NDT for Oil & Gas Industry
Expert NDT consulting and training for the oil & gas industry. Pipeline inspection, refinery maintenance, and offshore structure assessment by ASNT Level III professionals. API 510/570/653 compliance, CUI programs, and fitness for service assessment.
Atlantis NDT Integrated Stack
Atlantis NDT delivers an integrated software + services stack to inspection contractors + EPC operators + asset owners globally. Atlantis NDT ERP (NDT reports, technician certificates, procedures, crew dispatch and equipment calibration), Digital Twin platform (3D asset model + damage-mechanism heat-map), Reporting Software (mobile + offline field capture + code-aligned templates), Atlantis NDT LMS + Atlantis NDT Academy (inspector training pathway), 3D Scanning Services, Atlantis AI for NDT, CCS Inspection. Affordable, accessible, fully customizable.
Code Stack + Compliance
Audit-defensible records per ISO 9001:2015 + ISO 17020 (inspection body) + ISO 17025 (calibration lab) + ISO 17024 (personnel cert body). ASME B&PV Sections V + VIII + IX + XI, ASME B31 piping series, API 510 + 570 + 571 + 653 + 936 + 1169, NACE MR0175 + MR0103 sour-service, AMPP CIP coating, IACS Rec-20 marine + offshore. Dual-scheme inspector cert (ASNT NDT Level II/III + ISO 9712). ASNT NDT Level III final disposition + procedure approval on every engagement.
Delivery Model + Free Consultation
Three delivery models: On-site mobilisation across North America, confirmed in your RFQ; Remote procedure authoring + Level III sign-off (24-hour turnaround); Hybrid — local Level II + Atlantis Level III remote oversight. Atlantis NDT publishes no pricing — pricing varies by region, scope, delivery model, team size. Request your free 30-minute consultation with Atlantis NDT founder Anoop Rayavarapu (ASNT NDT Level III multi-method, API 653, ISO 9001 Lead Auditor). Tailored quote within 24 hours. Affordable, accessible, fully customizable.
Frequently Asked Questions
Which NDT methods are used in oil and gas?
Ultrasonic testing and phased array for wall thickness and weld examination; radiography for weld volumetric examination and for profile imaging of small-bore and insulated lines; magnetic particle and liquid penetrant for surface examination; eddy current and IRIS for heat exchanger tubing; guided wave for screening long insulated or buried runs; magnetic flux leakage for tank floors and in-line pipeline inspection; and visual examination throughout, which directs where the others are applied.
What codes govern NDT in oil and gas?
ASME Section V for the examination methods themselves; ASME Section VIII and B31.3 for construction acceptance; API 510 for pressure vessels, API 570 for piping and API 653 for aboveground storage tanks in service; API 1104 for pipeline girth welds; API 579 for fitness-for-service; and API 580/581 for risk-based inspection. API RP 571 defines the damage mechanisms that determine which examination is actually worth performing where.
What damage mechanisms drive inspection planning?
In refining, high-temperature sulfidation, naphthenic acid corrosion, high-temperature hydrogen attack, wet H2S cracking including HIC and SOHIC, chloride stress-corrosion cracking of austenitic stainless, corrosion under insulation, and erosion-corrosion at elbows and reducers. Upstream and midstream add CO2 and microbiologically influenced corrosion, top-of-line corrosion in wet gas, and external corrosion under coating and disbonded wrap.
How are inspection intervals set?
Under API 510, API 570 and API 653 the interval derives from measured corrosion rate and remaining life, subject to code maxima — not from a fixed calendar. That makes the quality of the thickness data decisive: readings that cannot be proven to come from the same corrosion monitoring location cannot support a defensible corrosion rate, and therefore cannot support the interval derived from it.
What qualifications should an oil and gas NDT contractor hold?
Technicians certified per method and level under ASNT SNT-TC-1A or ISO 9712 against a current written practice; inspectors holding API 510, 570 or 653 as the scope requires; ISO 17020 or ISO 17025 accreditation where third-party inspection is performed; and the operator-specific approvals that govern site access, which are separate from and additional to the certification scheme.
Can inspection data feed our integrity management system?
Yes. Results can be delivered as notifications or work orders into SAP PM, Oracle eAM, IBM Maximo or ServiceNow, or bound to locations on a 3D asset model where corrosion rates, remaining life and risk ranking update as new data arrives. The important design decision is that thickness readings attach to a persistent corrosion monitoring location rather than to a report, because that is what makes the time series usable years later.
Related reading
- Turnaround scope is dominated by exchanger work. how exchanger bundles are actually inspected.
Training your own oil & gas inspectors
Companies in this sector increasingly pair contracted inspection with in-house capability — Oil & Gas NDT training covers the methods, the regime and the certification path.
Building and maintaining that certified inspector bench runs through Atlantis NDT training and certification programs.
