Pressure Vessel Inspection Services (API 510 NDE)
What do pressure vessel inspection services include?
Pressure vessel inspection services provide the NDE behind an API 510 inspection: external and on-stream UT thickness at CMLs, internal examination during an outage, PAUT and TOFD on welds and nozzles, corrosion mapping and surface crack detection. Your API 510 inspector stays inspector of record, and Atlantis NDT reports are reviewed by an ASNT NDT Level III.
What you receive
- Thickness readings per CML, with current and previous values against your CML IDs
- Indications located and sized, and evaluated against the code you name
- The procedure, technique sheet, calibration and technician certification records used on the job
- A deviations log of areas not examined, with the reason
- A report reviewed by an ASNT NDT Level III before it is issued
What vessel NDE finds, and what it does not
Finds: Wall loss and remaining thickness at CMLs, localised corrosion in mapped areas, and surface and internal cracking at welds and nozzles.
Limits: Internal surfaces need entry, or an on-stream alternative your inspector justifies under API 510; UT needs a surface the sound can enter; insulation stays on only where a profile technique is planned.
Where we work: nationwide. Technicians are mobilised to your site anywhere in the USA; apart from the Houston office there is no local office, so mobilisation is planned and quoted for each job.
ultrasonic inspection services · corrosion mapping services · request an inspection quote
Atlantis performs the NDE for your API 510 programme; your API Authorized Inspector remains inspector of record. API 510 sets external inspection at intervals not exceeding five years and internal or on-stream inspection at the lesser of half the remaining life or ten years. We deliver CML thickness data and damage-mechanism-specific NDE findings your inspector uses to set rates, remaining life and the next date.
API 510 sets three clocks. External inspection runs at the lesser of five years or the internal/on-stream interval. Internal or on-stream inspection runs at the lesser of half the remaining life or ten years. Thickness measurement inspection runs on the same limit. When remaining life falls under four years, the interval may be the full remaining life to a maximum of two years. An on-stream inspection can stand in for entry only when seven conditions are all met, including a general corrosion rate under 0.005 in. per year, remaining life over ten years, and five years of established service history. Our scope is written per vessel against its credible damage mechanisms, so the NDE selected can actually find what that service produces. Fitness-for-service assessment picks up where metal loss exceeds the code's simple thickness rules.
Source: API 510, Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair, and Alteration, Eleventh Edition (October 2022) with Errata 1 (2023) and Errata 2 (2025) — clauses 1.1.1, 4.4, 4.5, 5.4.1–5.4.6, 5.5.4, 5.6.1–5.6.3, 5.7.1, 6.3, 6.4, 6.5.1–6.5.3, 7.1.1, 7.2, 7.8, Annex B. Also 29 CFR 1910.119(j)(4) (OSHA PSM). Clause text read directly from the standard; edition status confirmed August 2026.
| Inspection | Maximum interval | Set by | What it produces |
|---|---|---|---|
| Visual external | Lesser of 5 years or the internal/on-stream interval | Inspector or engineer under the owner-operator QA system | Condition of shell exterior, insulation, supports, nozzles, ladders and platforms |
| Internal | Lesser of half the remaining life or 10 years | Inspector or engineer under the owner-operator QA system | Internal surface condition, liner and internals, damage-mechanism evidence, entry-based NDE |
| On-stream in lieu of internal | Same limit as internal | Inspector, against the seven conditions in 6.5.2.1 | Wall thickness and pressure-boundary integrity without entry |
| Thickness measurement | Lesser of half the remaining life or 10 years | Inspector or engineer | CML data feeding corrosion rate, remaining life and next due date |
| Short remaining life case | Full remaining life, capped at 2 years | Inspector, when remaining life is under 4 years | A shortened cycle while replacement or upgrade is planned |
| RBI-set intervals | External capped at 10 years; internal and on-stream per the assessment | Team qualified in API RP 580, reviewed at least every 10 years | Documented, risk-justified intervals across the vessel population |
What a pressure vessel inspection has to establish
A vessel inspection exists to answer one question with numbers: how much longer can this vessel hold its rated pressure safely, and on what evidence. That resolves into remaining wall thickness at the limiting component, the corrosion rate acting on it, the credible damage mechanisms for its service, and the date by which it must be looked at again. API 510 covers in-service inspection, repair, alteration and rerating of hydrocarbon and chemical process vessels, including non-code vessels and jurisdictional-special vessels, not only ASME Section VIII Division 1 and 2 equipment.
