Free API 570 Exam Flashcards

Subtract the current measured thickness from the original baseline (initial) thickness recorded at installation, then divide by the total time in service since that baseline reading. LT rate reflects the full service history, not just recent conditions.

Subtract the current thickness from the previous inspection's thickness, then divide by the time elapsed between those two readings only. ST rate reacts faster than LT rate to recent process changes, so it can rise even while the long-term average still looks low.

The higher rate governs — here, 0.012 in./yr. Whenever LT and ST disagree, API 570 requires using the faster rate, since it represents the more conservative, worst-case corrosion trend.

Remaining life = (t-actual − t-required) ÷ corrosion rate. t-actual is the current measured thickness and t-required is the minimum thickness the component needs for its operating conditions; the result estimates years until the location reaches retirement thickness at the governing rate.

It is the minimum wall thickness the component needs to safely contain its design pressure and loads, typically derived from ASME B31.3. Remaining life measures how much thickness above t-required is left before the corrosion allowance runs out, so the calculation has no floor to measure against without it.

Both are 5 years — the tightest schedule in Table 1, reserved for the highest consequence-of-failure circuits such as rapid-vaporizing hydrocarbons, high-H2S streams, or piping over public areas.

Class 2 allows 10 years for thickness measurement but only 5 years for external visual inspection. Class 3 allows 10 years for both thickness measurement and external visual — the longest fixed schedule of the three classes.

3 years. Injection points suffer accelerated, localized corrosion just downstream of the injection nozzle, so API 570 caps this interval at 3 years even when the surrounding circuit's class would otherwise allow longer.

The next interval can be no longer than half of the calculated remaining life. This ensures no more than half of the safety margin above retirement thickness is ever consumed between two consecutive inspections.

When calculated remaining life is under 4 years, API 570 allows setting the interval at the full remaining life instead of half of it — but that interval can still never exceed 2 years, regardless of how much remaining life is left.

A more conservative value: actual measured thickness reduced by an added margin for anticipated future loss, commonly framed as twice the corrosion projected over the next interval. That keeps the rerated MAWP valid until the next inspection even if the corrosion rate holds steady or ticks up slightly.

ASME B31.3, paragraph 304.1.1. It relates design pressure, outside diameter, allowable stress, and the weld joint quality factor (Ej) to the minimum wall thickness needed — the starting reference for most remaining-life and rerating calculations.

Both derate the allowable stress used in the calculation when examination coverage is limited. Ej applies to longitudinal weld seams — a fully radiographed seam earns a higher, less-penalizing factor than a spot-examined one — and Ec applies the same logic to cast components.

A WPS is the written 'how-to' for making a weld — process, filler metal, preheat, current, and travel speed, among other variables. Welders follow it in the field, and it must be supported by a qualifying PQR before use.

A PQR documents the actual welding parameters and mechanical test results (tensile, bend, etc.) from a qualification test weld. It proves the WPS can produce a sound weld with adequate properties, and one qualified PQR can support one or more WPSs within its qualified range.

A WPQ proves an individual welder can produce an acceptable weld using a specific qualified WPS and process — it certifies the person, not the procedure. A PQR instead certifies that the written procedure itself is sound.

Changing an essential variable, such as base-metal P-Number, filler metal, or preheat range, affects mechanical properties and requires requalifying the WPS with a new PQR. Changing a nonessential variable only requires updating the WPS document, with no retest needed.

P-1 (carbon steel), P-3 and P-4 (low-alloy Cr-Mo steels), P-5 (higher-chrome Cr-Mo alloys), and P-8 (austenitic stainless steel). Dissimilar-metal joints between different P-Numbers are outside this exam's tested scope.

PT is required when the material is nonmagnetic, such as austenitic stainless steel or nonferrous alloys, since MT only works on ferromagnetic materials. Both methods detect surface-breaking flaws only — neither sees subsurface defects.

MT detects surface and near-surface cracks in ferromagnetic materials by inducing a magnetic field, via yoke or prod, and applying particles that cluster at flux-leakage points. It cannot be used on nonmagnetic materials like austenitic stainless steel.

RT images internal, volumetric flaws such as porosity, slag inclusions, and lack of fusion inside a weld, producing a film or digital radiograph as a permanent record. An image quality indicator (IQI) on the film confirms adequate sensitivity.

UT measures wall thickness directly, per SE-797 pulse-echo technique, and can size elongated, planar flaws like cracks using angle-beam technique — capabilities RT does not provide, since RT is primarily an imaging method for volumetric flaws rather than a thickness gauge.

VT is the broadest, most frequently used method, assessing overall external and internal condition, coatings, insulation jacketing, supports, and obvious damage. It is often the first method applied and can trigger follow-up with PT, MT, RT, or UT.

When a through-wall defect is suspected and direct confirmation of containment integrity is needed. Leak testing, using bubble or direct-pressure methods, directly demonstrates whether a component holds pressure, which surface or volumetric methods alone cannot confirm.

The equipment must be calibrated, for example against a reference block or IQI, and the results must be documented per the applicable Section V article. A reading from uncalibrated equipment is not valid evidence, regardless of which method was used.

