In-service inspection, repair, alteration, and rerating of process piping per ASME B31.3 — sets interval, CML, and class-based inspection extent.
Scope
API 570 — Piping Inspection Code — is the inspection-side companion to ASME B31.3 (Process Piping). API 570 governs in-service inspection of piping systems in petroleum, petrochemical, chemical, and similar process facilities. It applies to piping originally constructed to B31.3, B31.4, or B31.8 (with most application against B31.3). The scope includes hydrocarbon service piping, hazardous-service piping, and high-temperature piping in operating units. Utility piping (cooling water, instrument air) is generally excluded unless specifically incorporated by the operator's policy. API 570 establishes the Authorized Piping Inspector role, piping service classification system, inspection intervals per class, CML selection, and acceptance criteria for in-service piping. The current edition is the 5th Edition (December 2022) with Addendum 1 (2023).
Code compliance is only demonstrable if the evidence behind it is: the procedure revision in force, the inspector's certification state and the instrument's calibration status at the time of test. Atlantis NDT provides ASNT Level III consulting for procedure and written-practice work against this code, training toward the certifications that reference it, and inspection management software that keeps that evidence recoverable years later. Request a consultation.
How a standard like this is applied in an inspection programme
A standard is only half of the requirement. It defines how an examination is performed and, in some cases, how results are classified — but the acceptance criteria that decide whether a component stays in service normally come from the construction or in-service code governing the item, not from the examination standard itself. Confusing the two is one of the more common findings in a procedure review: a procedure that correctly cites the examination standard but applies acceptance criteria from the wrong code or the wrong edition.
What has to be in place for compliance to be demonstrable
A written procedure qualified against this standard for the specific materials, thickness ranges and geometries in scope — not a generic procedure covering everything
Personnel certified for the method and level under ASNT SNT-TC-1A, ANSI/ASNT CP-189, NAS 410 or ISO 9712, current on the date the examination was performed
Equipment, probes and reference standards in calibration on that date, with traceability to a national standard under ISO 17025
The applicable edition of the standard recorded against the examination, so historical work stays assessed under the edition then in force
Technique sheets under the same revision control as the procedure above them — the most frequently uncontrolled document in an otherwise compliant quality system
Edition changes
When a new edition is issued, new work moves to it from a defined effective date that you set and record; work already performed stays assessed under the edition in force at the time. Retrospectively applying a new edition to historical dispositions invalidates the original acceptance decision and creates a substantially larger problem than the one being solved.
Where this usually goes wrong
Not in the technical content, but in reconstruction. An auditor picks an issued report and asks which procedure revision applied, who performed the work and whether they were qualified on that date, and whether the instrument and reference blocks were in calibration. Programmes that hold only current state can answer none of those. Binding the document revision, the qualification state and the calibration state to each inspection record as it is created turns that from an investigation into a lookup.
API 570 is the in-service inspection code for metallic process piping. It divides a system into circuits, assigns each a class from the consequence of failure, and sets thickness measurement and external visual intervals by that class — with the calculated remaining life overriding any interval cap whenever it produces a shorter one.
Classing is consequence-driven rather than pressure-driven. Class 1 covers services where a release would do the most damage — flammables that flash on release, materials toxic at low concentration, hydrofluoric acid, streams operating above their autoignition temperature. Class 3 covers services that are flammable but slow to vaporise or sited well away from people and equipment. Class 2 is everything else, which in a working refinery is most of the plant. The intervals follow from the class: the highest-consequence circuits carry the shortest thickness interval and the lower classes extend, and external visual examination runs on its own schedule so that insulation, supports and coating damage are caught between thickness campaigns. Layered on top is a separate track for locations that corrode faster than the circuit containing them — injection points, mixing tees, dead legs and soil-to-air interfaces — which carry their own shorter intervals because a circuit-average corrosion rate systematically conceals them.
Source: API 570 Piping Inspection Code: In-Service Inspection, Rating, Repair and Alteration of Piping Systems; API RP 574 Inspection Practices for Piping System Components; API RP 571 Damage Mechanisms Affecting Fixed Equipment in the Refining Industry; API RP 583 Corrosion Under Insulation and Fireproofing; API RP 580 and 581 for risk-based inspection.
How API 570 assigns inspection effort, and what drives each interval
Element
What sets it
Why it exists
Circuit boundaries
Engineering judgement on where service actually changes
A single averaged rate across changing service describes no part of the system
Piping class
Consequence of a release, not operating pressure
Concentrates inspection where failure costs most
Thickness interval
Class cap, or half remaining life if shorter
The cap is a ceiling; measured corrosion always wins
External visual interval
Class, on a schedule separate from thickness
Catches insulation, support and coating damage between thickness campaigns
Injection point interval
Shorter, separately tracked from the parent circuit
Local turbulence and chemistry corrode far faster than circuit average
CUI inspection
Temperature band and class, per the code's CUI table
Damage is hidden and localised, so it needs its own targeting logic
Interval extension
Documented RBI assessment to API 580 and 581
Replaces the prescriptive cap with an assessed one, not with nothing
Every interval in the code is a maximum. A measured corrosion rate producing a shorter half-life always governs.