That breadth matters commercially. Buyers often assume an ASME stamp settles the question and that in-service inspection is optional. It does not and it is not — the construction code governs how the vessel was built, and API 510 governs what happens to it afterwards. Where you need the inspection plan and the technique selection reviewed independently of the crew executing it, our ASNT Level III consulting services provide that separation.
External inspection while the vessel runs
The external inspection is preferably performed with the vessel in operation, at an interval not exceeding the lesser of five years or the internal/on-stream interval. It covers the outside surface, insulation and jacketing, supports and saddles, foundations and anchor bolts, ladders, platforms and nozzle connections. Particular attention goes to attachment welds — reinforcement pads, support brackets, lifting lugs — and to telltale holes in reinforcing plates, which are there to reveal leakage and to prevent pressure building behind the pad.
API 510 allows the visual external inspection to be performed by qualified personnel other than the inspector when their qualifications are acceptable to the owner-operator. In practice this is how large vessel populations get covered on schedule. It only works when the escalation route is written down, because the person who spots a cracked support shoe is rarely the person who decides what it means for the next internal due date. Distortion found externally is measured and reported, not estimated by eye.
Internal inspection, and when on-stream can replace it
An internal inspection means entry: cleaning, isolation, permitting, and direct examination of internal surfaces, liners, trays, distributors and weld seams for the damage the service is known to produce. It is the only way to see product-side pitting, under-deposit attack, liner disbondment and cracking that external NDE resolves poorly. API 510 caps the interval at the lesser of half the remaining life or ten years, and provides that when the extent of thinning can be detected or effectively monitored externally, an internal inspection is not required at half the remaining life.
On-stream inspection substitutes for entry under two headings. Either size or configuration makes entry physically impossible, or every one of seven conditions is satisfied: corrosion rate under 0.005 in. per year, remaining life over ten years, corrosive character established over at least five years of the same or similar service, nothing questionable found externally, shell temperature below the creep rupture range from API 579-1/ASME FFS-1, no environmental cracking or hydrogen damage from the fluid, and no non-integrally bonded liner.
When an on-stream inspection is conducted, the type and extent of NDE must be specified in the inspection plan, and the inspector must have sufficient access to heads, shell and nozzles to make an accurate assessment. Weld examination technique selection is set out in ASME BPVC Section V, which governs how the MT, PT, RT, UT and ET are actually performed.
CMLs: thickness monitoring that produces a defensible number
Condition-monitoring locations are the designated areas where periodic examination tracks the presence and rate of damage. API 510 notes explicitly that CMLs include what were formerly called thickness-monitoring locations, and extends the idea beyond wall loss to cracking and other mechanisms. A CML can hold several examination points — a nozzle CML with a point in each quadrant, for instance — and the minimum thickness within a CML is located by ultrasonic scanning, not by a single spot reading dropped wherever the couplant landed.
Placement follows expected corrosion patterns, previous inspection results and consequence of loss of containment, distributed to give coverage of major components and nozzles. CMLs with the highest corrosion rates and the least remaining life must be part of the data used to determine the limiting component. That last requirement is where inherited data sets fail: an average across a vessel that includes a fast-corroding bottom head produces a comfortable number and a dangerous conclusion. We check that logic explicitly during report validation.
Damage mechanisms by service, and the technique that finds them
API 510 requires appropriate inspection techniques for each credible damage mechanism to be part of the inspection plan, and points to API RP 571 for the catalogue. The metal-loss group covers sulfidation and high-temperature H2S/H2 corrosion, oxidation, microbiologically influenced corrosion, naphthenic acid corrosion, erosion-corrosion, galvanic and atmospheric corrosion, corrosion under insulation, cooling water and boiler water corrosion, soil corrosion, ammonium bisulfide, ammonium chloride and amine hydrochloride corrosion, and CO2 corrosion.