Oil and gas NDT splits across three code families: fixed equipment inspected to API 510, 570 and 653, pipelines regulated under 49 CFR Parts 192 and 195, and new fabrication built to ASME Section VIII and Section IX. Method selection follows the credible damage mechanism identified in API 571, not inspector preference or habit.
A defensible programme runs in one direction: mechanism, then method, then interval, then acceptance. API 571 names what can credibly damage a given circuit — sulfidation in hot crude service, wet H2S cracking in sour systems, corrosion under insulation anywhere insulated carbon steel sits between roughly -4degC and 175degC, chloride stress corrosion cracking in austenitic stainless. Each mechanism has methods that detect it and methods that cannot: CUI is a profile radiography or pulsed eddy current problem because the damage sits under cladding, so a surface method finds nothing until the insulation comes off. API 510 and 570 then convert measured remaining wall into an interval, capped at one half remaining life, ten years for pressure vessels and five for most piping circuits. United States pipeline work adds a second authority — PHMSA enforces 49 CFR 192 and 195, and integrity management reassessment clocks under those parts run independently of API intervals.
Source: API 510 Pressure Vessel Inspection Code; API 570 Piping Inspection Code; API 653 Tank Inspection, Repair, Alteration and Reconstruction; API RP 571 Damage Mechanisms Affecting Fixed Equipment; API RP 583 Corrosion Under Insulation and Fireproofing; ASME B31.3, B31.4 and B31.8; 49 CFR Parts 192 and 195 (PHMSA); NACE MR0175 / ISO 15156 for sour service.
| Damage mechanism | Where it appears | Method that detects it | Governing reference |
|---|---|---|---|
| Sulfidation | Hot crude and vacuum circuits above roughly 230degC | Ultrasonic thickness on a fixed CML grid, profile radiography at elbows and tees | API RP 571; API 570 |
| Corrosion under insulation | Insulated carbon steel roughly -4degC to 175degC, and cycling service | Profile radiography, pulsed eddy current, targeted insulation removal at drains and penetrations | API RP 583; API 570 |
| Wet H2S cracking (HIC, SOHIC) | Sour service vessels, drums and associated piping | Angle-beam ultrasonics or TFM from the accessible side, wet fluorescent magnetic particle after blasting | API RP 571; NACE MR0175 |
| Chloride stress corrosion cracking | Austenitic stainless under insulation or in chloride-bearing service | Penetrant testing after descaling, eddy current on tubing | API RP 571 |
| Erosion-corrosion | Elbows, tees, letdown valves, slurry and multiphase service | Encoded ultrasonic corrosion mapping (C-scan) rather than spot readings | API 570; API RP 574 |
| Mechanical fatigue | Small-bore connections on vibrating and compressor piping | Magnetic particle or penetrant at the weld toe, paired with a vibration survey | API RP 571; Energy Institute SBC guidance |
| Tank floor soil-side corrosion | Aboveground storage tank bottoms | Magnetic flux leakage floor scan with ultrasonic prove-up of every indication | API 653 |
Why method selection starts with the mechanism, not the method list
The most common way an oil and gas inspection programme fails an audit is not a missed flaw. It is a scope that lists methods without ever stating what those methods are looking for. An auditor reading a data sheet showing ultrasonic thickness readings on an insulated line will ask what that scope was expected to find, because ultrasonic thickness on a CML grid does not detect corrosion under insulation except by luck — the damage is localised at penetrations, supports and drains, and a grid laid out on a drawing will not sit on top of it.
API RP 571 exists to close that gap. It catalogues the mechanisms that credibly affect refinery and production equipment, the materials and temperature ranges each affects, the morphology each produces, and the inspection approaches that find them. Building the scope from 571 forward means the method is chosen because a specific mechanism was judged credible for that circuit, which is the reasoning an auditor is looking for and the reasoning that survives a challenge after a leak.
This matters commercially as well as technically. A mechanism-led scope is usually smaller than a method-led one, because it concentrates coverage where damage is credible instead of spreading it evenly over a circuit for the appearance of thoroughness.
The three regulatory frames a US operator works inside at once
Fixed equipment inside the fence line runs on API inspection codes, which are consensus documents adopted by reference in most state boiler and pressure vessel programmes. API 510 governs pressure vessels, API 570 governs process piping and API 653 governs aboveground storage tanks. Each sets who may perform and certify the inspection, how intervals are calculated, and what constitutes an acceptable repair.
Pipelines are different. Transmission and distribution gas pipelines fall under 49 CFR Part 192 and hazardous liquid pipelines under Part 195, both enforced by PHMSA and, in many states, by a certified state agency acting on PHMSA's behalf. Integrity management under Subpart O of Part 192 requires baseline and periodic reassessment of high consequence areas on clocks defined in the regulation, and those clocks are not the API intervals. An operator holding both regulated pipelines and API-governed plant equipment is running two inspection calendars that intersect only at the fence line.
