API 570 Exam Flashcards

Q: How many questions are on the API 570 exam, and how is it split?

The exam has 170 multiple-choice questions: 140 scored and 30 unscored pretest items. It is split into 110 closed-book questions during the first 2.75 hours and 60 open-book questions during the final 3.75 hours, with a 45-minute lunch break between sessions, for a total 7.5-hour exam day.

Q: What score do I need to pass the API 570 exam?

API uses a scaled scoring system rather than a raw percentage, and the passing scaled score is 400 (on API's ICP 200-500 scale). API does not publish an exact raw-to-scaled conversion, but candidates should expect to need roughly 70% overall performance under that scaling model.

Q: If I fail the API 570 exam, how soon can I retake it, and how many attempts do I get?

API does not publish a fixed 'wait X days' rule like some other testing bodies. Retesting is tied to API's scheduled exam windows, which run about three times per year (roughly every 3-4 months). Candidates generally have up to 12 months from their first scheduled window to pass, which typically allows about 4 attempts; missing that period requires a brand-new application and the full exam fee again.

Q: How often do I need to recertify my API 570 credential, and what does that require?

API 570 certification must be renewed every 3 years. Recertification requires documenting 24 hours of continuing professional development (CPD) relevant to inspection and mechanical integrity during that 3-year cycle, plus completing API's renewal application. Failing a recertification quiz twice requires submitting a brand-new application and retaking the full initial exam instead.

Q: Does API publish official domain-by-domain percentage weights for API 570?

No. API publishes the Body of Knowledge sections and the 110 closed-book / 60 open-book split, but not public percentage weights per domain. Use the BOK sections and the listed references (API 570, RP 571, RP 574, RP 576, RP 577, RP 578, ASME B31.3, Section V, Section IX, and PCC-2) to plan study time instead of an official weighting table.

Q: What experience or education do I need before I can sit for the API 570 exam?

API uses an education-and-experience pathway. Candidates need 1 year of qualifying piping-inspection experience with a BS or higher in engineering/technology (or 3+ years of technical military service), 2 years with an associate degree/certificate, 3 years with a high school diploma, or 5+ years with no formal education, with at least 1 year involving supervision or performance of API 570-type inspection activities.

Question 1

How do you calculate the long-term (LT) corrosion rate for a piping circuit?

Accepted Answer

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.

Question 2

How do you calculate the short-term (ST) corrosion rate?

Accepted Answer

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.

Question 3

A circuit's LT rate is 0.005 in./yr and its ST rate is 0.012 in./yr. Which rate governs the next interval and remaining-life calculation?

Accepted Answer

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.

Question 4

What is the formula for remaining life at a condition monitoring location?

Accepted Answer

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.

Question 5

What is 't-required' (retirement thickness), and why is it essential to the remaining-life formula?

Accepted Answer

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.

Question 6

Under API 570 Table 1, what are the thickness-measurement and external-inspection intervals for Class 1 piping?

Accepted Answer

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.

Question 7

How do Class 2 and Class 3 inspection intervals differ under API 570 Table 1?

Accepted Answer

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.

Question 8

What is the maximum thickness-measurement interval for an injection-point circuit, regardless of its piping class?

Accepted Answer

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.

Question 9

What is the 'half-life rule' for setting an API 570 inspection interval?

Accepted Answer

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.

Question 10

What is the short-remaining-life exception to the half-life rule, and when does it apply?

Accepted Answer

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.

Question 11

What thickness value should feed a rerated MAWP calculation for a corroded component — just today's measured thickness, or something more conservative?

Accepted Answer

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.

Question 12

Where does API 570 point you for the minimum required thickness (t-min) formula for straight pipe under internal pressure?

Accepted Answer

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.

Question 13

What do the weld joint factor (Ej) and casting quality factor (Ec) do to a thickness calculation?

Accepted Answer

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.

Question 14

What does a Welding Procedure Specification (WPS) document, and who uses it?

Accepted Answer

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.

Question 15

What does a Procedure Qualification Record (PQR) prove, and how does it relate to a WPS?

Accepted Answer

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.

Question 16

What does a Welder Performance Qualification (WPQ) prove, and how is it different from a PQR?