Cracking splits by depth. Surface-connected cracking includes mechanical and thermal fatigue, caustic and polythionic acid stress corrosion cracking, sulfide stress cracking in wet H2S service, and chloride stress corrosion cracking. Subsurface cracking covers hydrogen-induced cracking and stress-oriented HIC. Then high-temperature hydrogen attack and creep, the metallurgical changes — graphitization, temper embrittlement, hydrogen embrittlement — and blistering. Straight-beam thickness readings find none of the cracking mechanisms, which is the argument set out in RT vs UT for weld inspection.
Cyclic-service vessels get separate treatment. Coke drums, mole sieves and pressure swing adsorbers are named examples, and the plan is expected to consider fatigue design criteria from the construction code, attachment and nozzle details, weld peaking and flattening, out-of-roundness, and NDE capable of finding fatigue cracks — external angle-beam UT, wet fluorescent magnetic particle, time-of-flight diffraction.
Corrosion rate, remaining life and the four-year rule
Corrosion rate for thinning is the difference between two thickness readings divided by the interval between them. Short-term rates use the two most recent readings; long-term rates use the most recent and one taken earlier in the vessel's life. Both are calculated, and the inspector, in consultation with a corrosion specialist, selects the rate that best reflects current conditions — considering whether the damage is general or localized, whether impingement or erosion is in play, when the corrosion actually initiated, and what process change may have caused it.
Remaining life is the margin above required thickness divided by that rate. The interval is then half that remaining life, capped at ten years. Below four years of remaining life, the interval may be the full remaining life to a maximum of two years — a legitimate short-cycle strategy, and one API 510 warns against relying on indefinitely, since frequent inspection can be a higher-risk strategy than replacement, redesign or a material upgrade. Permanently mounted sensors are named as an alternative to repeated manual campaigns.
What an owner-user inspection program has to contain
The record set is where most programs are audited and where most fail. API 510 requires permanent and progressive records: construction and design information, including serial number, manufacturer's data reports, U-1 forms, nameplate photographs, heat treatment charts and design calculations; inspection history for every inspection type; repair, alteration and rerating documentation; and fitness-for-service assessment documentation per API 579-1/ASME FFS-1. Each inspection report must carry the inspection date, the next scheduled date, the person who performed it, the equipment identifier, a description of what was done and the results.
Recommendations need a disposition, including the reason any recommendation was not implemented — the single most common gap we find in inherited files. Documented results must be approved by the responsible inspector, engineer or qualified designee and posted into the inspection data management system within 90 days of completion or startup. For vessels inside an OSHA PSM-covered process, 29 CFR 1910.119(j)(4) requires the same five data points on every test, which is the ground covered by OSHA PSM mechanical integrity NDT.
Who inspects, who examines, and who signs
The division of authority is the part buyers most often get wrong when comparing bids. The inspector is responsible to the owner-operator for assuring that inspection, NDE, repairs, alterations and pressure testing meet API 510, must be directly involved in the inspection activities, and must be certified under Annex B. Examiners perform the NDE. They need no API 510 certification and need not be employees of the owner-operator, but must be trained and competent in the procedures used, with certification records maintained by their employer.
All NDE results are evaluated and accepted by the inspector, who then makes the recommendations for repair, replacement or continued service. A bid that quotes technician hours without naming the certified inspector who will accept the data is quoting half the job. What that acceptance has to look like on paper is set out in what makes an NDT report defensible. Send us your vessel list and last reports through contact for a scoped quote — affordable, accessible, fully customizable.
What are the pressure vessel inspection requirements under API 510?
Three inspections, each with its own ceiling. A visual external inspection at no more than five years, or the internal/on-stream interval if that is shorter. An internal or on-stream inspection at no more than half the remaining life or ten years. Thickness measurement inspection on that same limit. All three are set by the inspector or engineer under the owner-operator's quality assurance system, and all three are documented.
Who can inspect a pressure vessel?