New construction adds a third frame. Fabrication follows ASME Section VIII for vessels and the relevant B31 book for piping, with welder and procedure qualification under Section IX, and the NDT itself performed to the techniques in ASME Section V. The acceptance criteria, however, always come from the construction code, not from Section V.
What Atlantis does on an oil and gas scope
Atlantis works the Level III end of this: written practice and procedure development against API and ASME requirements, procedure qualification and approval, technique sheets for the specific mechanisms in scope, personnel certification under a compliant SNT-TC-1A or CP-189 written practice, and independent review of contractor data before it becomes the basis for a fitness-for-service decision.
Where a client already has a competent inspection contractor, the useful role is usually adversarial rather than additive — reading the data package as an auditor would, checking that the technique actually addresses the mechanism claimed, and confirming that remaining life arithmetic uses the right thickness basis. That review has caught circuits where corrosion rate was calculated against nominal wall rather than the code minimum, which understates the rate and overstates the interval.
Delivery is remote or on-site depending on the scope. Request a consultation to scope the work against your specific circuits and codes.
Where these programmes most often go wrong
Three failures recur. The first is a corrosion rate computed from two readings taken at nominally the same location by different technicians using different probes — the difference between them is measurement scatter, not metal loss, and it produces either an alarming false rate or a comfortable false one. Encoded corrosion mapping exists precisely to remove this, because the second survey is registered to the first.
The second is treating the CML grid as permanent. Grids drawn at commissioning reflect the process as designed. After a revamp, a feedstock change or a new tie-in, the flow regime moves and the grid no longer sits where the damage is. API 570 expects the circuit definition and CML placement to be revisited when service changes, and that review is frequently skipped.
The third is a written practice that has drifted from what is actually done. When the practice says Level II personnel are qualified by an examination the site no longer administers in that form, every certification issued under it is exposed. This is the cheapest of the three to fix and the most often found.
Which NDT methods are actually used in US oil and gas inspection?
Ultrasonic thickness and encoded corrosion mapping for wall loss, phased array and TFM for crack-like flaws and weld volumetrics, radiography for profile and weld quality, magnetic particle and penetrant for surface-breaking flaws, eddy current and pulsed eddy current for tubing and for screening under insulation, and magnetic flux leakage for tank floors and in-line pipeline runs.
What codes govern NDT for oil and gas fixed equipment?
In service, API 510 for pressure vessels, API 570 for process piping and API 653 for aboveground storage tanks, with API RP 571 supplying the damage mechanism basis. For new fabrication, ASME Section VIII and the applicable B31 piping book set acceptance, ASME Section V sets the examination technique and ASME Section IX governs welder and procedure qualification.
How are inspection intervals actually set under API 510 and API 570?
From measured corrosion rate and remaining wall. Remaining life is the difference between actual thickness and required thickness divided by the corrosion rate, and the next inspection falls at one half that remaining life, subject to a hard cap — ten years for pressure vessel internal inspection under API 510 and five years for most piping circuits under API 570.
Why does corrosion under insulation need a different method?
Because the damage is hidden and localised. It concentrates at penetrations, supports, drains and damaged cladding rather than distributing evenly, so a thickness grid laid out on a drawing usually misses it. API RP 583 directs profile radiography, pulsed eddy current or targeted insulation removal at the locations where water ingress and retention are credible.
Do PHMSA pipeline rules follow the same inspection intervals as API codes?
No. Pipelines regulated under 49 CFR Parts 192 and 195 carry their own reassessment intervals for high consequence areas, defined in the integrity management subparts and enforced by PHMSA or a certified state agency. An operator with both regulated pipelines and API-governed plant equipment runs two independent inspection calendars.
Who is permitted to certify an oil and gas inspection in the United States?
The API inspection codes require a certified API inspector — 510, 570 or 653 as applicable — to authorise the inspection and sign the results. The NDT technicians performing the examinations are certified separately under the employer's written practice, written to ASNT SNT-TC-1A or ANSI/ASNT CP-189, and a Level III approves the procedures they work to.
Frequently asked
Can one inspection scope cover both the plant and the pipeline?
It can be managed by one team, but it cannot be one scope. The interval logic, the qualifying credentials and the record retention obligations differ between API-governed plant equipment and PHMSA-regulated pipeline, so the deliverables are separated even where the field crew is shared.
Is phased array accepted in place of radiography for weld examination?
Where the construction code permits it and the procedure is qualified accordingly. ASME Section V Article 4 provides the technique requirements and the referencing code section states whether an ultrasonic examination may substitute for radiography, generally requiring a documented, demonstrated procedure.
What is the most common finding in an independent data review?
Corrosion rate calculated against nominal wall thickness rather than the code required minimum. It makes the measured rate look lower and the resulting interval look longer, and it is the single most frequent arithmetic error found in remaining life calculations.