How API 570 and API 510 Treat CUI in Inspection Plans

Short answer: Both codes make corrosion under insulation (CUI) a required part of the inspection plan for insulated equipment that operates in, or cycles through, the susceptible temperature range. API 570 gives piping a structured follow-up: an external visual on every susceptible system, then NDE or insulation removal on a target share of damaged and suspect locations that rises with piping class. API 510 has no percentage table. It lists the susceptible ranges and locations for vessels and asks the inspector to justify how much insulation comes off.

This guide is for mechanical-integrity engineers, inspection supervisors and plant inspectors in the US and Canada who have to write or defend a CUI section in a piping or vessel inspection plan. It explains what each code says, where the two differ, how the follow-up work is chosen, and which records an inspector expects to see. It does not replace the codes. API 570 is in its fifth edition (February 2024) and API 510 in its eleventh edition (October 2022, with errata). Some figures quoted here come from the API 570 fourth edition (2016), and they are labelled that way. Check every number against your licensed copy of the current edition and against your jurisdiction. The owner and the owner's API-certified inspector set scope and intervals.

Why CUI gets its own place in both codes

Direct answer: CUI is written into the codes because it cannot be seen from outside. Insulation and jacketing hide the steel, water gets in at breaks and penetrations, and the corrosion is usually local. Spot thickness readings at fixed CMLs rarely land on it. So the codes require a deliberate look for CUI on top of the normal thickness programme.

Both codes define CUI the same way. It is external corrosion caused by water trapped under insulation. In austenitic and duplex stainless steels it shows up as external chloride stress corrosion cracking (ECSCC), which both codes also count as CUI damage. That definition matters for planning. On carbon and low-alloy steel you are looking for wall loss, often patchy and well away from where the CMLs sit. On stainless you are looking for cracks, which need a different NDE method. Our guide to chloride stress corrosion cracking covers the stainless side in detail.

Both codes also point to the same supporting document, API RP 583 (Corrosion Under Insulation and Fireproofing), for the detail they do not carry themselves. API RP 583 covers susceptibility ranking, inspection techniques with and without insulation removal, and the link to fireproofing (CUF). The in-service codes say what must be done. RP 583 explains how to do it well. A CUI section that cites only API 570 or API 510, and never mentions how API RP 583 was used, usually reads as thin to an auditor.

A third reason is practical. Thickness readings taken through insulation plugs can create CUI. Every inspection port is a possible water path. API 510 says outright that CML sealing systems, such as plugs, must be kept in place so insulation covers stay sealed. A CUI programme that ignores the damage caused by the thickness programme is only half a programme.

What API 570 requires for piping CUI

Direct answer: API 570 asks the owner to consider CUI inspection on insulated carbon and low-alloy piping in the susceptible range. It requires an external visual for CUI on every susceptible system at the class interval, then additional NDE or insulation removal at a target share of damaged-insulation and suspect locations. The extent widens if significant CUI is found.

The fourth edition (2016) puts this in two places. A CUI clause in the inspection-practices section sets the temperature trigger. Inspection for CUI should be considered for externally insulated carbon and low-alloy piping operating between 10 °F (−12 °C) and 350 °F (175 °C). That clause also says CUI may occur where insulation looks fine, and it names non-intrusive techniques that help: real-time radiography to see scale behind the insulation, and profile radiography, pulsed eddy current and guided wave examination to locate damage. It lists factors that favour removing insulation. These include CUI history, the condition of the jacketing (rust stains, biological growth, bulging), signs of leaks, intermittent service, coating age, wet insulation, water-holding insulation types such as calcium silicate, low points of sagging lines, the bottoms of vertical runs, nearby sources of humidity such as cooling towers, and lines whose temperature moves in and out of the CUI range.

