What an API 653 tank inspection establishes about your tank
Atlantis inspects aboveground storage tanks to API 653: monthly routine in-service checks, the five-year external inspection by an authorized inspector, external shell UT, and out-of-service internal inspection with MFL floor scanning, settlement survey and thickness evaluation. The report fixes your next internal inspection date and shows the corrosion rates and remaining-thickness calculations that produced it.
API 653 splits tank inspection into work you can do with the tank running and work that needs it empty. Routine in-service inspection is a ground-level visual at intervals not exceeding one month, done by your own operators. The formal external inspection is performed by an authorized inspector at least every five years, or at RCA/4N years if the shell corrosion rate makes that shorter. External shell UT runs to a maximum of five years when the corrosion rate is unknown, and to the smaller of RCA/2N or fifteen years once it is known. The internal inspection is where the floor gets scanned, settlement gets surveyed and the next interval gets set. Our scope is written against those clauses, so every measurement in the deliverable is traceable to the decision it supports rather than to a checklist item. See API 653 tank inspection intervals explained for the interval arithmetic in full.
Source: API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, Fifth Edition (November 2014) with Addendum 4 (July 2025) — clauses 1.1.1, 4.2.3, 4.3.2, 4.4.4–4.4.6, 6.3.1–6.3.4, 6.4.1–6.4.2, 6.9, Tables 4.4a/4.4b and 6.1, Annex B and Annex G. Also 40 CFR 112.8(c)(6) (EPA SPCC) and 29 CFR 1910.119(j)(4) (OSHA PSM). Clause text read directly from the standard; edition status confirmed August 2026.
| Inspection | Performed by | Maximum interval | What it establishes |
|---|---|---|---|
| Routine in-service | Owner/operator personnel; no certification required | 1 month | Leaks, shell distortion, signs of settlement, corrosion, coating, insulation and foundation condition |
| External (formal) | API 653 authorized inspector, tank in service | 5 years, or RCA/4N years if shorter | Condition of shell, roof, appurtenances, grounding and foundation from outside |
| External shell UT | Examiner working under the inspector | 5 years if corrosion rate unknown; smaller of RCA/2N or 15 years if known | Uniform shell corrosion rate and remaining shell thickness |
| Internal (out-of-service) | API 653 authorized inspector conducting or supervising the NDE | 10 years initially plus Table 6.1 safeguard credits; ceiling 20 years without an RPB, 30 years with one | Bottom integrity, minimum remaining thickness, settlement, and the next interval |
| Bottom-only in-service | Robotic UT and electromagnetic methods under the inspector | Set by the resulting bottom thickness, corrosion rate and integrity data | Bottom condition when that is the only reason the internal inspection is due |
| Cathodic protection survey | Personnel whose competency the owner/operator assures | Per API 651 | Whether soil-side bottom corrosion is being controlled |
What an API 653 tank inspection establishes
An API 653 inspection answers three questions your organization has to be able to answer on demand: is the bottom sound and not leaking, what is the minimum remaining thickness of bottom and shell after corrosion, and how much settlement has the foundation taken. API 653 6.4.1.1 states the purpose of internal inspection in those exact terms. Everything else in the scope exists to support those three answers, which is why a tank report full of observations but empty of thickness and corrosion-rate numbers has not done the job it was bought to do.
The commercial consequence is the interval. The inspection sets the date your tank next comes out of service, and that date is arithmetic: measured thickness, corrosion rate, and minimum acceptable thickness at the end of the period. We deliver the calculation, the data behind it, and the repair list that has to be closed for the interval to hold. Where you need the interval logic reviewed independently of the inspection contractor, our API 653 tank inspector services cover exactly that.
Routine in-service inspection: the monthly ground-level check
API 653 6.3.1.1 requires the external condition of the tank to be monitored by close visual inspection from the ground on a routine basis, at intervals not exceeding one month. Your own operators can do it. They need no certification, but they should know the facility, the tank and the characteristics of the product stored. The scope is deliberately narrow: evidence of leaks, shell distortions, signs of settlement, corrosion, and the condition of foundation, paint coatings, insulation systems and appurtenances.
This is the cheapest inspection you own and the one that most often catches a problem early. Its value depends entirely on escalation. API 653 says findings should be documented for follow-up action by an authorized inspector, and a monthly walk that produces no written record produces no follow-up either. We set up the route sheet, the photographic standard and the escalation path so that a shell weep found in March reaches an inspector in March rather than at the next five-year external.
