What Governs External Inspection Intervals for Atmospheric Storage Tanks

In-service tank inspection: what the inspector actually checks

Short answer: An in-service tank inspection is everything done to an aboveground storage tank while it stays full and operating. Under API 653 that means the routine visual by site personnel, the formal external inspection by an authorized inspector, and the external ultrasonic thickness program. The inspector walks the tank from foundation to roof, records leaks, distortion, settlement, corrosion, coating and insulation condition, and checks grounding, appurtenances and cathodic protection records. Internal floor condition waits for the out-of-service inspection.

The interval rules above tell you when each clock falls due. This section covers the other half of the question people search for: what an in-service tank inspection consists of on the day, component by component, which NDE methods are practical while product is in the tank, what the report has to contain for the interval arithmetic to stand up, and how the same job looks on a shop-built tank inspected to STI SP001 rather than API 653. Inspection practice detail for tanks sits in API RP 575, Inspection Practices for Atmospheric and Low-pressure Storage Tanks, which API 653 points to; we describe the practice in our own words here, so check the current editions of API 653 and RP 575 for the exact text. API 653 is currently the 5th edition with Addendum 4 issued in July 2025, which revised several clauses including tank-bottom thickness measurement text, so confirm which edition and addendum your program references.

Who does what during an in-service inspection

Three parties are usually involved, and confusing their roles is the root of many audit findings. The owner or operator owns the tank, sets the inspection program, decides the extent of thickness measurements, and is responsible for acting on findings. The authorized inspector, an individual certified by API under the API 653 program and employed or engaged by an inspection agency acceptable to the owner, performs and signs the formal external inspection and evaluates the data. NDE examiners, such as UT thickness technicians certified under an SNT-TC-1A written practice, produce measurements and examination results that the authorized inspector uses.

The monthly routine inspection may be performed by owner or operator personnel who are not authorized inspectors, provided they know the facility, the tank and the product. That inspection is a feeder: anything abnormal it finds is supposed to be documented for follow-up by an authorized inspector. The best programs give the routine inspector a checklist that mirrors the formal external inspection, so observations arrive already located and photographed.

Where an engineer is needed, for example to evaluate settlement beyond what the inspector can accept, or to assess a locally thinned shell area, the owner commissions that evaluation. It is not part of the NDE scope and not part of the routine inspection. API 653 itself contains evaluation procedures, and some owners commission fitness-for-service assessments under API 579-1/ASME FFS-1 for unusual findings; those are engineering decisions made by the owner and its engineers.

Component-by-component: the external walkdown

A formal external inspection follows the tank from the ground up. The order matters less than completeness, but working bottom to top keeps the inspector from missing the foundation, which is where many in-service problems first show.

Foundation and grade. The inspector looks for settlement around the perimeter, erosion or washout of the pad, vegetation and standing water against the chime, cracking and spalling of concrete ringwalls, and gaps between the bottom projection and the foundation that let water reach the underside of the floor. Distorted anchor bolts and heavily cracked concrete around them can indicate foundation settlement or an uplift condition and should be dimensioned, not just noted.

Bottom projection and chime. The exposed edge of the bottom or annular plate is one of the few places the floor can be seen while the tank is in service. Corrosion at the chime, especially where soil, gravel or a sealant traps water, is checked visually and with UT where the edge is accessible. Many owners fit a chime seal or weather shield; its condition is recorded because a failed seal turns into soil-side bottom corrosion.

Shell. The shell is examined for external corrosion, paint failure, leaks or weeps at seams and nozzles, dents, bulges and out-of-roundness, and signs of buckling near the bottom course or under wind girders. Riveted shells get particular attention at seams and rivet heads. Where the shell is insulated, insulation is removed only to the extent needed to judge the condition of the shell, so the inspector targets the places water collects: around nozzles and supports, at insulation terminations and at damaged jacketing.

Nozzles, piping connections and appurtenances. Reinforcing pads, telltale holes, nozzle necks and the first flange are checked for leaks, corrosion and cracking. Piping should not be imposing visible strain on shell nozzles, a common issue after settlement. Manways, gauge hatches, mixers, heaters, level gauges and sample connections are inspected for leaks and mechanical condition.

Grounding and electrical continuity. Grounding cables, shunts and mechanical connections are visually checked; API 653 refers to API RP 2003 for ignition-prevention practice. On floating-roof tanks, shunts between roof and shell are part of this check.

Stairways, platforms and wind girders. Structural members, treads, handrails and their attachments to the shell are checked for corrosion and loose connections. Wind girders are inspected for corrosion and for water traps that are corroding the shell beneath them.

