API 570 Process Piping Inspection: Classes, Methods, CMLs

Process piping carries the fluids that make refineries, chemical plants, and gas processing facilities work. When it leaks, the consequences range from production loss to fires, releases, and regulatory action. API 570 is the in-service inspection code that governs how that piping gets evaluated, maintained, and kept fit for service. Owners of facilities with process piping need to understand how API 570 works because the inspection program shapes both safety outcomes and operating cost.

What follows covers the parts of API 570 that matter most for tank and plant owners: the piping classes that drive inspection frequency, the condition monitoring locations (CMLs) that focus inspection effort, the NDT methods used to evaluate piping condition, and the practical differences between piping inspection and the inspection of tanks or pressure vessels.

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What API 570 covers (and what it doesn't)

API 570, "Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems," applies to metallic piping carrying process fluids in operating facilities. The code is the in-service counterpart to ASME B31.3, which is the design and construction code for the same kind of piping. Construction follows B31.3; in-service inspection follows API 570.

API 570 applies to piping that carries hydrocarbons, flammable fluids, toxic fluids, and certain other process media. It does not apply to several types of piping that are sometimes confused with process piping:

Utility piping (compressed air, plant water, plumbing) falls under different codes entirely
Pipelines under DOT jurisdiction are governed by 49 CFR rules
Piping internal to fired equipment (boiler tubes, furnace tubes) follows other API and ASME codes
Refrigeration piping in some configurations falls under ASME B31.5

Mistaking one category for another is a common source of misapplied inspection programs. Process piping that should be inspected under API 570 sometimes gets treated like utility piping and inspected too lightly, while utility piping occasionally gets treated like process piping and inspected too aggressively. Both are expensive mistakes.

The three piping classes

API 570 categorizes piping into three classes based on the consequence of a release. Higher consequence means more frequent inspection and tighter scrutiny. The class assignment drives almost every other inspection decision.

Class	Typical Services	Consequence Level	Typical Inspection Frequency
Class 1	Flammable services that vaporize quickly on release, toxic fluids, anhydrous hydrogen chloride, hydrofluoric acid, sulfur dioxide	Highest	Up to 5-year external; up to 5-year thickness
Class 2	On-site hydrocarbons that do not significantly vaporize on release, acids, caustics, most flammable fluids handled at lower volatility	Intermediate	Up to 10-year external; up to 10-year thickness
Class 3	Flammable fluids that do not significantly vaporize, combustible fluids handled below their flash point, distillate and product lines that do not flash on release	Lowest	Up to 10-year external; longer thickness intervals possible

Class assignment is made by the owner-operator with input from the inspector and engineering. Service conditions, location relative to public exposure, and operating pressure and temperature all factor in. The assignment is documented and reviewed periodically because services and conditions change over time.

What changes when class changes

A piping circuit operating in Class 3 service that gets repurposed for Class 1 fluid does not automatically inherit Class 1 inspection treatment. The owner has to make the formal class change, update the inspection plan, and increase inspection rigor. Skipping that step is a compliance gap that audits will find.

Condition Monitoring Locations (CMLs)

API 570 inspection is not a uniform sweep across the entire piping system. The standard recognizes that corrosion and degradation concentrate in predictable locations, so inspection effort concentrates there too. The mechanism for that focus is the condition monitoring location.

A CML is a specific point on a piping circuit where inspection data is collected repeatedly across inspection cycles. Each CML is documented (location, dimensions, baseline thickness, history) and revisited at each inspection so the inspector can trend wall thickness over time and calculate corrosion rate.

Where CMLs go

Effective CML placement targets the spots most likely to fail first:

Elbows and bends, particularly the extrados (outside curve) where erosion concentrates on high-velocity lines and the intrados (inside curve) for some flow regimes
Tees and other branch connections, where flow disturbance accelerates corrosion or erosion
Reducers and other geometry changes that disturb flow
Locations downstream of valves and orifices where turbulent flow causes localized thinning
Dead legs and stagnant sections where settled water or condensate sits against the pipe wall
Low points where water accumulates, particularly on hydrocarbon services with entrained water
Areas under insulation where corrosion under insulation (CUI) develops out of sight
Injection points and mix points where corrosive chemicals are introduced
Heat-affected zones around welds on certain services

How many CMLs is enough

API 570 does not prescribe a fixed number of CMLs per length of pipe. The standard requires that CML quantity and placement be sufficient to characterize the corrosion behavior of the circuit. Practical CML density depends on circuit complexity, service severity, historical corrosion behavior, and the operator's corrosion management strategy.

CML placement is one of the highest-leverage decisions in any piping inspection program. Too few CMLs and corrosion patterns get missed; too many and inspection cost balloons without proportional safety benefit. Experienced inspectors and corrosion engineers earn their fees here.

NDT methods used on piping

The NDT toolkit for piping overlaps with what gets used on tanks and pressure vessels but with some piping-specific emphasis.

Visual inspection

Visual inspection is the starting point of every piping inspection and the only method that catches some categories of damage outright. Inspectors look for external corrosion, paint and coating failures, leaks at flanges and connections, support condition, insulation damage, and signs of unauthorized modifications. Visual inspection costs little but catches many findings that more sophisticated methods would miss or only detect after damage has progressed.