An API 510 certified inspector, working for the owner-operator or as a contractor the owner-operator accepts, is responsible for the inspection and shall be directly involved in it. NDE examiners do not need API 510 certification, but must be trained and competent in the procedures used and may be required to hold ASNT SNT-TC-1A, CP-189, CGSB or AWS QC1 credentials. The inspector evaluates and accepts all NDE results.
What does a pressure vessel inspection company deliver?
A dated report per vessel carrying the equipment identifier, the inspection type and scope, the examinations performed and their results, thickness data per CML, long-term and short-term corrosion rates, remaining life for the limiting component, the next inspection due date, and a tracked list of repair recommendations with the disposition of each. API 510 expects results posted into the inspection data management system within 90 days.
When can an on-stream inspection replace opening the vessel?
When entry is physically impossible, or when all seven conditions hold: general corrosion rate below 0.005 in. per year; remaining life above ten years; corrosive character established by at least five years of the same or similar service; nothing questionable found on the external inspection; shell temperature below the creep rupture range; no environmental cracking or hydrogen damage from the fluid; and no non-integrally bonded liner.
How many CMLs does a vessel need?
API 510 sets no fixed count. More CMLs go on vessels with higher consequence of leakage, higher expected or experienced corrosion rates, and higher potential for localized corrosion. Fewer go on vessels with low leak consequence, non-corrosive contents and uniform corrosion. Where CMLs would be cut sharply or eliminated, a corrosion specialist has to be consulted, and that consultation belongs in the file.
What does a pressure vessel inspection cost?
Scope sets it. Vessel count, diameter and height, insulation removal, scaffolding or rope access, entry and cleaning for internal work, the number of CMLs, and whether the credible damage mechanisms call for angle-beam UT, wet fluorescent magnetic particle, TOFD or phased array rather than straight-beam thickness readings. Send the vessel list, the last inspection reports and the service conditions, and we will quote the scope on request.
Pressure vessel inspection services: what Atlantis delivers
Atlantis provides the nondestructive examination that an API 510 pressure vessel inspection depends on. ASNT-certified technicians, under ASNT NDT Level III oversight, perform UT thickness at CMLs, corrosion mapping, PAUT, TOFD, MT including wet fluorescent MT, PT and VT. Radiography is performed by licensed radiography crews. Results go to your API 510 Authorized Inspector, who stays inspector of record. Every job is quoted on request, and we reply within one business day.
What is included in a pressure vessel NDE scope
Most vessel work falls into six scope types. One turnaround often combines several of them across a unit. The table shows what triggers each scope, the methods normally used and what you receive. Final method selection is agreed with your inspector against each vessel's credible damage mechanisms.
| Scope | Typical trigger | Methods | What you receive |
|---|---|---|---|
| On-stream thickness survey | Thickness measurement inspection due; on-stream inspection in lieu of internal | UT at CMLs, encoded corrosion mapping, profile RT on small nozzles | CML table with current and previous readings, C-scans, verified minimum per CML |
| External inspection support | External inspection cycle, insulation damage, corrosion under insulation concern | VT, UT at inspection openings, mapping at stripped areas | Condition photos, thickness at openings, a findings list for the inspector |
| Turnaround internal support | Vessel open for internal inspection | VT, MT and wet fluorescent MT, PT, UT, PAUT on welds | Indication reports with locations, weld maps, photos |
| Crack-focused examination | Wet H2S, amine, caustic or cyclic service; earlier cracking | Wet fluorescent MT on internal welds, angle-beam UT, PAUT, TOFD | Indication length and, where the technique allows, depth; location sketches |
| Repair and alteration NDE | Weld repair, nozzle addition, rerating | MT or PT before and after repair; RT or UT as the repair plan requires | Acceptance reports against the code the repair plan names |
| New-construction NDE | ASME Section VIII fabrication in a shop or on site | RT through licensed crews, UT or PAUT where the code allows, MT, PT | Examination reports for the fabricator's quality control and its ASME Authorized Inspector |
Every report is built in our own NDT reporting software. Each reading is tied to the vessel, CML, procedure, technician certification and instrument calibration. Thickness data exports in a format your inspection data management system can import. Mapped areas can also be placed on a 3D model of the vessel. See Digital Twin reporting.