The five-year external inspection: what the authorized inspector covers
The formal external inspection is the one buyers usually mean by "tank inspection". API 653 6.3.2.1 requires every tank to be given a visual external inspection by an authorized inspector at least every five years, or at RCA/4N years, whichever is less. The tank may stay in operation throughout. The inspector works the shell courses, the roof and roof-to-shell junction, nozzles to the first flange, stairways, walkways, wind girders, seals, drains, vents, the dike and the foundation ring.
Two details are worth knowing before you scope the job. Insulated tanks need insulation removed only to the extent necessary to determine the condition of the exterior wall or roof, so a whole-tank strip is a scope choice rather than a code requirement. And grounding system components such as shunts and mechanical cable connections must be visually checked. For how this interval interacts with shell corrosion data, see atmospheric storage tank external inspection intervals.
External shell UT and the corrosion rate that sets your interval
External ultrasonic thickness measurement of the shell is how you establish a uniform general corrosion rate while the tank stays in service. API 653 6.3.3.2 caps the interval at five years when the corrosion rate is not known, and at the smaller of RCA/2N or fifteen years once it is. Rates may be estimated from tanks in similar service, provided those thickness measurements were themselves taken at intervals not exceeding five years. Out-of-service internal inspection of the shell can substitute for the external UT program when its interval is equal to or shorter.
The extent of the measurements is set by the owner/operator, which means the scope is a decision you make rather than a number the code hands you. A sparse grid produces a corrosion rate with wide uncertainty, and that uncertainty lands on the interval. Where tank population size makes a per-tank grid expensive lets you concentrate measurement effort where likelihood and consequence justify it, with the documentation API RP 580 requires.
Internal inspection: roof, shell, floor and foundation, item by item
Roof work splits by type. On floating roofs, areas of deck plate and pontoons with cracks or punctures are repaired or replaced, holes are repaired or replaced, and pitted areas are evaluated for the likelihood of through-pitting before the next scheduled internal inspection. Roof support systems, perimeter seals, the rolling ladder, anti-rotation devices, drain systems and vents are all evaluated for repair. Fixed roofs are assessed for plate loss and for the condition of the roof-to-shell junction where frangibility matters.
Shell evaluation produces a controlling thickness for each course from the corroded areas found, excluding widely scattered pits. Those pits may be ignored only when no pit leaves remaining thickness below half the minimum acceptable shell thickness, and the sum of pit dimensions along any vertical line does not exceed 2 in. in an 8 in. length. Foundation evaluation looks at settlement, erosion, cracking and concrete deterioration around the ringwall, chime and drainage.
Floor scanning: MFL coverage, UT prove-up and the detection threshold
Magnetic flux leakage tools scan the floor for soil-side and product-side metal loss; ultrasonic thickness measurement then confirms and quantifies what MFL flagged. API 653 4.4.4 is explicit that data quality from both techniques depends on personnel, equipment and procedures, and points to Annex G for qualifying scanning operators and prove-up technicians. A floor scan is not a commodity — coverage percentage, plate-by-plate mapping and prove-up rules are scope decisions that belong in the contract, not assumptions.
One clause decides more than any other. Where a floor has been MFL scanned and has no effective cathodic protection, the thickness used to calculate the underside corrosion rate must be the lesser of the MFL threshold or the minimum thickness of unrepaired corroded areas. The MFL threshold is the minimum remaining thickness the scan is set up to detect, and the owner predetermines it based on the interval they want. Set the threshold loosely and your corrosion rate is fiction, checked in a tank report review before it reaches your integrity file.
Settlement survey and foundation evaluation
Excessive foundation settlement damages shells and bottoms, so API 653 Annex B treats settlement measurement as a normative part of the assessment. Shell settlement is measured with the tank empty using an even number of elevation points distributed uniformly around the circumference, never fewer than eight, with spacing no greater than 10 m (32 ft). The survey then separates uniform settlement, planar tilt and out-of-plane settlement, and evaluates edge settlement and localized bottom settlement against the Annex B limits.
Point spacing is where surveys go wrong. Eight points on a 200 ft tank satisfies the minimum count but exceeds the 32 ft spacing rule, and coarse spacing hides the local dish that actually threatens the shell-to-bottom weld. Additional points are needed halfway between any two that show a change in direction. Where geometry is complex or the tank is one of many in a turnaround, LiDAR scanning during a refinery turnaround captures a dense elevation profile in a fraction of the hours.