Roof. Fixed roofs are checked for corrosion, pitting, holes and deformation, ponding, and the condition of vents and pressure-vacuum valves. Roof access is a safety decision: a corroded roof can fail under a person's weight, so the inspector confirms condition, often by UT at the perimeter and visual from the platform, before walking on it. External floating roofs are checked for pontoon leaks, drains, seal condition, ladder and guide pole condition, and whether the roof sits level. Internal floating roofs are generally viewed through roof hatches with appropriate atmospheric precautions.

Containment and leak detection. Dikes, drains and release prevention barriers are part of the facility's spill control, and leak detection ports or interstitial monitoring are checked where fitted. Leak detection history is one of the factors API 653 lists for setting inspection frequency, so its condition belongs in the report.

NDE that works while the tank is in service

Most NDE on an operating tank is done from the outside, which limits what can be learned about the floor. The table summarises what each method contributes during an in-service inspection and where its limits are.

The honest summary is that the floor is the blind spot of an in-service tank inspection. Floor thickness, product-side pitting and the soil-side corrosion that drives most internal intervals can only be measured properly when the tank is empty, cleaned and gas-free, usually with magnetic flux leakage floor scanning and UT prove-up. In-service techniques such as chime inspection, leak detection data, CP surveys and acoustic emission screening tell the owner whether the floor is likely to be deteriorating faster than the interval assumed; they do not establish the minimum remaining bottom thickness. See MFL vs UT floor scanning for what happens at the out-of-service inspection.

Taking shell UT readings that support the arithmetic

External UT thickness data is what turns an in-service inspection into an interval. RCA and N cannot be computed from a visual, and a corrosion rate cannot be defended unless the readings are repeatable. Three practices make the difference.

First, fixed measurement locations. Readings should be taken at the same marked or mapped points each time: typically on each shell course, with additional points near the bottom of the first course, at the liquid-vapour interface zone where corrosion often concentrates, and at areas with known damage. The owner decides the extent, but changing the locations from survey to survey destroys the rate.

Second, technique control. The procedure should state transducer type, calibration method, how coatings are handled (echo-to-echo or coating removal), temperature correction, and how the minimum reading in a grid is recorded. A spot reading on a painted shell with a single-echo gauge can read coating plus steel; a subsequent survey with an echo-to-echo technique will then appear to show corrosion that did not happen.

Third, scanning where it matters. Spot readings at a fixed grid are designed for uniform corrosion. Where the visual inspection shows pitting, chime corrosion, or corrosion under a wind girder or insulation, the inspector should call for scanning or corrosion mapping of that area so that the minimum thickness, not an average, feeds the evaluation. Our corrosion mapping page explains the difference.

The output the authorized inspector needs is a table per shell course: location ID, current and previous thickness, the date of each, and the instrument and technique used. With that, RCA, N and both external clocks can be recalculated and checked by anyone. Ask us to scope a shell UT survey.

What the in-service inspection report should contain

An in-service inspection that cannot be reconstructed from its report is, for audit purposes, an inspection that did not happen. A defensible report usually contains:

• tank identification, product and specific gravity, design data and the edition of API 653 applied;
• the authorized inspector's name and certification number, and the NDE examiners' certification levels;
• the scope actually performed, including what was not accessible and why;
• findings by component with locations, dimensions and photographs, not adjectives;
• shell thickness data by course and location, with previous data for comparison;
• minimum required thickness used, RCA, corrosion rate and the resulting next external and UT dates;
• settlement survey results where taken, and the evaluation basis;
• cathodic protection survey reference and confirmation that the owner reviewed it;
• recommendations, separated into immediate actions, items for the next internal inspection, and monitoring items;
• open findings from monthly routine inspections and how they were closed.

Shop-built tanks: STI SP001 instead of API 653

Many in-service tank inspection searches come from facilities with shop-fabricated tanks, such as horizontal and vertical fuel tanks at terminals, plants and fleet yards, where API 653 is not the natural fit. The Steel Tank Institute's STI SP001, Standard for the Inspection of Aboveground Storage Tanks, covers shop-built tanks of all common configurations, including double-wall and diked tanks, and field-erected tanks up to a limited size, along with portable containers.

SP001 uses the same tiered idea as API 653 but different vocabulary. Periodic monthly and annual inspections are done by the owner's inspector, a person familiar with the site who can identify changes. Formal external inspections, and formal internal inspections where required, are done by a certified inspector, either STI-certified or API-certified with the additional STI qualification. The required tier depends on the tank category, which SP001 sets from the presence of spill control and a continuous release detection method, and on tank size. STI publishes monthly and annual checklists that many facilities use as their routine inspection record; the current checklists are associated with the 7th edition, so confirm the edition your SPCC plan references.

