{"slug":"/standards/api-575","title":"API 575 Storage Tank Inspection: Intervals and Limits","description":"API 575 tells you how to inspect an atmospheric tank; API 653 sets the numbers — external inspection at 5 years or RCA/4N, internal capped at 20 years.","h1":"API RP 575 — inspection practices for atmospheric and low-pressure storage tanks","answer":"API RP 575 is the recommended practice describing how to inspect atmospheric and low-pressure storage tanks built to API 650, API 620 and the API 12 series. It explains damage mechanisms, inspection methods and checklists, but it sets no mandatory acceptance criteria — the intervals and minimum thicknesses that govern an in-service tank come from API 653.","expansion":"The practical value of API 575 is that it tells an inspector what to look at and why it degrades, tank component by tank component: the shell course at the liquid level, the vapor space above it, the roof rafters and underside, the shell-to-bottom weld and critical zone, the underside of the bottom where soil-side corrosion runs unseen, the water draw-off, nozzles and their reinforcing pads, floating-roof pontoons and rim seals, and the foundation. It then maps each of those to a method — MFL floor scanning with ultrasonic prove-up, vacuum box testing of lap welds, settlement surveys, shell UT grids, and tracer-gas leak testing. What it deliberately does not do is decide whether the tank is fit for continued service. That decision belongs to API 653 and to the API 653 Authorized Inspector, and confusing the two is the fastest route to an audit finding.","source":"Named sources: API RP 575, Inspection Practices for Atmospheric and Low-pressure Storage Tanks; API 653, Tank Inspection, Repair, Alteration, and Reconstruction (Sections 4, 6, 9 and 12, Annex B, Annex G); API 650; API 620; API 651, Cathodic Protection of Aboveground Petroleum Storage Tanks; API 652, Linings of Aboveground Petroleum Storage Tank Bottoms; API 2015 and API 2016 (tank cleaning and entry); API 2610; ASME BPVC Section V; AMPP/NACE SP0169; 49 CFR 195.432.","table":{"caption":"Inspection activity on an in-service tank — API 575 describes the practice, API 653 sets the ceiling","columns":["Activity","Who performs it","Interval ceiling","Governing reference"],"rows":[["Routine in-service external visual","Owner/operator personnel; no formal NDT certification required","Monthly is the practice normally adopted","API 653 Section 6.3.1; API 575 checklists"],["Formal external inspection","API 653 Authorized Inspector","The lesser of 5 years or RCA/4N years","API 653 Section 6.3.2"],["Shell ultrasonic thickness measurement","UT technician, data reviewed by the Authorized Inspector","The lesser of RCA/2N or 15 years where the corrosion rate is known; 5 years where it is not","API 653 Section 6.3.3"],["Internal inspection","API 653 Authorized Inspector","Initial within 10 years; thereafter not exceeding 20 years; 30 years is the absolute ceiling under a documented RBI assessment","API 653 Sections 6.4.2 and 6.4.3"],["Cathodic protection survey","CP specialist","Annual structure-to-electrolyte potential survey; rectifier output readings at least every two months","API 651; AMPP/NACE SP0169"],["Bottom examination procedure qualification","NDT Level III / procedure owner","Demonstrated before use, and again on any essential variable change","API 653 Annex G"]],"note":"RCA is the remaining corrosion allowance and N the corrosion rate, in consistent units. Both are derived from thickness data, so an interval calculated from unmapped readings cannot be defended in an audit."},"facets":[{"q":"Is API 575 a code or a recommended practice?","a":"It is a recommended practice. API 575 describes how to inspect atmospheric and low-pressure storage tanks — planning, access, methods, checklists and reporting — but it imposes no mandatory intervals, no minimum thicknesses and no repair rules. Those live in API 653, which is the in-service code and the document regulators, client specifications and 49 CFR 195.432 actually point at. A report that cites only API 575 has not discharged a 653 obligation."},{"q":"Which tanks fall inside the scope of API 575?","a":"Welded, riveted and bolted tanks operating from atmospheric pressure up to the low-pressure range: tanks built to API 650, to API 620, and to the API 12 series including 12B bolted, 12D and 12F shop-fabricated units, plus older riveted stock still in refinery, terminal and pipeline breakout service. Pressure vessels above 15 psig sit under API 510, piping under API 570, and underground tanks under a separate regulatory regime entirely."