A specific, fixed point on a piping circuit where thickness is measured repeatedly over time to track corrosion. CMLs are placed at locations most likely to show representative or worst-case metal loss for the circuit.

A grouping of piping, including pipe, fittings, and valves, that shares similar service, material, and expected corrosion behavior, and is therefore evaluated together using a common set of CMLs rather than inspecting every foot of pipe individually.

When the circuit carries higher risk factors, such as localized or accelerated corrosion mechanisms, complex geometry, dead legs, or injection points, versus a low-risk, noncorrosive, straight run of pipe, which can be adequately monitored with fewer CMLs.

Point-to-point uses each CML's own worst-case reading independently and is simple and conservative. The circuit/statistical method pools data across multiple CMLs using a confidence interval, but it is only valid when corrosion is reasonably uniform across the circuit.

Class 1, the highest-consequence class, because these streams create an immediate emergency risk, such as rapid vapor-cloud formation or acute toxicity, if the piping fails, driving the tightest 5-year/5-year inspection interval.

The owner-user, not API, is responsible for establishing and administering the program, including setting inspection intervals, CML strategy, and using qualified personnel, with authorized inspectors and engineers expected to document a meaningful share of their time on inspection-related duties.

A deadleg is a low- or no-flow branch off the main process line, such as a capped stub or infrequently used connection. Stagnant fluid can concentrate corrosive species or allow solids to settle, so deadlegs often corrode faster than the actively flowing main run.

Upstream: 12 inches or 3 pipe diameters, whichever is greater. Downstream: 25 feet or to the next change in flow direction, whichever comes first. This zone gets the accelerated 3-year thickness-monitoring interval because injected chemicals often cause localized corrosion just past the nozzle.

The same class-based rules that apply to primary piping apply to small-bore piping — it is not automatically exempt just because of its size. Threaded connections are inspected the same way, since threads can hide corrosion or leak paths that visual inspection alone may miss.

Permanent records, such as original design data and baseline thickness, are kept for the life of the piping system and rarely change. Progressive records, such as thickness readings and repair history, are updated after every inspection to build a running corrosion and maintenance history.

The reference thickness recorded at the piping system's original installation inspection, or the earliest reliable reading available. It anchors the long-term (LT) corrosion-rate calculation for the rest of the piping's service life.

Every 3 years. The inspector must document 24 hours of continuing professional development (CPD) relevant to inspection and mechanical integrity during each 3-year cycle to recertify, in addition to meeting API's renewal application requirements.

External corrosion that develops on piping under weatherproofed thermal insulation when moisture becomes trapped against the metal surface. It concentrates at insulation jacketing seams, penetrations, low points, and dead ends where water gets in but does not fully evaporate.

High-temperature thinning caused by sulfur compounds in the process stream reacting with steel to form iron sulfide scale. It requires no water phase — it is driven by temperature and sulfur or naphthenic-acid content, and it worsens as either increases.

Cracking of austenitic stainless steels caused by the combination of tensile stress, chlorides, and temperature, typically above about 140°F (60°C). Insulated stainless piping prone to CUI is a classic location, since trapped moisture can concentrate chlorides against the metal.

Cracking in carbon steel amine-treating unit piping and vessels, usually at welds that were not post-weld heat treated (PWHT), where residual stress combines with the alkaline amine environment to initiate cracks.

Localized corrosion accelerated by the metabolic activity of bacteria, such as sulfate-reducing bacteria, living in stagnant water or deposits. It often produces isolated pitting under tubercles rather than uniform, widespread metal loss.

They are all forms of stress corrosion cracking (SCC) — each requires the combination of a susceptible material, tensile stress, and a specific chemical environment (amine, caustic, or chloride). Recognizing the SCC family helps you rule in cracking mechanisms once the right environment and material are present.

RP 574 addresses inspection practices for piping system components, including pipe, flanges, fittings, valves, and specialty items. The entire document is within scope, so questions can draw from any component-specific inspection guidance it contains.

Flange faces, bolting, and gaskets are common leak points with their own degradation modes, such as bolt corrosion, gasket creep, and face damage, that are independent of the pipe wall's corrosion rate, so they need a dedicated visual and condition check during inspection.

5 years is the typical default test interval, extendable up to 10 years for PRDs in clean, non-fouling service with a good performance history. The actual interval should be justified by service experience, not simply assumed.

System pressure reaching roughly 150% of the PRD's set pressure without the device lifting is a common red flag suggesting the valve may be stuck shut and failing to relieve as designed.

PMI confirms that the actual alloy of an installed or newly fabricated component matches its intended material specification, catching mix-ups that could otherwise leave a lower-grade alloy in high-temperature or corrosive service where it was not designed to perform.

RP 578 describes 100% verification, risk-based verification, and statistical sampling approaches. Retroactive PMI specifically targets legacy piping systems installed before routine PMI programs existed, to find alloy mix-ups that were never originally verified.

PCC-2 provides accepted methods for repairing in-service pressure equipment and piping, such as welded insert plates, full-encirclement sleeves, and weld overlay. A temporary repair restores integrity only until a permanent fix can be scheduled, while an engineered repair is intended as a lasting fix documented like new construction.