A second clause, on the extent of visual external and CUI inspections, sets the sequence:

1. External visual on all CUI-susceptible systems. It runs on the class interval from the code's recommended-maximum-interval table, or on an RBI-based due date if the owner has a valid RBI assessment under API RP 580. The visual also assesses insulation condition, and the results must be documented so the follow-up can be planned.
2. Additional CUI examination. The code sets the extent and type in a dedicated table. Damaged insulation high on a line may cause CUI lower down, away from the visible damage. The code says radiography, or insulation removal with a visual, is normally required at damaged or suspect locations, and other NDE may be used where it applies.
3. Escalation. If the damaged or suspect areas show significant CUI, more areas should be inspected and, where warranted, up to 100% of the circuit.

The table gives target percentages by class, with Class 1 highest and Class 4 optional. The fourth edition listed approximately 75% of damaged-insulation locations and 50% of suspect locations without visible damage for Class 1. It listed 50% and 33% for Class 2, and 25% and 10% for Class 3. A note explains that the two columns are separate populations, not a cumulative sequence. The fifth edition carries the same structure. Confirm its exact values in your licensed copy before you write them into a plan. Our piping service classes guide explains how the class is assigned, because the class drives both the visual interval and the CUI target.

Targets, not quotas: how API 570 lets owners adjust

Direct answer: API 570 calls the table percentages targets for systems with no CUI inspection experience. Facilities with real CUI data may raise or lower them, an exact accounting is not required, and some systems can be excluded from the NDE targets. Every adjustment needs a recorded basis.

The fourth edition names the factors that move the likelihood of CUI: local climate, insulation design and maintenance, coating quality, and service conditions. A Gulf Coast refinery with salt air, heavy rain and older calcium silicate insulation is a different case from a dry inland plant with cellular glass and a good coating under it. The code lets the owner reflect that. It also says the owner may confirm targets with operating history or other documents.

Two groups of piping need not be included in the table-driven NDE:

• Systems known to have a remaining life of more than 10 years.
• Systems adequately protected against external corrosion. The fourth edition's examples are piping insulated so that moisture cannot enter, jacketed cryogenic piping, piping in an inert-purged cold box, and piping held at a temperature low or high enough to keep water out.

Even for these, the code expects operating or other personnel to look at the insulation or outer jacketing periodically and report any deterioration to the inspector. An exclusion is a decision, so it belongs in the plan with its reason. "Coated before insulation in 2015, coating type X, no CUI found in two prior campaigns" is a basis. "Low risk" on its own is not.

In practice, adjustment works both ways. A site that keeps finding CUI at the bottoms of vertical runs or at pipe supports should push its targets up at those features, not just meet the circuit-level percentage. A site with years of clean findings on well-coated lines can use that record to justify lower targets. What an auditor looks for is the link between the data and the number chosen.

What API 510 requires for vessel CUI

Direct answer: API 510 (11th edition) says CUI inspection shall be considered for externally insulated vessels, and those in intermittent service, operating in three material-specific ranges. It lists the most susceptible locations on vessels and leaves the amount of insulation removal to a risk-based judgement against named factors. There is no percentage table.

The temperature ranges in the eleventh edition are:

• Carbon and low-alloy steels: −12 °C (10 °F) to 177 °C (350 °F).
• Austenitic stainless steels: 60 °C (140 °F) to 177 °C (350 °F).
• Duplex stainless steels: 138 °C (280 °F) to 177 °C (350 °F).

The code adds a point that catches many plans out. A vessel may run outside the CUI range and be judged not susceptible, while its nozzles and supports pass in and out of the range. Those penetrations need their own susceptibility call, and it must be recorded in the inspection plan.

For locations, API 510 notes that CUI on carbon and low-alloy steel is usually local, though vessels in sweating service may show general loss with local attack where the coating has failed. It lists the most susceptible spots on vessels: above insulation or stiffening rings, at nozzles and manways, at other penetrations such as ladder clips and supports, at damaged insulation where water can get in, at failed caulking, on top and bottom heads, and anywhere else that traps water. It also warns that CUI can turn up in unpredictable places. If CUI is found, the inspector should look at other susceptible areas on the vessel.