What triggers repair, and what the inspection record has to show
Repair triggers are numeric. If minimum bottom thickness projected to the end of the in-service period falls below Table 4.4 — 0.10 in. for a tank bottom and foundation design with no means of leak detection and containment, 0.05 in. where those means exist or where an API 652 reinforced lining over 0.05 in. is applied — the bottom is lined, repaired, replaced, or the interval to the next internal inspection is shortened. In the critical zone the limit is the smaller of 0.118 in. or 50 % of the lower course minimum thickness, and never below 0.10 in., with no averaging permitted.
US regulation puts a second demand on the same paperwork. The EPA SPCC rule at 40 CFR 112.8(c)(6) requires each aboveground container to be tested for integrity on a regular schedule and whenever material repairs are made, combining visual inspection with another technique such as hydrostatic, radiographic, ultrasonic or acoustic emission testing, keeping comparison records and inspecting supports and foundations. For tanks inside an OSHA PSM-covered process, 29 CFR 1910.119(j)(4) adds the date, the name of the person, the equipment identifier, the description and the results — the discipline covered in OSHA PSM mechanical integrity NDT.
Send us the tank list, the last inspection reports and the product service and we will scope the work against these clauses. Atlantis is affordable, accessible and fully customizable, and quotes are issued on request through contact.
How often does a storage tank need inspecting?
Four clocks run at once. Routine in-service visual inspection at intervals not exceeding one month. Formal external inspection by an authorized inspector at least every five years, or RCA/4N years if shorter. External shell UT at five years when the corrosion rate is unknown. Internal inspection at ten years initially, extended by Table 6.1 safeguard credits to a ceiling of twenty years, or thirty with a release prevention barrier.
Who is qualified to inspect an aboveground storage tank?
The formal external and internal inspections must be conducted or supervised by an API 653 authorized inspector employed by an authorized inspection agency. Routine monthly checks can be done by your own operating personnel, who need no certification but should know the tank and the product stored. NDE examiners scanning the floor or shooting UT work under the inspector; API 653 Annex G covers qualifying MFL operators and procedures.
What does an API 653 tank inspection cost?
Scope drives it. Diameter and floor area set the MFL scanning hours; shell height and course count set the UT grid; a floating roof, an internal lining, a heating coil or an annular ring each add work. Out-of-service inspections also carry cleaning, degassing and confined-space entry that sit outside the inspection scope. Send us the tank data sheet and the last report and we will quote the scope precisely.
What triggers a tank repair after inspection?
Calculated numbers, not opinion. If projected minimum bottom thickness at the end of the interval falls below Table 4.4 — 0.10 in. with no means of leak detection and containment, 0.05 in. with it — the bottom must be lined, repaired, replaced or the interval shortened. Critical zone plate below the smaller of 0.118 in. or half the lower course minimum thickness, and never below 0.10 in., triggers repair. Cracks, punctures and holes in floating roof plates are repaired outright.
Can a tank floor be inspected without taking the tank out of service?
Yes, when the internal inspection is required solely to establish bottom condition and integrity. API 653 6.4.1.2 permits robotic ultrasonic thickness measurement and other on-stream methods, supplemented by electromagnetic techniques, provided the data is sufficient to evaluate thickness, corrosion rate and integrity and to set the next internal interval. If shell, roof or appurtenance condition is also in question, the tank comes out of service.
What does a tank inspection company have to hand over at the end?
API 653 6.9 lists it: inspection date and scope, including anything not inspected and why; tank description; components inspected and deficiencies found; methods used and results; minimum measured remaining bottom thickness; corrosion rates before and after repair for bottom, shell and roof; the uncorroded thickness of one plate per shell course; pit locations and depths; through-holes; and the settlement survey with its analysis.
API 653 tank inspection: what Atlantis performs and what your inspector decides
For an API 653 tank inspection, Atlantis performs the NDE: shell UT, floor MFL scanning with UT prove-up, corrosion mapping, weld VT, MT and PT, and settlement survey support. ASNT-certified technicians do the work under ASNT Level III oversight. Your API 653 Authorized Inspector plans the inspection, evaluates the data, decides repairs and intervals, and signs the report. Atlantis is not the Authorized Inspector. We send a quote once we have your tank data.