},{"q":"Where does the tank end and the piping begin for inspection purposes?","a":"At the first flange or first circumferential weld outboard of the nozzle, depending on the configuration and the owner's documented boundary. The nozzle, its reinforcing pad and any shell insert plate belong to the tank and to API 653. The line beyond belongs to API 570. Where nobody has drawn that boundary in writing, roof drain flexible joints and nozzle-to-shell welds routinely fall between the two programmes and are examined by neither."},{"q":"What minimum bottom plate thickness does API 653 require?","a":"API 653 Section 4.4 sets a minimum remaining thickness at the next scheduled internal inspection — commonly 0.100 in. for a bottom without a release prevention barrier and 0.050 in. where one is fitted, per Table 4.4. Separately, the critical zone within 3 in. of the shell carries its own 0.100 in. floor. Applying the general bottom criterion inside the critical zone is one of the most frequently written findings."},{"q":"How often must a tank be opened for internal inspection?","a":"API 653 Section 6.4 sets the initial internal inspection within 10 years of service where the soil-side corrosion rate is unknown, and thereafter an interval not exceeding 20 years. A risk-based inspection assessment under Section 6.4.3 can extend that, with 30 years as the absolute ceiling. An RBI-extended interval must be documented, reviewed by qualified personnel and reassessed — the missing reassessment is what auditors find."},{"q":"Does a cathodic protection system remove the need to inspect the bottom?","a":"No. API 651 expects an annual structure-to-electrolyte potential survey, with the criterion normally a −850 mV instant-off reading against a copper/copper-sulphate reference or 100 mV of polarisation, plus rectifier output readings at least every two months. A rectifier that has been switched off since the last turnaround is a common discovery, and it invalidates the corrosion-rate assumption the internal interval was built on."}],"sections":[{"heading":"What API RP 575 actually is, and what it is not","paragraphs":["API RP 575 is a recommended practice. It is written for the person planning and performing the inspection of an atmospheric or low-pressure storage tank, and it reads like a field manual: reasons for inspecting, types of inspection, safety and entry preparation, the components to examine, the deterioration expected at each of them, the methods that find that deterioration, and how the results are recorded. It is genuinely useful, and it is the best single source on tank inspection practice that most owners have on the shelf. What it is not is the document that decides anything.","The decisions belong to API 653. API 653 sets the inspection intervals, the minimum acceptable shell and bottom thicknesses, the evaluation rules for locally thinned areas and settlement, the requirements for repairs and alterations, and the certification of the API 653 Authorized Inspector who signs the tank back into service. Every regulatory hook lands on 653, not 575: 49 CFR 195.432 requires breakout tank integrity to be assessed to API 653, and the great majority of terminal and refinery specifications do the same. Where an owner needs the written practice, procedures and technical authority behind that work built properly, that is [ASNT Level III consulting](/consulting) territory rather than a document-purchase exercise.","API 575 also does not stand alone. It sits in a family: API 650 and API 620 for construction, API 651 for cathodic protection, API 652 for bottom linings, API 2015 and API 2016 for cleaning and safe entry, API 2610 for terminal and tank facility management, and ASME BPVC Section V for the NDE methods themselves. Reading 575 in isolation is how programmes end up with an inspection scope that looks complete and an evidence chain that has holes in it."]},{"heading":"Scope: which tanks, which pressures, and where the boundary sits","paragraphs":["The practice addresses welded, riveted and bolted tanks storing petroleum, petroleum products, chemicals and water at atmospheric pressure and in the low-pressure range. In practical terms that means API 650 welded tanks, API 620 low-pressure tanks, API 12B bolted production tanks, API 12D and 12F shop-fabricated tanks, and the population of riveted tanks still in service at older terminals. It covers fixed roof, external floating roof, internal floating roof and dome-covered configurations, and it covers the foundation the tank sits on as well as the tank itself.","What falls outside is just as important. Pressure vessels operating above 15 psig are inspected under API 510 to ASME Section VIII criteria. Associated piping is API 570. Underground storage tanks sit under a separate regulatory regime. Shop-fabricated tanks in many jurisdictions are inspected to STI SP001 rather than API 653, and the choice between the two is a compliance decision the owner has to document rather than a preference. API 575 also does not qualify anyone: the certification of an API 653 Authorized