On insulation removal, the code says CUI may be active under insulation that looks good. Where the jacketing is in good condition and there is no reason to suspect damage, the insulation need not be removed. The amount removed depends on the risk of an incident caused by CUI. The listed factors include the consequence of a CUI leak, CUI history on the vessel or similar equipment, the condition of the covering, signs of leakage, intermittent service, the age and condition of the coating under the insulation, water-holding insulation types, whether specialised NDE can find CUI without removal, and sweating service. The code also notes a practical limit: many NDE techniques used for CUI on small-diameter piping do not scale to vessel diameters, so removing insulation windows is more common on vessels. Thickness readings taken from inside during an internal inspection may help, but CUI is often so local that it is hard to find from the inside.

API 510 also adds corrosion under fireproofing (CUF). External inspections must check fireproofing on shells and supports for spalling, cracking, bulging and rust stains, with further investigation where damage is found.

API 570 vs API 510 on CUI, side by side

Direct answer: The codes agree on the definition and the damage. They differ in how scope is set. API 570 uses class-based target percentages after a visual. API 510 uses a location list and a factor-based removal decision. The upper temperature limit is 350 °F in both, but the Celsius values differ slightly (175 °C in API 570 4th edition, 177 °C in API 510 11th edition).

For a site that runs both codes, the cleanest approach is one CUI susceptibility method for both piping and vessels, with code-specific rules applied at the end. Piping gets its class-based targets. Vessels get the location list and a removal decision per vessel. The data from both feeds the same picture of where water gets in on that site.

Building CUI into the inspection plan: a worked example

Direct answer: A defensible CUI section moves through five steps. Screen for susceptibility, run the visual, choose follow-up locations and methods, escalate on findings, then record and feed the results back. Each step leaves a record the inspector can point to.

Consider, as a qualitative example, a Class 2 hydrocarbon circuit of insulated carbon steel that cycles between ambient and about 250 °F during regeneration. It shares a unit with a carbon steel separator that normally runs above 400 °F but has nozzles and a skirt that sit cooler.

1. Susceptibility screen. The circuit cycles through the carbon steel CUI range, so it is susceptible. The separator shell runs above the range, so the shell may be judged not susceptible. Its cooler nozzles, skirt attachment and insulation-support ring may still sit in the range, so they are marked susceptible on their own. The basis, with operating data, goes in the plan.

2. External visual. On the circuit, the inspector walks the line at the class interval. They record jacketing breaks at a valve and two supports, bulged jacket at a low point, failed caulking at a vertical-to-horizontal transition, and old insulation plugs left from a previous campaign. On the separator, they note a cracked cap at the insulation ring and stains below one nozzle.

3. Follow-up selection. For the circuit, the owner's plan applies the Class 2 targets from the current edition of API 570. A share of the damaged-insulation locations and a separate share of suspect locations without visible damage get NDE or insulation removal. Low points, support points and the bottoms of vertical runs are chosen first. Methods are picked to suit the line. Profile radiography suits the smaller-bore sections and fittings. Pulsed eddy current can screen the larger straight runs through the jacketing. Insulation windows with visual and UT go where screening flags something. For the separator, the inspector selects windows at the insulation ring and the stained nozzle, because the vessel diameter makes through-insulation methods less useful there.

4. Escalation. Profile RT at the low point shows significant wall loss. Under API 570 this widens the scope: more locations on the circuit, and up to 100% of it if the findings warrant. The engineer works out a corrosion rate and remaining life from the measured thickness. The inspector decides whether the next interval, or a repair, changes.

5. Record and feedback. The findings go into the plan as CUI history. That history is what allows the site, later on, to argue for higher or lower targets on similar lines. The damaged jacketing is listed for repair, and the insulation plugs are resealed or removed.

In this example the NDE contractor produces images, readings and a report. The owner's inspector decides the scope, accepts the results and sets the next date. That split of roles follows the codes. The piping circuit and CML page shows how CUI findings sit beside the routine thickness data.