What the NDE report pack contains
Your inspector writes the inspection report. Our job is to give them evidence they can accept without chasing anyone. Each vessel's NDE pack includes:
- A CML table with nominal, previous and current readings, using your CML IDs.
- C-scan images and the raw scan files for every mapped area, with datum records.
- Indication reports with location, length and, where the technique allows, depth, plus weld maps and photos.
- The procedure and technique sheet reference for every examination.
- Technician certifications and instrument calibration certificates.
- A deviations log: areas not examined, with the reason, such as no access or insulation left in place.
The deviations log matters more than it looks. An inspector who knows what was not examined can make a sound decision. One who assumes full coverage cannot.
Where NDE effort usually goes, by vessel type
The same plant can hold vessels that need very different examinations. This is a starting point for discussion with your inspector, not a substitute for a damage mechanism review.
| Vessel type | Typical concerns | Where NDE effort usually goes |
|---|---|---|
| Amine contactors and regenerators | Amine stress corrosion cracking at welds; wet H2S damage in some sections | Wet fluorescent MT on internal welds, angle-beam UT or PAUT from outside |
| Sour water strippers and overhead accumulators | Wet H2S damage, including blistering and hydrogen-induced cracking; under-deposit corrosion | 0° mapping to find mid-wall damage, wet fluorescent MT, PAUT |
| Separators, knock-out drums and scrubbers | Bottom and water-boot corrosion, liquid-level attack, erosion at inlets | Corrosion mapping of bottom heads and boots, UT at inlet impingement areas |
| Air receivers | Internal corrosion where condensate collects | UT mapping of the bottom head and lower shell, VT of drains and supports |
| Deaerators | Cracking at shell welds | Wet fluorescent MT on internal welds, angle-beam UT |
| Heat exchanger shells and bundles | Shell-side corrosion, tube wall loss | UT on shells and channels, eddy current on non-ferrous tubes |
How an engagement runs, step by step
- Send the vessel list. Equipment IDs, manufacturer's data reports or nameplate data, drawings with CML locations, the last two inspection reports, service and operating temperature, insulation, access, target dates and your inspector of record's contact.
- Receive a written quote. The quote is written per vessel. It lists methods, crew size, days on site and the assumptions behind them, such as who provides scaffolding, insulation removal and vessel cleaning. Pricing is quote on request.
- Agree the scope with your inspector. We confirm methods per damage mechanism, any added CMLs and the areas that need crack-focused techniques. Our Level III issues the technique sheets.
- Pre-mobilisation pack. You receive procedures, technician certifications, instrument calibration certificates and, for radiography, the crew's licensing documents before anyone arrives. Your site issues permits and runs orientation.
- Field execution. On-stream work runs while the unit operates. Internal work fits the turnaround window. You get a daily progress note against the vessel list.
- Same-shift escalation. Any reading at or near the required thickness, and any crack-like indication, goes to your inspector before the crew leaves the vessel.
- Level III review and report. Data is reviewed under Level III oversight, and one report is issued per vessel.
- Data handover. CML readings and C-scan files go to your inspector in the agreed format, using your CML IDs.
- Next campaign. The same datums and CML IDs are used again, so the next corrosion rate compares like with like.
Want the inspection plan or technique selection checked before the crew is booked? Talk to a Level III.
Turnaround timing: when to bring the NDE provider in
On the Gulf Coast most vessel work is planned around spring and autumn turnarounds. NDE goes wrong when it is booked as a last-minute crew rather than planned as part of the work list. A workable sequence looks like this:
- At work-list freeze. Share the vessel list and damage mechanism review. This is when crack-focused techniques, added CMLs and radiography exclusion zones get into the plan.
- Before the outage. Run the on-stream thickness surveys and corrosion mapping while the unit is still running. Findings then shape the internal scope instead of surprising it.
- During the outage. Internal examinations follow cleaning and entry permits vessel by vessel. Hold points for your inspector are agreed in advance, so a crew is never waiting on a decision.
- After start-up. Reports are finalised, data loads into your inspection database, and any deferred items move into the next on-stream plan.