The NDE scope, component by component
API 653 sets what a tank inspection has to establish. This section covers the practical side: which examinations produce that evidence, and what to write into the purchase order so the data supports your inspector's decisions.
| Tank area | NDE we perform | What your inspector gets |
|---|---|---|
| Shell courses | UT thickness at the shell CMLs on each course, in service or out of service | Readings by course and CML, comparable with earlier surveys |
| Lower course, door sheet and nozzle areas | Corrosion mapping with automated UT or PAUT where spot readings scatter | Thickness grids showing the extent and depth of local loss |
| Floor plates | MFL scanning to the agreed threshold, with UT prove-up of every flagged area | Plate map with indications and confirmed remaining thickness |
| Annular ring and critical zone | UT, PAUT or corrosion mapping where MFL scanners cannot reach | Thickness data for the zone next to the shell |
| Shell-to-bottom weld, nozzle welds and repairs | VT, MT and PT; RT through licensed radiography crews where volumetric examination is specified | Weld results with location, method and acceptance standard |
| Roof, pontoons and appurtenances | VT, with UT where plate loss is suspected | Findings with photos and thickness where measured |
| Foundation and settlement | Settlement survey support at the points your inspector specifies | Elevation data tied to the plate map, ready for the Annex B evaluation |
Shell UT
Shell thickness surveys run on fixed CMLs so each survey can be compared with the last. External UT can be taken while the tank is in service, from ground level or from access the owner provides. If the CML register is missing or inconsistent, we propose a layout for your inspector to approve before the first reading. We do not invent one in the field.
Floor MFL with UT prove-up
MFL finds metal loss quickly over large plate areas. UT then measures what MFL flagged. Two numbers belong in the contract: the MFL threshold your inspector has chosen, and the prove-up rule, meaning which indications get UT and how many points per indication. Scanners cannot cover every square inch. The strip next to the shell, lap welds, sumps, column bases and patch plates need UT or other methods. The coverage map in our report shows exactly what was scanned and what was not. Our MFL operators and procedures come with the qualification records your inspector will want to see under API 653 Annex G.
Corrosion mapping
Where single readings scatter, a grid tells the truth. We use automated UT or PAUT C-scans on the lower shell course, around nozzles and reinforcing plates, and on annular plates where local loss is suspected. The output is a thickness grid with its location on the tank, not a single minimum value. See corrosion mapping for the method.
Weld examination
VT covers the shell-to-bottom weld, nozzle welds and visible repairs. MT or PT is applied where your inspector or repair procedure calls for surface examination, for example on cracking suspects or completed repair welds. Every result records the weld or area ID, method, procedure and acceptance standard.
Settlement survey support
Settlement is measured with the tank empty, so it should be planned into the out-of-service window. We support the survey by laying out and recording the points your inspector specifies, or by working alongside your surveyor. The data is tied to the same plate map as the floor results. The Annex B evaluation of the readings stays with your inspector or engineer.
Who does what on an API 653 inspection
Most disputes on tank jobs come from unclear roles. This matrix is how we write them into the scope.
| Task | Owner / operator | Owner's API 653 Authorized Inspector | Atlantis |
|---|---|---|---|
| Decide when the tank comes out of service | Yes | Advises from the last interval | No |
| Cleaning, degassing, entry permits and access | Yes, or its contractors | Confirms the tank is ready to inspect | Works under the owner's permits |
| Inspection plan and NDE scope | Approves | Writes or approves | Proposes methods and coverage |
| MFL threshold and prove-up rules | Agrees | Sets | Applies and documents |
| NDE examinations and method reports | Receives | Reviews and accepts | Performs and signs as examiner |
| Corrosion rates, minimum thickness and remaining life | Receives | Calculates and documents | Supplies the measured data |
| Repair decisions and next inspection interval | Acts on them | Decides | No |
| Repair work | Hires the repair contractor | Approves the repair plan | No |
| Examination of repairs | Schedules | Specifies and accepts | Performs the NDE specified |
| Inspection report | Keeps it for the life of the tank | Signs it | Supplies NDE reports and data |
If your inspector wants an independent check of the NDE before signing, our Level III can review the data. The decisions stay with the inspector.
How an engagement runs, step by step
- You send the tank list. Data sheets, the last inspection report, product service and your inspector's scope, if it exists.
- We scope and quote. Methods, coverage, crew, equipment and days per tank. We reply within one business day.
