under the company's controlled document system with an authorised signature. The Level III is the technical authority who develops the practice, approves it, approves the procedures written beneath it, and administers and grades the examinations, but the Level III does not own the certificates.

Three roles are constantly conflated in upstream work and an auditor will separate them in the first ten minutes. The API 510, 570 or 653 inspector authorises and signs the in-service inspection of the equipment. The NDT technician is certified under the employer's written practice to SNT-TC-1A or CP-189 and performs the examination. The ASNT Level III approves the procedures the technician works to and the practice under which the technician was certified. A written practice that blurs these, for example by implying the Level III accepts the equipment, invites a finding on the first page.

The basis of the Level III's own certification matters more offshore than anywhere else. SNT-TC-1A permits an employer-certified Level III. Most Gulf of Mexico operator supplements do not: they require certification by examination in the specific method. A Level III certified in radiography and ultrasonics who signs penetrant and magnetic particle procedures is outside their method authority, and every procedure signed after a lapsed certification date is open to challenge. Track the Level III's expiry as rigorously as the technicians'.

How an auditor actually samples it

No auditor reads a written practice cover to cover on site. They read the approval block, the methods list and the experience table, then they stop and pull files. Five technicians is the usual sample, chosen to include at least one recent certification, one recertification and one subcontractor. From each certificate they work backward through a chain: certificate, examination records, training records, experience log, vision record, and finally the revision of the practice in force on the certification date.

Any break in that chain is the finding, and the most common break is the last link. Companies keep excellent training and examination records and keep no record of which revision applied. The auditor then cannot confirm the experience hours were sufficient under the rules that governed at the time, and writes it up as an unverifiable certification. The fix costs nothing at issue and is expensive to reconstruct three years later, when the training vendor has changed hands and the supervisor who signed the experience log has left.

The second most common break is arithmetic. Experience hours are logged as a total and never broken out by method, so the auditor cannot see whether the method minimum was met. Or training hours are quietly credited toward experience. Or a degree-based reduction is applied to the method-specific minimum when the practice only allows it against the total. None of these are technical failures. All of them void certificates when a client's third-party auditor recalculates the table in front of you.

The drift that makes a good practice fail two years later

Revision drift is the first and worst. The practice is revised, usually to close a previous audit finding, and the certification templates are not updated. Certificates continue to issue against superseded rules for months. Nobody notices because nothing in the field changes. The fix is procedural: the revision block must trigger a re-issue of the certification forms and a documented review of every certificate issued since the last revision.

Scope drift is the second. A client asks for a technique the practice never contemplated, a supervisor says yes because the crew is on the platform, and reports start coming back with a method or technique in the header that appears nowhere in the certification programme. Phased array and time-of-flight diffraction are the usual culprits under a plain ultrasonic certificate. Once the report exists, so does the exposure, and the client's own document control will surface it long after demobilisation.

Agency drift is the third and it is specific to offshore staffing. Peak work forces subcontracting, subcontract crews arrive certified under a different employer's written practice, and the agreement that was supposed to define oversight either does not exist or was signed once and never audited. Your practice has to define how agencies are qualified, what evidence you hold on their technicians, and at what frequency you audit them. Then you have to actually run the audit, because the evidence of the audit is what the operator asks for.

BSEE, SEMS and what "adequate" means in the Gulf of Mexico

Offshore work on the US outer continental shelf sits under BSEE regulation at 30 CFR Part 250. The Safety and Environmental Management Systems requirements, which grew out of API RP 75, oblige an operator to run a documented management system covering, among other elements, mechanical integrity and contractor selection and oversight. There is no BSEE rule that names your written practice. The rule reaches you through the operator, because the operator has to demonstrate documented criteria for choosing contractors and documented verification that those contractors work to defined programmes.

That indirect route is what makes offshore audits feel different from onshore ones. Onshore, a refinery audits your NDT programme because its own quality system says to. Offshore, an operator audits it because its regulator will audit the operator's contractor management, and a gap in your document becomes a gap in their system. The practical consequences are short notice for record production, requests for records long after a project closes, and a low tolerance for "the person who had those files has left".