Inspector is an API Individual Certification Program matter and is entirely separate from the NDT personnel certification that governs the technicians producing the thickness data.","The boundary that causes real trouble is the tank-to-piping transition. The nozzle, its reinforcing pad and any shell insert plate belong to the tank. The line beyond the first flange or first circumferential weld belongs to the piping programme. Where that boundary has never been written down, predictable components fall through: roof drain flexible joints, the internal roof drain line, water draw-off assemblies, and mixer nozzles. An auditor who asks to see the last examination record for the roof drain inside the tank and is met with silence has found the boundary problem in about ninety seconds."]},{"heading":"The degradation mechanisms API 575 tells you to hunt","paragraphs":["Soil-side corrosion of the bottom plates dominates the leak statistics. It is invisible from inside the tank until it perforates, it is driven by the quality of the foundation and the pad rather than by the product, and it is the reason cathodic protection, release prevention barriers and magnetic flux leakage floor scanning exist as a package. A bottom that looks clean and shiny from the inside can be within a few tens of mils of through-wall on the underside, which is exactly why prove-up ultrasonics behind the scanner is not optional.","Internally, the mechanisms cluster where phases meet. The water bottom and the product-water interface pit aggressively; microbiologically influenced corrosion concentrates under sludge where nobody has swept; the shell just above the maximum liquid level and the vapour space above it collect wet hydrogen sulphide and oxygen and corrode faster than the wetted shell below; and in fixed-roof terminal tanks the underside of the roof plate and the rafters are very often the worst-corroded component in the entire tank. Floating roofs add pontoon corrosion, deck seam leakage and rim seal degradation with a vapour-loss consequence as well as a mechanical one.","Externally the list is corrosion under insulation, corrosion at the chime and under the annular ring where the foundation traps water against the plate, coating breakdown at the wind girder and stairway attachments, and environmental cracking — caustic cracking near shell nozzles in caustic service, amine cracking, and sour water cracking. Old, non-normalised plate brings brittle fracture into the conversation whenever the service or the fill temperature changes. Finding these reliably is a skills question as much as a procedural one, which is why terminals increasingly pair their programme with structured [NDT training and certification](/training) rather than relying on whoever is available."]},{"heading":"Inspection intervals: the numbers come from API 653","paragraphs":["The routine in-service external inspection is a visual walk-down by owner-operator personnel, and it does not require a certified inspector. Most operators run it monthly. It is not a substitute for the formal external inspection, which must be performed by an API 653 Authorized Inspector at an interval not exceeding the lesser of 5 years or RCA/4N years, where RCA is the remaining corrosion allowance on the shell and N is the shell corrosion rate. Ultrasonic thickness measurement of the shell follows its own clock under Section 6.3.3: the lesser of RCA/2N or 15 years where the corrosion rate is established, and 5 years where it is not.","Internal inspection is the expensive one and therefore the one under permanent commercial pressure. API 653 Section 6.4 requires the initial internal inspection within 10 years where the soil-side corrosion rate is unknown, and caps subsequent intervals at 20 years. A risk-based inspection assessment under Section 6.4.3 can push that further, to an absolute ceiling of 30 years, but the assessment has to be documented, performed by qualified personnel, and reassessed on a defined cycle. The recurring finding is not that an owner extended an interval — it is that the extension was granted once, in a study dated eleven years ago, and never revisited.","Every one of those intervals is computed from thickness data, and that is where programmes quietly fail. If a corrosion rate is derived from readings taken at locations that cannot be reproduced — no permanent marking, no condition monitoring location map, no photograph — then the rate is arithmetic without provenance and the interval built on it collapses under questioning. Keeping location, date, procedure revision, equipment and technician bound to each reading is a data-management problem before it is an inspection problem, and it is precisely what [mechanical integrity software](/mechanical-integrity-software) exists to solve."]