Accepted Answer

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.

Question 17

What is the difference between an essential variable and a nonessential variable on a WPS?

Accepted Answer

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.

Question 18

Which base-metal P-Numbers are within scope for API 570 welding-review questions?

Accepted Answer

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.

Question 19

When would an inspector require PT (liquid penetrant testing) instead of MT (magnetic particle testing) for surface-crack detection?

Accepted Answer

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.

Question 20

What does MT (magnetic particle testing) detect, and what does it require of the material?

Accepted Answer

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.

Question 21

What is RT (radiographic testing) best suited to detect, and what does it produce as a record?

Accepted Answer

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.

Question 22

What can UT (ultrasonic testing) do that RT typically cannot for an in-service piping inspection?

Accepted Answer

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.

Question 23

What is the role of VT (visual testing) in an API 570 inspection program?

Accepted Answer

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.

Question 24

When would an inspector use a leak test instead of another NDE method?

Accepted Answer

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.

Question 25

What must happen before any NDE method is applied and trusted in an API 570 scenario?

Accepted Answer

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.

Question 26

What is a Condition Monitoring Location (CML)?

Accepted Answer

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.

Question 27

What is a 'circuit' in API 570 terminology?

Accepted Answer

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.

Question 28

When should an inspector add more CMLs to a circuit rather than relying on the existing set?

Accepted Answer

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.

Question 29

What is the difference between the point-to-point method and the circuit (statistical) method for evaluating a circuit's corrosion rate?

Accepted Answer

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.

Question 30

What piping class would a rapid-vaporizing C2-C4 hydrocarbon line or a stream with more than 3% H2S typically be assigned, and why?

Accepted Answer

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.

Question 31

What is the owner-user's general oversight responsibility for an API 570 mechanical integrity program?

Accepted Answer

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.

Question 32

What is a deadleg, and why does it carry elevated corrosion risk?

Accepted Answer

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.

Question 33

How far upstream and downstream of an injection nozzle does an injection-point circuit typically extend for inspection purposes?

Accepted Answer

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.

Question 34

How should small-bore piping, such as vents, drains, bridles, and level-gauge piping, and threaded connections be inspected under API 570?

Accepted Answer

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.

Question 35

What is the difference between a permanent record and a progressive record in an API 570 inspection program?

Accepted Answer

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.

Question 36

What is 'baseline thickness' and when is it established?

Accepted Answer

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.

Question 37

How often must an API 570 certification be renewed, and what continuing education is required?

Accepted Answer

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.

Question 38

What is CUI (corrosion under insulation), and where does it most commonly occur?

Accepted Answer

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.

Question 39

What is sulfidation, and what conditions promote it?

Accepted Answer

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.

Question 40

What is chloride stress corrosion cracking (chloride SCC), and which materials are most susceptible?

Accepted Answer

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.

Question 41

What is amine stress corrosion cracking (amine SCC), and where is it typically found?

Accepted Answer

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.

Question 42

What is MIC (microbiologically influenced corrosion), and what does it typically look like?

Accepted Answer

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.

Question 43

Amine SCC, caustic SCC, and chloride SCC are all grouped together under what damage-mechanism family, and what do they share?

Accepted Answer

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.

Question 44

What does API RP 574 cover, and how is it used on the exam?

Accepted Answer

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.

Question 45

Why do flanged joints and gaskets get specific inspection attention beyond general pipe-wall thickness?

Accepted Answer

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.

Question 46

What are the typical PRD (pressure relief device) test intervals under API RP 576?

Accepted Answer

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.

Question 47

What is a common default threshold used to flag a PRD as possibly 'stuck shut' when reviewing its performance history?

Accepted Answer

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.

Question 48

What does a Positive Material Identification (PMI) program verify, and why does API RP 578 matter for piping inspectors?

Accepted Answer

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.

Question 49

What verification approaches does RP 578 describe, and what is 'retroactive PMI' aimed at?

Accepted Answer

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.

Question 50

What is ASME PCC-2 used for, and what is the difference between a temporary repair and an engineered permanent repair under it?

Accepted Answer

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.

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