For SPCC-regulated facilities, 40 CFR 112.8(c)(6) requires containers to be tested or inspected for integrity on a regular schedule according to industry standards, and both API 653 and STI SP001 are commonly cited in SPCC plans as those standards. The choice of standard for each tank, and any engineer-certified deviations, belong in the plan, so check that the inspection you buy matches what the plan says.

Regulatory overlay and Canada

API 653 is an industry standard; regulation is what makes it mandatory. In the USA, SPCC facilities rely on it or STI SP001 under 40 CFR 112, PHMSA breakout tanks are tied to API 653 by 49 CFR 195.432 with additional calendar requirements, and process safety management sites treat it as recognised and generally accepted good engineering practice for mechanical integrity under OSHA 1910.119(j). State fire codes and environmental agencies can add requirements, so confirm with your jurisdiction.

In Canada, tank inspection requirements come from provincial and territorial fire codes and environmental regulations, the federal Storage Tank Systems for Petroleum Products and Allied Petroleum Products Regulations for federally regulated sites, and the Canada Energy Regulator for federally regulated pipeline terminals. Many Canadian operators apply API 653 for field-erected tanks and ULC or STI standards for shop-built tanks; confirm the requirement with the applicable regulator.

How Atlantis supports in-service tank inspections

Atlantis performs the NDE that in-service tank inspections need: shell UT thickness surveys at owner-defined locations, corrosion mapping of suspect areas, MT and PT of nozzle and attachment welds, visual examination support, and, at the out-of-service inspection, floor MFL scanning with UT prove-up. Our technicians are certified under an SNT-TC-1A written practice with ASNT Level III oversight of procedures. Results are delivered in a format your API 653 authorized inspector can use directly, and the authorized inspector remains the inspector of record. See aboveground storage tank inspection, ultrasonic testing and API 653 tank inspection support, or request a quote for in-service tank NDE; we reply within one business day.

More questions about in-service tank inspections

What is an in-service tank inspection?

It is the inspection of an aboveground storage tank while it remains in operation. Under API 653 it includes the monthly routine visual by site personnel, the formal external inspection by an authorized inspector, and external UT thickness measurements of the shell.

How often are in service tank inspections required?

Under API 653 the routine visual is at least monthly, the external inspection is the lesser of five years or RCA/4N, and shell UT follows its own interval. Jurisdictional rules, such as PHMSA requirements for breakout tanks, can add more frequent inspections.

Can the tank stay full during an in-service inspection?

Yes. API 653 allows the external inspection to be performed with the tank in operation. Internal inspection of the floor and inside surfaces requires the tank to be taken out of service, cleaned and made safe for entry.

Who can perform an in-service tank inspection?

The monthly routine inspection can be done by knowledgeable owner or operator personnel. The formal external inspection must be performed by an authorized inspector. UT thickness readings are taken by certified NDE technicians and evaluated by the authorized inspector.

What NDT is used for in-service tank inspection?

Visual examination, UT thickness readings and scanning of the shell, MT or PT where cracking is suspected, settlement surveys and cathodic protection surveys. Acoustic emission can screen the floor for active corrosion, but floor thickness needs an internal inspection.

Can you inspect a tank floor while the tank is in service?

Only indirectly. Chime inspection, leak detection data, CP surveys and acoustic emission screening indicate floor condition, but minimum remaining bottom thickness is measured during the out-of-service internal inspection, usually with MFL and UT.

Does an in-service inspection replace the internal inspection?

No. API 653 sets internal inspection intervals separately. An internal shell inspection can substitute for the external UT program under conditions in the standard, but not for the external visual or the routine inspection.

Is STI SP001 or API 653 used for shop-built tanks?

Shop-built tanks are usually inspected to STI SP001, which has its own monthly, annual and formal external inspection tiers based on tank category and size. API 653 is the usual standard for field-erected tanks built to API 650. The facility's SPCC plan should state which applies.

Have a tank due for its external inspection? Send us the tank list and last report and we will scope the UT survey for your authorized inspector. Related: API 653 internal and external intervals and settlement measurement and acceptance.

Sources: API standards catalogue (API 653 and API RP 575, current editions); 40 CFR 112.8; 49 CFR 195.432; STI SP001 annual inspection checklist. Confirm requirements against the current edition and addendum.