Who this service is for
- Refineries and petrochemical plants along the Texas and Louisiana Gulf Coast. These sites usually have their own API 510 inspectors but need NDE crews for turnarounds and on-stream programmes.
- Chemical plants, gas processing and midstream sites. Separators, scrubbers, amine and dehydration vessels, and other services where cracking mechanisms sit alongside thinning.
- LNG facilities and terminals. Process vessels, knock-out drums and receivers, often in coastal settings where external corrosion and CUI dominate.
- Power plants. Deaerators, feedwater heaters and air receivers. Some of these fall under boiler or jurisdictional rules as well as the owner's programme.
- Fabrication shops. New-construction NDE to ASME Section VIII. The acceptance criteria differ from in-service work; see ASME Section VIII Division 1 RT and UT acceptance.
- Manufacturing, food and pharmaceutical sites. Air receivers, autoclaves and process vessels. Smaller sites often rely on an insurer's inspector and need NDE when that inspector asks for thickness or crack checks.
Scopes range from a few vessels on an insurer's list to a full unit turnaround.
Who does what on a pressure vessel inspection
Bids are hard to compare when the roles are blurred. This matrix shows who holds each responsibility and where Atlantis fits.
| Role | What they do | Basis | Atlantis role |
|---|---|---|---|
| Owner-user | Owns the inspection programme, the quality assurance system and the records | API 510 owner-user responsibilities | Client |
| API 510 Authorized Inspector | Directs the inspection, evaluates and accepts NDE results, sets intervals, recommends repairs | API 510 certification | Not Atlantis. Your inspector stays inspector of record |
| NDE examiner | Performs and records examinations to procedure | Employer certification, typically a written practice to ASNT SNT-TC-1A | Yes |
| ASNT NDT Level III | Approves procedures and technique sheets, oversees examiners, reviews data | ASNT Level III certification | Yes |
| Pressure vessel engineer and corrosion specialist | Required thickness, rerating, damage mechanism review, input on corrosion rate selection | Owner's engineering function | No |
| Fitness-for-service and RBI assessors | Assessments to API 579-1/ASME FFS-1 and API 580/581 | Specialist engineering | No. Atlantis supplies NDE data only |
| Repair organisation | Weld repairs and alterations | As API 510 and the jurisdiction allow, often a National Board "R" certificate holder | No. We perform the repair NDE |
| Jurisdictional or insurer inspector | Certificate inspections where state or local law requires them | Usually a National Board commission | No |
If your RFP is unsure which inspector credential to specify, API 510 versus a National Board commission sets out where the two overlap.
How to compare pressure vessel inspection companies
Most bids look alike on the cover page. These questions separate them:
- Is the scope written per vessel? A crew-day rate with no method list leaves method choice to whoever turns up.
- Who accepts the data? The bid should name the inspector of record. If the same firm supplies both the inspector and the NDE crew, ask how that inspector stays independent of the crew's output.
- Do methods match the damage mechanisms? Straight-beam thickness readings alone on a vessel in cracking service is a gap, however many readings are taken.
- Are procedures and technique sheets Level III-approved? Ask for a sample technique sheet with the bid.
- Are certifications current for each method? Check method, level, expiry and vision exam date for every named technician.
- Is radiography properly licensed? RT crews must hold the radioactive material licence and radiographer certification the state requires.
- Will the data fit your system? Your CML IDs, an export file and the raw C-scan files, not only a PDF.
- How are urgent findings handled? The bid should promise same-shift escalation to your inspector.
A template for the report structure inspectors expect is in our free API 510 inspection report template.
Jurisdiction overlay: US states and Canada
API 510 is an owner-user code. Whether a state also inspects your vessels depends on where they sit. Federal OSHA's process safety management standard covers mechanical integrity for covered processes in every state. Beyond that, the rules vary.
- Texas. Boilers are registered and inspected through the TDLR Boiler Program. Texas does not run a general state inspection programme for unfired pressure vessels, so vessel inspection is driven by PSM, insurers and owner programmes built on API 510. Confirm the status of a specific item with TDLR. See inspection services in Texas.