"Adequate" therefore is not defined by ASNT in this environment. It is defined by whichever operator's supplement you have signed, read against the SEMS element it supports. Two operators on adjacent blocks can hold you to different experience floors and different Level III certification bases for the same work. The written practice has to be built so that a supplement can be satisfied without rewriting the base document each time, usually by writing the base document to the more stringent regime and mapping supplements to it in a controlled annex.

Structural, subsea and pipeline scope each pull a different requirement into the same practice

Offshore structural examination brings API RP 2X and API RP 2A-WSD into the programme. Tubular T, Y and K joints are a geometry problem before they are a certification problem: the local dihedral angle changes around the intersection, so the ultrasonic technique and the operator's ability to apply it change too. A practice that certifies to a generic weld-examination outline and says nothing about node examination leaves your Level III approving procedures for work the certification programme never trained anyone to do.

Pipeline scope brings a separate acceptance regime. API 1104 governs the welding and examination of pipelines and related facilities, and PHMSA regulations at 49 CFR Parts 192 and 195 govern transmission and hazardous liquid lines that come ashore or move gas between facilities. Acceptance criteria differ from ASME criteria, and the interpretation training a radiographer needs differs accordingly. The practice must state which acceptance standards personnel are trained and examined against, method by method, not merely which methods they hold.

Class and flag requirements are the third pull. Mobile offshore drilling units and floating production systems are surveyed by a classification society, and class rules commonly expect ISO 9712 certification, which is third-party rather than employer-based and cannot be satisfied by your written practice at all. Where both regimes touch the same fleet, the practice should state plainly which scopes are covered by employer certification and which require third-party certificates that the company merely verifies and files.

Vision, hitches and the arithmetic that catches rotational crews

Near-vision acuity and colour-contrast differentiation are usually the least technical clauses in the document and the most frequently breached offshore. The mechanism is banal: the annual due date falls on day four of a twenty-one day hitch, the technician is on a platform, and there is no mechanism to stop work. Reports issued in that window are technically produced by an uncertified examiner. Build the reminder into the mobilisation checklist rather than the annual calendar, and require the vision record to be current through the end of the scheduled rotation, not merely current on the day of departure.

Interrupted service is the second rotational trap. Upstream work is lumpy; crews demobilise between campaigns and sometimes sit for months. If the practice defines a break threshold in consecutive days without work in the method, someone has to count the days, and the payroll system is usually the only place that data exists. Write the clause so that the trigger is checkable from records the company already keeps, and define what re-entry requires: a practical re-demonstration is defensible, an informal chat with the supervisor is not.

The experience arithmetic deserves a standing check. Three errors recur. Hours worked across several methods are credited in full to each method rather than apportioned. Classroom training hours are added to the experience ledger. And an academic reduction permitted against total NDT experience is applied to a method-specific minimum instead. Each of these produces a certificate that looks correct and collapses when an auditor recomputes the table. A monthly reconciliation of the experience ledger against timesheets removes all three permanently.

How Atlantis develops and maintains the document

We write the written practice against the standard your contracts actually require, map every client supplement to it in a controlled annex, and rebuild the certification file structure so that each certificate carries its governing revision on its face. Where an existing practice is sound, we amend rather than replace, so historic certificates stay traceable. Procedures are then written or requalified beneath the practice to ASME Section V and the relevant API or AWS acceptance standard, and approved by a named Level III in the specific method.

The engagement continues past issue, because the failures described above are all maintenance failures. We run the annual practice review, re-verify the certificate population after every revision, audit outside agencies to the frequency the practice states, maintain examination banks and practical specimen records, and attend operator audits to answer technical questions on the record. Where an audit finding lands, we write the corrective action against the clause that failed rather than against the symptom.

We supply NDT technical authority and nothing beyond it. We are not your process safety management auditor, we do not act as the API inspector of record, and we do not sign the in-service inspection. What we do sign is the written practice, the procedures, and the examination and certification recommendations underneath them, and we stand behind those in front of your client. Request a consultation and we will start by reading the practice you already have.

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