Circuit definition is the decision everything else inherits
A piping system is not uniform. One system can pass through changes in temperature, phase, velocity, and chemistry, each of which changes the corrosion regime. Averaging thickness data across that whole system produces a corrosion rate that describes none of its parts, and an interval built on it protects nothing in particular.
Circuit definition is the engineering judgement that prevents this — drawing boundaries where the service genuinely changes, so that the readings inside each circuit belong to one corrosion regime. It is also the judgement most often inherited without review. Circuits drawn at commissioning describe the plant as it was designed, and after a revamp, a feed change or a new tie-in, the flow regime moves while the boundaries stay where they were.
The code expects circuit definitions and condition monitoring location placement to be revisited when service changes. Treating that as a standing engineering item rather than a turnaround task is the difference between a programme that tracks the plant and one that tracks a drawing.
Why injection points get their own clock
An injection point is anywhere a chemical enters a flowing stream — corrosion inhibitor, neutraliser, water wash, antifoulant. Downstream of the quill, the mixing is incomplete and the local chemistry and turbulence are nothing like the bulk stream, so metal loss concentrates in a short length of pipe that can corrode several times faster than the circuit around it.
If those readings are folded into the circuit average, the average barely moves and the interval stays long while a short length of pipe thins toward failure. API 570 therefore treats injection point circuits separately, with their own CMLs distributed through the affected length and their own shorter interval.
The same logic covers mixing tees, dead legs where stagnant product allows under-deposit attack, and soil-to-air interfaces where moisture and oxygen concentrate at the transition. Each is a location where a circuit average is actively misleading rather than merely imprecise.
What Atlantis contributes on an API 570 programme
The inspection itself is signed by a certified API 570 inspector. What sits underneath it — the written practice governing NDT personnel certification, the examination procedures those technicians work to, and the Level III approval of those procedures — is separate, and it is where most audit findings actually land.
Atlantis builds and reviews that layer: written practice to ASNT SNT-TC-1A or ANSI/ASNT CP-189, procedure development and qualification for the specific damage mechanisms in scope, technique sheets, and independent review of contractor data packages before they become the basis for a remaining life decision.
That review reliably surfaces the same arithmetic error: corrosion rate computed against nominal wall rather than the code required minimum, which understates the rate and overstates the interval. Request a consultation to scope a review against your own circuits.
What does API 570 actually cover?
In-service inspection, repair, alteration and rerating of metallic process piping systems in refineries and chemical plants. It governs piping already in operation rather than new construction, which is covered by the applicable ASME B31 book, and it excludes several categories including internal piping of fired heaters and equipment covered by other codes.
How are API 570 piping classes assigned?
By consequence of failure rather than by pressure. Class 1 covers the most damaging release scenarios — flammables that flash on release, materials toxic at low concentration, hydrofluoric acid, streams above autoignition temperature. Class 3 covers low-consequence or remote services. Class 2 is everything in between, which is most of a working plant.
What is a condition monitoring location?
A designated position on a circuit where thickness is measured repeatedly over the life of the asset, so that a corrosion rate can be trended from comparable readings. Placement should reflect where damage is credible for the mechanism in play, which is why CML layout has to be revisited whenever the service changes.
Why do injection points need shorter intervals?
Because incomplete mixing downstream of the quill creates local chemistry and turbulence unlike the bulk stream, and metal loss concentrates in a short length of pipe that can corrode several times faster than the surrounding circuit. Folded into a circuit average, that loss is invisible until it leaks.
Can API 570 intervals be extended?
Yes, through a risk-based inspection assessment performed to API 580 and API 581, documented and approved by the owner-user and revalidated periodically. RBI substitutes an assessed interval for the prescriptive cap; it does not remove the obligation to justify the interval or to keep the underlying data current.
Who is qualified to perform API 570 inspections?
A certified API 570 inspector authorises and signs the inspection. The NDT technicians performing the examinations are certified separately under the employer's written practice to ASNT SNT-TC-1A or ANSI/ASNT CP-189, and a Level III approves the procedures those technicians follow. The three roles are distinct and are frequently conflated.
Frequently asked
Does API 570 apply to pipelines?
No. Pipelines in the United States fall under 49 CFR Parts 192 and 195, enforced by PHMSA or a certified state agency, with their own integrity management reassessment intervals. An operator holding both runs two separate inspection calendars that meet only at the plant boundary.
How is remaining life calculated under API 570?
Actual thickness minus required thickness, divided by the corrosion rate. Both long-term and short-term rates should be computed and the more conservative used, because a short-term rate exceeding the long-term rate means the service has changed and the older interval is no longer defensible.