- California. Cal/OSHA's Pressure Vessel Unit issues permits to operate for air tanks, LP-gas tanks and power boilers above set size and pressure thresholds. Permit inspections are performed by Cal/OSHA inspectors or qualified insurance company inspectors, under the Title 8 Unfired Pressure Vessel Safety Orders. See inspection services in California.
- Louisiana, Illinois and Pennsylvania. Check the state's boiler and pressure vessel rules before scoping, because coverage of unfired vessels differs from state to state. See Louisiana, Illinois and Pennsylvania.
- Owner-user inspection organisations. Where the jurisdiction accepts it, an owner-user accredited by the National Board under NB-371 can have its own commissioned inspectors carry out in-service inspections.
Canada notes. Pressure equipment is regulated by each province, generally through CSA B51, by bodies such as ABSA in Alberta, TSSA in Ontario and Technical Safety BC. Large owners may run integrity programmes that the provincial authority approves. NDT personnel on Canadian work are commonly certified to CAN/CGSB-48.9712. The CGSB closed on 1 April 2026, and NRCan's NDT Certification Body continues and issues CAN/CGSB-48.9712. Atlantis delivers Canadian work onsite; there is no Canadian office.
Common mistakes when buying vessel inspection
- Buying technician hours instead of a scope. Without a method list per vessel, the cheapest bid is often the one that left out crack detection.
- Letting the NDE contractor become the inspector by default. API 510 requires the inspector to evaluate and accept NDE results. A report with no named acceptor is not a completed inspection.
- Renaming CMLs every campaign. New IDs break the corrosion rate history and force a fresh baseline.
- Not sending the previous reports. The crew cannot spot a jump in corrosion rate on site if it cannot see the last readings.
- Planning insulation removal and scaffolding late. NDE then becomes the critical path when the vessel opens.
- Forgetting the small vessels. Air receivers and small process vessels outside the main unit often carry permit or insurer requirements of their own.
- Treating fitness-for-service as part of the NDE bid. FFS is an engineering assessment. Scope it separately with a qualified assessor.
Frequently asked questions
Do you provide pressure vessel inspection services near me?
Atlantis is based in Houston and mobilises crews to client sites across the United States. We have no other US offices, so crews travel to your plant. Our state pages, from the inspection services hub, cover local regulators and cities.
What do pressure vessel inspection companies actually do?
Two different jobs often share the label. Inspection is the API 510 inspector's judgement on condition, intervals and repairs. Examination is the NDE that produces the evidence. Atlantis performs the examination and hands the results to your inspector.
Is Atlantis the API 510 Authorized Inspector on my job?
No. Your API 510 Authorized Inspector stays inspector of record and accepts the NDE results. Atlantis is the NDE provider working under ASNT Level III oversight.
Can you inspect a pressure vessel while it is running?
Yes. UT thickness and corrosion mapping are routinely done on-stream, within the temperature limits of the probe and couplant. Whether that on-stream work can replace an internal inspection is your inspector's decision under API 510. The API 510 standard summary sets out the conditions.
Do you perform NDE for new pressure vessel fabrication?
Yes. We perform RT through licensed radiography crews, UT or PAUT where the code allows, MT and PT for shops and site fabrication to ASME Section VIII. Reports go to the fabricator's quality control and its ASME Authorized Inspector.
Do you perform fitness-for-service or risk-based inspection?
No. API 579-1/ASME FFS-1 assessments and API 580/581 risk-based inspection are engineering services that Atlantis does not offer. We supply thickness grids and indication data in the form an assessor needs.
Can you inspect air receivers for a California permit?
Permit inspections in California are performed by Cal/OSHA Pressure Vessel Unit inspectors or qualified insurance company inspectors. If that inspector asks for thickness readings or other NDE, Atlantis can perform it and report to them.
What do you need from us to quote?
The vessel list, data reports or nameplate details, CML drawings, the last inspection reports, service conditions, access and insulation details, and your dates. We reply within one business day. Request an inspection quote.
How are results delivered?
As one report per vessel with CML tables, C-scans, indication reports, photos and certification records, plus a data export for your inspection database. See how intervals are then set in API 510 interval calculation explained. Ready to scope a campaign? Request an inspection quote.