- Pre-job agreement. Your inspector confirms the CML and plate numbering, the MFL threshold, prove-up rules and any corrosion-mapping areas. We submit procedures, technician certifications and calibration records for acceptance.
- Owner preparation. Cleaning, degassing, ventilation, lighting and entry permits are in place. MFL scanning needs a floor clean enough for the scanner to run.
- Fieldwork in sequence. Visual survey, then floor MFL, prove-up, annular and shell UT, corrosion mapping, weld examinations and settlement support. Significant findings go to your inspector the same day.
- Reports. Method reports reviewed under Level III oversight, with plate maps, reading tables and coverage maps.
- Repairs. Once your inspector decides the repairs, we examine them as specified.
- Close-out. The data is handed over in your format. It can also be placed on a 3D model of the tank through Digital Twin reporting.
Ready to scope a tank or a tank farm? Request an inspection quote and attach the last report.
NDE deliverables your inspector receives
API 653 lists what the inspection report must contain. The NDE package is what that report is built from. Ours includes:
- Method reports for each examination, signed by the examiner and reviewed under Level III oversight.
- A floor plate map with every MFL indication, its prove-up thickness and its position on the plate.
- A coverage map showing scanned areas, unscanned areas and the reason for each gap.
- Shell reading tables by course and CML, in the same numbering as your earlier surveys.
- Corrosion-mapping grids with their location on the tank.
- Weld examination results with weld IDs, methods, procedures and acceptance standards.
- Settlement data tied to the agreed points and datum.
- Supporting records: procedures, technician certifications, Annex G qualification records for the MFL work, and instrument calibration certificates.
Your inspector uses this package to calculate corrosion rates and minimum thickness, decide repairs and set the next interval. Data comes back in your format, so it drops into your existing inspection files without re-keying.
US regulatory overlay: SPCC, STI SP001, PHMSA and California
API 653 is an industry standard. In the US, regulations decide when you must follow it, or something equivalent.
EPA SPCC rule (40 CFR 112)
The SPCC rule generally applies to non-transportation facilities with more than 1,320 US gallons of aggregate aboveground oil storage capacity, counting only containers of 55 gallons or more, where a discharge could reach navigable waters or adjoining shorelines. The facility's SPCC Plan has to name the industry standard used for integrity testing of each container and the qualifications of the people doing it. A licensed Professional Engineer certifies the Plan, unless the facility qualifies to self-certify. Tier I and Tier II qualified facilities hold 10,000 gallons or less in aggregate and meet the rule's discharge-history criteria. The Plan must be reviewed at least once every five years. EPA's guidance says inspection and test records must be kept for three years, and recommends keeping formal inspection records for the life of the container. Where a facility departs from the industry standard with a site-specific program, a PE generally has to certify that it is environmentally equivalent. Tier I qualified facilities cannot deviate.
STI SP001 for shop-built tanks
API 653 is written for field-erected welded steel tanks. Shop-built tanks, such as horizontal fuel tanks, double-wall tanks and small vertical tanks, are commonly inspected to the Steel Tank Institute's SP001 standard instead. SP001 covers welded metal shop-fabricated tanks, small field-erected tanks and portable containers such as drums and totes. It sets the type and frequency of inspection by tank size and configuration, for example whether the tank has secondary containment and a means of release detection. Some configurations need only the owner's periodic visual inspections. Others need formal external and internal inspections by a certified inspector as SP001 defines. Atlantis performs the UT thickness readings and other NDE the SP001 inspector calls for. The formal inspection itself stays with the certified inspector.
PHMSA breakout tanks (49 CFR 195.432)
Hazardous liquid pipeline operators must inspect the physical integrity of in-service atmospheric and low-pressure steel breakout tanks according to API Std 653, as incorporated by reference. One exception matters for planning. The risk-based alternative internal inspection interval in API 653 section 6.4.3 cannot be used for these tanks. Intervals come from section 6.4.2.
California APSA
California's Aboveground Petroleum Storage Act applies to tank facilities with 1,320 gallons or more of petroleum and requires an SPCC Plan. Local Certified Unified Program Agencies (CUPAs) administer it, with oversight from the Office of the State Fire Marshal. Expect your CUPA inspector to ask for the integrity testing records your Plan promises.
Edition note: API 653's current edition carries Addendum 4, published July 2025. Confirm which edition and addenda your owner's procedures and your regulator reference before the job starts.