NDE methods for CUI follow-up and what each can tell you

Direct answer: No single method covers every CUI case. Profile radiography and insulation removal with visual and UT give the most direct evidence of wall loss. Pulsed eddy current and guided wave are screening tools that need confirmation. Wet-insulation surveys find water, not corrosion. Stainless steel needs crack-detection methods.

Each method needs a written procedure and qualified personnel under the employer's written practice, and the plan should name what each method can and cannot detect. Our NDE method selection guide sets CUI alongside other damage mechanisms.

Documentation the inspector expects to see

Direct answer: Expect to show the susceptibility basis, the visual results, the follow-up locations and methods with the reason for each, the escalation decisions, any adjustments to targets or exclusions with their basis, and the resulting corrosion rates. Missing reasons are the most common gap.

• Susceptibility list. Which systems, circuits and vessel zones are in scope, based on material, operating and upset temperatures, intermittent service and penetrations that cross into the range.
• Visual records. Dated findings by location, with photos where they help. API 570 says the visual results should be documented so follow-up can be planned.
• Follow-up selection. The locations chosen, how they relate to the targets in API 570 (piping) or to the risk factors in API 510 (vessels), and the method used at each.
• NDE reports. Procedure reference, technique, personnel qualification, calibration or reference standard, results and any limits on coverage.
• Escalation record. What was found, what extra scope it triggered, and why the inspector stopped where they did.
• Adjustments and exclusions. The data used to raise or lower targets, and the basis for any system left out.
• Repairs and reinstatement. Jacketing repairs, resealed plugs and coating work, so the next campaign starts from a known state.

Under OSHA's process safety management standard (29 CFR 1910.119(j)), covered processes need written mechanical-integrity procedures, inspection and testing that follow recognised and generally accepted good engineering practice, and documentation of each inspection. API 570 and API 510 are commonly treated as that practice. A CUI section without its basis is hard to defend in a PSM audit.

Common mistakes in CUI plans

Direct answer: The usual errors are treating the table as the whole programme, skipping penetrations on hot vessels, using old temperature ranges, ignoring damage caused by inspection ports, and not escalating when CUI is found.

• Counting percentages instead of choosing locations. Meeting a target with easy, dry locations defeats its purpose. Low points, supports, vertical-run bottoms and jacketing breaks come first.
• Using an old edition's temperature range. The ranges have been revised between editions and across documents. Take them from the current API 570, API 510 and API RP 583, and record which edition the plan uses.
• Missing the penetrations. Hot vessels and lines get marked "not susceptible", while their nozzles, supports and dead-ended branches sit in the range.
• Forgetting intermittent and idle service. Lines that are normally hot but sit cold during outages, or cycle with regeneration, are susceptible.
• Screening without confirmation. A guided wave or PEC call is a reason to look, not a thickness for a remaining-life calculation.
• Leaving plugs open. API 510 specifically asks for CML sealing systems to stay in place. An unsealed plug is a planned water entry point.
• Not escalating. API 570 expects more scope, up to the whole circuit, when significant CUI is found. Logging the finding and moving on is a gap.
• Applying piping rules to vessels. API 510 has no percentage table. Copying Class 2 percentages onto a vessel is not what the code asks for, though nothing stops an owner from using its own targets as part of a risk-based decision.

Jurisdiction and Canada notes

Direct answer: The codes set the method, but regulators decide whether and how they apply. In the US that means OSHA PSM for covered processes and state boiler and pressure vessel laws for vessels. In Canada it means provincial regulators that adopt CSA B51 and their own requirements. Confirm the rules with your jurisdiction.

In the US, many states regulate pressure vessels through a state boiler and pressure vessel programme. Some accept owner-user inspection programmes based on API 510 or the National Board Inspection Code (NBIC). Process piping is less often covered by state law, so for most refining and chemical sites the main driver for API 570 is the OSHA PSM good-practice requirement and the owner's own standards. EPA's Risk Management Program (40 CFR 68) has similar mechanical-integrity expectations for covered processes.

