API-571 API Corrosion and Materials Professional Free Practice Exam Questions (2026 Updated)

API RP 571 emphasizes under Hydrogen Stress Cracking – Hydrofluoric Acid (HF):

“Cracking in carbon steel is influenced by high hardness and tensile stress in the presence of wet HF acid.”

“Controlling weld and heat-affected zone hardness to below 200 BHN is a key mitigation measure, as higher hardness significantly increases susceptibility.”

Steel hardness and strength are thus critical for cracking in HF environments, making option C correct.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, hydrofluoric (HF) acid corrosion rates increase significantly once operating temperatures exceed approximately 150 °F (65 °C).

Key points noted in API RP 571:

Below ~150 °F, corrosion rates are relatively low due to formation of protective iron fluoride films.

Above 150 °F, these films become unstable.

Corrosion rates increase rapidly with temperature, especially under high velocity and water contamination conditions.

Why the other options are incorrect:

Option A (100 °F) is below the threshold for accelerated corrosion.

Option C and D are well above the onset temperature but are not the minimum threshold.

API RP 571 explicitly identifies 150 °F (65 °C) as the critical temperature where corrosion acceleration begins.

Referenced Documents (Study Basis):

API RP 571 – Section on Hydrofluoric Acid Corrosion

API Alkylation Unit Corrosion Study Guide

According to API RP 571 Section 5.2.1 (Fatigue – High Cycle and Low Cycle):

“Unsupported small-bore attachments like vents and drains are prone to high-cycle mechanical fatigue due to vibration. These attachments experience cyclic stress, especially near welds or bends.”

Thermal overload is unlikely without over-temperature data.

SSC (Option C) requires a wet H2S environment, which is not indicated.

Weld defects may contribute but are less likely the root cause without other signs.

Hence, mechanical fatigue (Option A) is most probable in this configuration.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, chloride stress corrosion cracking (Cl-SCC) of austenitic (300 series) stainless steels becomes a credible concern when:

Chlorides are present

Tensile stress exists

Metal temperatures exceed approximately 140 °F (60 °C)

Below this temperature, Cl-SCC is far less likely, while susceptibility increases rapidly above this threshold.

Referenced Documents (Study Basis):

API RP 571 – Section on Chloride Stress Corrosion Cracking

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API RP 571 under Ammonium Chloride Corrosion details:

“The corrosion results from the deposition of ammonium chloride salts from high-temperature process streams as they cool.”

“This typically occurs in crude unit overheads or other systems where salts condense out as the stream temperature drops below their dew point.”

“Corrosion becomes especially aggressive when the salts are wetted by condensation.”

(Reference: API RP 571, Section 4.3.3.1 – Ammonium Chloride Corrosion)

Therefore, option A is technically accurate and supported.

Comprehensive and Detailed Explanation From Exact Extract:

Amine stress corrosion cracking is most frequently associated with rich amine services, where:

Acid gas loading (H₂S / CO₂) is high

Corrosive contaminants and degradation products are present

Higher operating temperatures and stresses exist

Per API RP 571, cracking is far more common in rich amine systems than in lean amine circuits.

Why the other options are incorrect:

Lean amine has lower acid gas content and reduced SCC risk

SCC is not limited to low temperatures

Concentration alone is not the dominant factor

Referenced Documents (Study Basis):

API RP 571 – Section on Amine Stress Corrosion Cracking

API RP 751, which governs HF alkylation units, specifies:

“The total residuals of chromium, nickel, and copper in carbon steel used in HF service should be less than 0.15 wt.% to minimize corrosion risk.”

“Higher residuals increase the reactivity and corrosion rate of carbon steel in the presence of HF acid.”

(Reference: API RP 751, Section 5.3 – Materials Specification for HF Units)

Therefore, option A is the correct choice.

API RP 571 notes under Sour Water Corrosion:

“Localized thinning or under-deposit corrosion in sour water services is best detected by profile radiography, which provides a visual comparison of wall thickness over a length of pipe.”

“This technique is especially useful for assessing localized metal loss due to under-deposit attack or flow regime effects.”

(Reference: API RP 571, Section 4.3.2.3 – Sour Water Corrosion)

Hence, profile radiographic testing is most effective, making option B correct.

According to API RP 571, under Oxidation:

“Austenitic stainless steels (300 Series) are generally used for oxidation resistance up to about 1500°F (815°C). At higher temperatures, scaling and loss of protective chromium oxide layers increase.”

“Above these temperatures, specialized high-temperature alloys may be required.”

(Reference: API RP 571, Section 5.1.1 – Oxidation)

Therefore, option C is the correct answer.

According to API RP 571 Section 5.3.2.3 (Spheroidization):

“Spheroidization is the transformation of the microstructure of carbon and low alloy steels when exposed to elevated temperatures for long durations. The rate of spheroidization depends on temperature, prior microstructure, and exposure time... The microstructure becomes less effective at carrying loads, and strength is reduced.”

Key influencing factors for the rate of spheroidization are:

Temperature (higher accelerates the process),

Microstructure (initial phase distribution and morphology).

Pressure and hydrogen partial pressure are not relevant for this transformation, nor is stress a primary driver.

Therefore, Option D (temperature and microstructure) is correct.