Ultrasonic thickness gauging

Ultrasonic testing (UT) is the primary tool for measuring wall thickness at CMLs. A handheld instrument with a transducer measures the steel thickness at each documented point, producing a numerical reading that gets compared against historical readings and minimum required thickness. UT mapping on piping follows similar principles as on tank shells, with the difference that pipe geometry requires more careful transducer placement.

Radiographic testing

Radiographic testing (RT) uses x-ray or gamma-ray imaging to evaluate weld integrity and detect subsurface defects. RT is used selectively on piping: typically for new construction welds, for repair welds, and for evaluating welds that show indications during visual or UT inspection. Profile radiography (a variation) can image pipe cross-section to detect internal corrosion patterns and erosion in ways that thickness gauging alone cannot.

Magnetic particle and dye penetrant testing

Magnetic particle testing and dye penetrant testing are surface NDT methods used to detect tight cracks and surface flaws that other methods can miss. They show up on piping inspection in targeted scenarios: evaluating suspect welds, checking after stress-corrosion-cracking is suspected, and verifying repair quality.

Specialized techniques

Three additional techniques are worth knowing about because they show up on more complex piping programs:

Long-range guided wave UT covers long sections of pipe from a single transducer ring, trading resolution for range. Useful for screening pipe runs that are difficult to access
Phased array UT (PAUT) uses multiple transducer elements for higher resolution on welds and complex geometry
Eddy current testing is used on certain alloy piping where UT or RT is less effective

How piping inspection differs from tank and vessel inspection

Tank, vessel, and piping inspections share NDT methods and code structure (API 653, 510, and 570 are siblings), but the practical work is quite different.

Piping inspection is fundamentally distributed

A tank is one structure at one location. A pressure vessel is one structure at one location. A piping circuit is a long, branching path that crosses unit boundaries, changes elevation, runs through pipe racks, and interacts with multiple vessels and equipment. Inspection planning has to account for distribution: where does the inspector access elevated sections, how does the team coordinate across operating units, what scaffolding or man-lift access is required, and how does the documentation tie back to a single coherent circuit.

Inspection is rarely 100 percent

API 653 internal tank inspections evaluate essentially the entire floor and shell. API 510 internal vessel inspections similarly cover the full vessel interior. API 570 piping inspections are sampling-based by necessity: examining 100 percent of a piping circuit would be prohibitively expensive and is rarely required. The CML system exists precisely because piping inspection has to be statistically representative rather than comprehensive.

Piping rarely comes out of service

Tank and vessel internal inspections require taking the equipment out of service. Most piping inspection happens on-stream, with the piping carrying product. This shapes both the NDT methods that can be used and the access required. External UT, visual inspection from grade and from access platforms, and RT applied without isolation are the workhorses. Inspections that require isolation are coordinated with operating turnarounds.

Corrosion mechanisms differ

Tank corrosion concentrates at the water-product interface and at the floor. Vessel corrosion patterns depend on internal geometry and service conditions. Piping has its own characteristic patterns: erosion at elbows, dead-leg corrosion at low points and stagnant branches, CUI under insulation, injection point corrosion, and high-temperature degradation modes that depend on alloy and service. Effective piping inspection requires understanding these mechanisms and placing CMLs accordingly.

Repair, rerate, and re-evaluation under API 570

When an inspection identifies damage that affects piping integrity, API 570 governs how repairs get evaluated and approved. Three primary paths exist:

Repair to original design. The damaged section is restored to original specifications via welding, replacement, or other approved methods. Repair procedures must meet code requirements for the original construction code (typically ASME B31.3)
Rerating to current condition. When repair to original specs is impractical, the piping circuit can sometimes be rerated to a lower pressure or service condition based on its current measured thickness. Rerating requires engineering analysis
Replacement. When damage is extensive or repair is not economical, replacement of the affected section follows new-construction code requirements

The inspector documents findings and recommends repair categories; the engineering authority approves repair plans; qualified personnel execute the work. API 570 requires that repair documentation become part of the piping circuit's permanent record.

Building an inspection program that works

Effective API 570 programs share several characteristics. Class assignments are reviewed periodically rather than set once and forgotten. CMLs are placed by people who understand both the piping system and the corrosion mechanisms involved. Inspection findings are reviewed against historical trends, not just against absolute minimum thickness. Documentation is robust enough to support both regulatory audits and engineering decisions years later.

Programs that fall short usually have one or more of: outdated class assignments that no longer reflect current service, CMLs placed by checklist rather than by judgment, inspection results recorded but not trended, and documentation gaps that force conservative assumptions on the next inspection cycle. The cost of fixing these problems is typically far less than the cost of leaving them in place.

Working with an inspection provider

API 570 inspection requires more than NDT technicians with thickness gauges. The right provider brings inspectors certified to API 570, corrosion engineering judgment for CML placement and trending, documentation systems that produce defensible records, and integration with other inspection programs (API 653 for tanks, API 510 for vessels) when the facility has mixed assets.

NDT Tanknicians performs API 570 process piping inspections for facilities across all 50 states, often as part of integrated programs that include tank and vessel inspection at the same site. To discuss a new piping inspection program, audit an existing program, or scope upcoming inspection work, contact us.