},{"heading":"Acceptance criteria and where they actually come from","paragraphs":["API 575 contains no acceptance criteria. Shell evaluation is API 653 Section 4.3, where the minimum acceptable thickness for the one-foot method is t-min = 2.6 D (H − 1) G / (S E), with D the tank diameter in feet, H the height from the bottom of the course under consideration to the maximum liquid level, G the specific gravity, S the allowable stress and E the joint efficiency. Two errors recur: using the original design corrosion allowance as if it were the acceptance limit, and averaging thickness over a length the code does not permit when evaluating a locally thin area.","Bottom evaluation is Section 4.4. The criterion is a minimum remaining thickness projected to the next scheduled internal inspection — commonly 0.100 in. for a bottom with no release prevention barrier and 0.050 in. where one is fitted, per Table 4.4 — and the projection depends on the corrosion rate, which depends again on the quality of the data. The critical zone within 3 in. of the shell has its own 0.100 in. floor, and applying the general bottom number inside that annulus is one of the most commonly written findings on a tank report, because it is where the shell-to-bottom weld carries load.","Repairs and alterations are Section 9, and the examination and testing that must follow them is Section 12. Bottom lap welds are proved with a vacuum box at a partial vacuum of at least 21 kPa (3 psi) gauge, consistent with API 650 Section 7.3.7. Where a report reaches an owner from a contractor and the acceptance basis is unclear, an [independent review of the inspection reports](/report-validation) before the data feeds a fitness-for-service decision is cheap insurance — misapplied acceptance criteria are far easier to catch on paper than after a tank has been returned to service."]},{"heading":"Bottom inspection: MFL, prove-up and coverage you can prove","paragraphs":["Magnetic flux leakage scanning is the standard screening tool for tank floors, and its limitation is structural rather than incidental: MFL detects volumetric metal loss and locates it, but it does not size it reliably. Every reportable indication requires ultrasonic prove-up to a documented technique, and the prove-up record — not the scanner output — is what supports the corrosion rate. Sensitivity is also a function of lift-off. A thick reinforced lining or a heavy coating degrades detection substantially, and the lining thickness is very often nowhere in the report.","API 653 Annex G exists precisely to close this gap: bottom examination procedures are qualified by demonstration against plates containing known through-wall loss, and the demonstration establishes what the procedure can and cannot find. Where a contractor has never demonstrated the procedure in use, the coverage claim on the report has no supporting evidence behind it. An auditor who asks for the Annex G qualification record and receives a scanner brochure has learned everything they need to know about that programme.","The other half of the problem is what was not scanned. Areas under the sump, inside the annular ring lap, around support columns and legs, beneath heating coils, and in the critical zone next to the shell are all difficult or impossible for a scanner to reach — and they are where corrosion concentrates. Those areas need a documented manual ultrasonic grid or an explicit, mapped exclusion. A report claiming one hundred per cent floor coverage, with eight per cent of the floor physically inaccessible and no coverage map in the package, is the single most common bottom-inspection finding in terminal audits."]},{"heading":"Settlement, foundations, and the survey nobody plans for","paragraphs":["API 653 Annex B separates settlement into categories that behave completely differently. Uniform settlement is largely harmless to the tank, though it matters for nozzle and piping loads. Planar tilt is evaluated against floating roof clearance and nozzle strain. Out-of-plane settlement is fitted to a cosine curve and assessed against permitted deviation. Edge settlement — the localised dishing of the bottom near the shell — is the one that cracks the shell-to-bottom weld, and its criteria differ depending on whether the settlement is contained within a bottom lap weld or crosses a breakover.","The survey itself is prescriptive: measurement points at a maximum spacing of 32 ft (10 m) around the circumference, with a minimum of eight points. That minimum is a floor, not a target. On a large-diameter tank, eight points describe a shape only very approximately, and two surveys taken from different reference marks are not comparable at all. Where a repeatable baseline matters — a tank on questionable foundation, or one being monitored between internals — [3D laser scanning services](/3d-scanning-services) produce a continuous surface rather than eight elevations, and the same registration can be re-occupied years later.","Settlement that passes the shell criteria can still be operationally intolerable. A floating roof that binds, a rim seal lifted off the shell, a roof drain that no longer drains, a shell that is out of round enough to jam the roof at one azimuth — none of these are failures of the shell calculation, and all of them are consequences of foundation movement. API 575 is unusually good on this point, and it is worth reading its foundation section before commissioning a survey rather than after."]