According to API RP 571, high-cycle fatigue (HCF) is characterized by very tight, narrow cracks that can escape detection using typical NDE methods due to their minimal opening displacement and fine geometry.

From API RP 571 Section 5.2.1 (Fatigue - High Cycle):

"The cracks are usually tight and may be difficult to detect using conventional NDE techniques such as PT or MT. UT and RT may also have difficulty identifying these small, tight flaws, especially in early stages of propagation."

The primary issue in NDE is not the geometry (such as 90° corners) or ID location, but rather the tightness and early-stage subtlety of the cracks which results in reduced detectability. Therefore, option B is correct as it aligns most accurately with API RP 571's detailed characterization of HCF detection challenges.

From API RP 571 Section 5.3.2.1 (Creep and Stress Rupture):

“Short-term creep rupture is often associated with localized overheating and results in bulging and thinning, often with a characteristic ‘fish-mouth’ rupture appearance. These failures occur under sustained load in a short time (hours or days), typically in high-temperature service due to a sudden increase in temperature or poor heat distribution.”

Thus, Option B accurately describes the mechanism and visual indications of short-term stress rupture.

Comprehensive and Detailed Explanation From Exact Extract:

High-Temperature Hydrogen Attack (HTHA) is described in API RP 571 and API RP 941 as a damage mechanism where hydrogen reacts with carbides at elevated temperature and pressure, forming methane and causing loss of strength and fissuring.

Prevention is primarily achieved by selecting materials with stable carbides that resist hydrogen attack. Chromium and molybdenum alloying elements:

Form more stable carbides

Reduce susceptibility to methane formation

Extend safe operating limits

Why the other options are incorrect:

Option B may be used in some services but is not the usual prevention method.

Option C is incorrect because RP 941 does not recommend high-nickel alloys as the primary solution.

Option D low-carbon steels are more susceptible, not resistant.

API RP 571 clearly identifies Cr-Mo alloy steels as the standard mitigation approach.

Referenced Documents (Study Basis):

API RP 571 – Section on High-Temperature Hydrogen Attack

API RP 941 – Nelson Curves and Material Selection

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API RP 571 identifies these parameters as critical to the corrosion rate of carbon and low alloy steels in sour water environments:

“The extent of corrosion in sour water is influenced by pH, H₂S content, temperature, liquid velocity, and oxygen contamination.”

“These factors control the formation and stability of protective iron sulfide layers.”

(Reference: API RP 571, Section 4.3.2.1 – Sour Water Corrosion)

Therefore, the correct answer is A.

Comprehensive and Detailed Explanation From Exact Extract:

Microbiologically Induced Corrosion (MIC) is one of the most universally applicable corrosion mechanisms, affecting:

Carbon steel

Low-alloy steel

Stainless steels

Copper alloys

Aluminum alloys

According to API RP 571, MIC can occur in any aqueous system where microorganisms are present, regardless of metallurgy.

By contrast:

Sour water corrosion and amine corrosion mainly affect carbon steel

Polythionic acid corrosion is limited to austenitic stainless steels

Referenced Documents (Study Basis):

API RP 571 – Section on Microbiologically Induced Corrosion

According to API RP 571 Section 5.1.2.6 (Carbonate Stress Corrosion Cracking - CSCC):

“The cracking is usually intergranular and is most commonly detected using wet fluorescent magnetic-particle testing (WFMT) after surface cleaning. PT may not be sensitive enough to detect fine cracks formed by this mechanism.”

Because CSCC cracks are typically surface-connected and very fine, WFMT offers the best visibility, especially after proper surface prep.

Therefore, Option D is correct.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, corrosion in cooling water systems often increases at low flow velocities due to:

Stagnation

Deposit formation

Increased risk of underdeposit corrosion and MIC

Higher velocities tend to:

Sweep away deposits

Maintain protective films (within erosion limits)

Therefore, decreasing velocity is strongly associated with increased corrosion risk.

Referenced Documents (Study Basis):

API RP 571 – Section on Cooling Water Corrosion

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According to API RP 571, under the section "4.2.1.2 Brittle Fracture", the following conditions are explicitly identified as most critical for brittle fracture risk:

"Most processes run at elevated temperature, so the main concern is for brittle fracture during startup, shutdown, hydrotest, or other situations where equipment may be exposed to low temperatures."

"Equipment fabricated from materials susceptible to brittle fracture (e.g., carbon steel) is most vulnerable when exposed to low temperatures combined with high stress or pressure."

"A brittle fracture is characterized by a sudden and rapid crack propagation with little or no plastic deformation."

(Reference: API RP 571, Section 4.2.1.2 – Brittle Fracture)

Thus, while other options represent stress events, the main concern specifically noted by the standard is during start-up and shutdown—especially due to cooling and repressurization at low temperatures—making option A the most accurate choice.

In steam systems, the absence of a steam trap allows condensate to accumulate, which can lead to corrosion from oxygen and carbon dioxide dissolved in the water—a classic case of condensate corrosion.

From API RP 571 Section 5.3.3.1 (Condensate Corrosion):

“If steam lines or equipment like soot blowers do not have proper drainage or steam traps, condensate may accumulate... Corrosion results from the presence of dissolved oxygen and/or carbon dioxide in the condensate.”

Thus, the correct answer is Option D (condensate corrosion).