In Canada, boilers, pressure vessels and pressure piping are regulated by the provinces and territories, generally under CSA B51 together with provincial acts and regulations. Examples include ABSA in Alberta and TSSA in Ontario. An owner-user programme there must satisfy the provincial authority as well as the API code it is built on, and the regulator's documents may add requirements for CUI or for inspection intervals. Check with the authority having jurisdiction before you rely on any of the code flexibility described above.

Wherever you are, interval and acceptance decisions stay with the owner's inspector and engineer under the code and the jurisdiction. RBI under API RP 580 can change visual intervals and CUI scope, but it is an engineering assessment the owner commissions and documents. It is not a shortcut around the CUI requirements. For how the intervals interact, see time-based vs risk-based intervals.

How Atlantis supports this

Atlantis NDT performs the CUI NDE that the owner's inspection plan specifies on piping and vessels. That includes profile radiography by licensed crews, UT and corrosion mapping at insulation windows, guided wave screening, and crack detection on stainless steel, all under ASNT Level III oversight. We deliver results to the owner's API 570 or API 510 inspector, who stays inspector of record and decides scope, escalation and intervals. Atlantis does not act as the authorized inspector and does not offer RBI or fitness-for-service assessments. See our CUI inspection services and pressure vessel inspection services. Ask for a CUI NDE scope and quote. We respond within 24 hours.

Frequently asked questions

What are the API 570 CUI inspection requirements?

API 570 requires an external visual for CUI on all susceptible insulated piping at the class interval. It then expects NDE or insulation removal at a target share of damaged-insulation and suspect locations, with more scope, up to the whole circuit, if significant CUI is found. Check the current fifth edition for exact wording.

What is the API 570 CUI table?

It is the table of recommended CUI inspection extent after the visual, set by piping class. The fourth edition listed about 75%, 50% and 25% of damaged-insulation locations for Classes 1, 2 and 3, and about 50%, 33% and 10% of suspect locations without damage, with Class 4 optional. Confirm the values in your current copy.

Are the API 570 CUI percentages mandatory?

The code calls them targets for systems with no CUI inspection experience. Facilities with experience may increase or reduce them, an exact accounting is not required, and systems with more than 10 years of remaining life or adequate protection may be excluded from the NDE. Record the basis for any change.

What temperature range does API 570 use for CUI?

The fourth edition used 10 °F to 350 °F (−12 °C to 175 °C) for carbon and low-alloy steel piping. Ranges have changed between editions, so take the current figure from the fifth edition and API RP 583.

Does API 510 have a CUI inspection percentage like API 570?

No. API 510 lists susceptible temperature ranges and locations on vessels and asks for a risk-based decision on insulation removal, using factors such as consequence, history, covering condition and coating age.

What is the API 510 CUI temperature range?

The eleventh edition lists −12 °C (10 °F) to 177 °C (350 °F) for carbon and low-alloy steels, 60 °C (140 °F) to 177 °C (350 °F) for austenitic stainless, and 138 °C (280 °F) to 177 °C (350 °F) for duplex stainless. Intermittent service is included.

Where does CUI occur on pressure vessels?

API 510 lists areas above insulation or stiffening rings, nozzles and manways, penetrations such as ladder clips and supports, damaged insulation, failed caulking, top and bottom heads, and anywhere water collects. It adds that CUI can be unpredictable.

Can profile radiography replace insulation removal for CUI?

Often, on smaller piping. API 570 names radiography as a normal follow-up at damaged or suspect locations. Profile RT shows wall loss without stripping, but it is less precise than UT, so confirm critical readings by UT at a window when remaining life is close.

How does RBI change CUI inspection under API 570?

API 570 allows external visual intervals or due dates to come from a valid RBI assessment under API RP 580. RBI is an engineering assessment the owner commissions. It still has to address CUI likelihood and consequence for each system.

Who decides how much insulation to remove?

The owner's inspector, working with the corrosion specialist or engineer under the owner's programme. NDE contractors carry out the work and report results. They do not set the scope.

Talk to an NDE Level III about your CUI campaign or request profile RT and insulation-window UT for your next outage.