},{"heading":"The misreadings that turn into audit findings","paragraphs":["First, citing API 575 as the inspection code. It is a recommended practice; write API 653 on the report and cite 575 as supporting practice. Second, applying the general bottom minimum thickness inside the critical zone. Third, treating the monthly routine external walk-down as satisfying the formal external inspection — it does not, because that inspection must be performed by an API 653 Authorized Inspector against Section 6.3.2 and recorded as such.","Fourth, extending an internal inspection interval by risk-based inspection and then never reassessing it. The 30-year ceiling is not a licence; it is the outer bound on a live assessment that has to be maintained. Fifth, deriving corrosion rates from condition monitoring locations that were never permanently marked, which makes every subsequent interval calculation unverifiable. Sixth, and increasingly common, accepting an MFL coverage claim without a coverage map or an Annex G procedure qualification behind it.","The seventh is quieter and does more damage than the rest. An owner assumes that because a cathodic protection system was installed, soil-side corrosion is controlled and the bottom corrosion rate is near zero. API 651 expects an annual structure-to-electrolyte potential survey — normally a −850 mV instant-off criterion against a copper/copper-sulphate reference, or 100 mV of polarisation — plus rectifier output readings at least every two months. Finding a rectifier that has been off since the last turnaround does not just generate a finding; it invalidates the corrosion-rate assumption every interval in the programme was built on."]}],"faq":[{"q":"Can an inspection report cite API 575 as its governing document?","a":"Not on its own. API 575 is a recommended practice describing how to inspect; API 653 is the in-service code that sets intervals, acceptance criteria and repair rules, and it is what regulators and client specifications invoke. Reports should be written to API 653 with API 575 cited as supporting practice for method selection and technique."},{"q":"What is the difference between API 575 and API 653?","a":"API 575 tells you how to inspect a storage tank — components, damage mechanisms, methods, checklists. API 653 tells you when to inspect, what thickness is acceptable, how to evaluate settlement and locally thin areas, how repairs and alterations must be performed, and who is authorised to sign the tank back into service."},{"q":"Does API 575 apply to shop-fabricated tanks?","a":"It covers API 12D and 12F shop-fabricated tanks and 12B bolted tanks as part of its population. Whether the compliance programme for a given shop-fabricated tank runs to API 653 or to STI SP001 is a separate decision driven by the tank's size, service and jurisdiction, and the owner should have that choice documented rather than assumed."},{"q":"How do RCA and N work in the API 653 interval formulas?","a":"RCA is the remaining corrosion allowance — measured thickness minus the calculated minimum acceptable thickness — and N is the corrosion rate in the same units per year. External inspection runs at the lesser of 5 years or RCA/4N; shell ultrasonic thickness at the lesser of 15 years or RCA/2N where the rate is known. Both collapse if the underlying readings are not reproducible."},{"q":"Who can perform the routine external inspection between formal inspections?","a":"Owner-operator personnel, typically on a monthly cycle, using a structured checklist of the kind API 575 provides. No NDT or API certification is required for that walk-down. The formal external inspection at the 5-year or RCA/4N interval is a different activity and must be performed and certified by an API 653 Authorized Inspector."},{"q":"What NDT support does Atlantis provide around API 653 tank programmes?","a":"Technical authority on the NDT side: written practice and procedure development and qualification, personnel certification within the employer's written practice, bottom examination procedure demonstration under API 653 Annex G, independent review of contractor inspection data, and inspection data management. Start with a [consultation](/contact) describing the tank population and the current programme."}]}