How to choose an API 653 tank inspection company
Many companies say "API 653 tank inspection". Few separate the NDE from the inspector's role clearly. Ask these questions before you award the work:
- Who signs what? The NDE contractor signs method reports. The Authorized Inspector signs the inspection report. If a bid blurs the two, ask which person holds the API 653 certification and who employs them.
- What is the MFL threshold, and who set it? It should come from your inspector, not from the scanner's default setting.
- What is the prove-up rule? Every flagged area, or a sample? How many UT points per indication?
- Will you get a coverage map? Unscanned areas must be visible, not implied.
- Are MFL operators and procedures qualified per Annex G? Ask to see the records before mobilization.
- How are the critical zone and annular ring covered? This is where scanners stop and failures start.
- Will the data come back against your CML and plate numbers? If not, the next survey cannot be compared with this one.
Common mistakes when buying tank NDE
- Booking the MFL crew before cleaning is finished. Scale and sludge stop the scanner and waste crew days.
- Forgetting the settlement survey. It needs the tank empty, so it belongs in the out-of-service window.
- Accepting a floor report with no prove-up depths. An MFL indication without a UT value cannot support a remaining-thickness calculation.
- Letting each contractor renumber CMLs and plates. The next survey then cannot be compared with this one.
- Buying on price per tank alone. Coverage, threshold and prove-up rules decide what the price actually buys.
For the full code background, read the API 653 tank inspection guide.
Where we work in the US
Atlantis is based in Houston, with crews mobilized onsite across the US. For local detail, see API 653 tank inspection in Baton Rouge and tank inspection in Houston, Beaumont, Corpus Christi and Los Angeles. State overviews cover Texas, Louisiana and California. For the full list of methods and services, see inspection services. Atlantis has delivered 1,500+ inspection activities.
Frequently asked questions
Who performs an API 653 tank inspection: Atlantis or our inspector?
Both, in different roles. Your API 653 Authorized Inspector conducts or supervises the inspection, evaluates the data and signs the report. Atlantis performs the NDE that produces the data. Atlantis is not the Authorized Inspector.
What NDE does an API 653 internal inspection usually need?
Typically floor MFL scanning with UT prove-up, UT of the annular ring and critical zone, shell UT by course, corrosion mapping where loss is local, visual examination of welds and appurtenances, surface examination where specified, and a settlement survey. Your inspector sets the final scope.
How do we choose an API 653 tank inspection company?
Check that the bid separates NDE from the inspector's role, names the MFL threshold and prove-up rule, provides a coverage map and reports against your CML and plate numbers. Ask for Annex G qualification records for the MFL crew.
Does API 653 apply to shop-built tanks?
API 653 is written for field-erected welded steel tanks. Shop-built tanks are usually inspected to STI SP001, as named in the facility's SPCC Plan. We perform the NDE either standard calls for.
What does an MFL tank floor inspection not cover?
MFL scanners cannot reach the strip next to the shell, lap welds, sumps, column bases or patch plates, and MFL alone does not size remaining thickness. Those areas need UT or corrosion mapping, and every MFL indication needs UT prove-up. A coverage map shows what was and was not scanned.
Do you repair tanks?
No. Repairs are done by a repair contractor under a plan your inspector approves. We perform the NDE of the repairs your inspector specifies.
Do you offer API 653 inspector training?
No. Atlantis training is ASNT SNT-TC-1A only, for Level I, II and III NDT technicians, delivered self-paced online or onsite at the employer.
How quickly can we get a quote?
Once we have the tank list, data sheets and last report; we reply within one business day. Request an inspection quote to start.
Can the results go into a digital model of the tank?
Yes. Floor, shell, annular and settlement data can be placed on a 3D model of the tank, campaign by campaign. Request an inspection quote and ask for the 3D handover.
API inspection guide library
Practical answers for owner-users and inspectors, from the NDE side of API 510, 570 and 653 work:
- API 510 and API 570 Inspection Plan: What It Must Contain
- Corrosion Rate Formula: Long-Term vs Short-Term (API)
- API 570 Class 1 Piping Inspection Intervals Explained
- API 653 Tank Inspection Checklist: Annex C Walkthrough
- RAGAGEP: How API 510, 570 and 653 Satisfy OSHA PSM
- Who Can Inspect SPCC Tanks? Certified vs Owner Inspector