Free API API-571 Practice Exam with Questions & Answers | Set: 3

Comprehensive and Detailed Explanation From Exact Extract:

Polythionic acid stress corrosion cracking (PASCC) occurs when sulfide scales on stainless steel surfaces are exposed to oxygen and moisture, most commonly during shutdowns and outages.

Per API RP 571:

Polythionic acids form when iron sulfides react with air and water

Cracking occurs in austenitic stainless steels

Damage is most likely during shutdown, not normal operation

Therefore, PASCC is the damage mechanism directly associated with shutdown exposure conditions.

Referenced Documents (Study Basis):

API RP 571 – Section on Polythionic Acid Stress Corrosion Cracking

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In API RP 571, under the section Polythionic Acid Stress Corrosion Cracking, it is stated:

“Sensitization of austenitic stainless steels occurs when the material is exposed to temperatures in the range of 800°F to 1500°F (427°C to 816°C), which causes chromium carbide precipitation at grain boundaries, depleting the adjacent areas of chromium.”

“Once sensitized, the steel becomes susceptible to attack in the presence of polythionic acids, particularly in environments containing sulfides and oxygen.”

(Reference: API RP 571, Section 4.2.2.5 – PTA SCC)

This makes option B (750°F to 1500°F / 400°C to 815°C) the most accurate and standard-aligned answer.

API RP 571 on Organic Acid Corrosion in Overheads explains:

“Corrosion caused by organic acids (e.g., formic, acetic) in overhead systems is best mitigated by neutralization, usually via injection of alkaline neutralizing amines that raise pH and reduce acidity.”

“Water wash can be helpful but is often insufficient by itself.”

Therefore, the most effective approach is option C – injection of neutralizer.

API RP 571 explains under Condensate Corrosion (CO₂ Corrosion):

“In condensate systems, carbon dioxide dissolves in the water forming carbonic acid, which leads to localized corrosion, including grooving and under-deposit attack, especially at low points like the bottom of horizontal piping.”

“This is most commonly observed in steam condensate return lines, and the damage is localized due to stratification.”

This matches the scenario described, where internal grooving at the bottom of steam condensate piping is characteristic of CO₂-induced corrosion. Hence, option A is correct.

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.

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.

API RP 571 notes in the context of Hydrochloric Acid Corrosion in overhead condensers:

“Titanium is highly resistant to low pH acidic aqueous phases, including hydrochloric acid formed during condensation in overhead systems.”

“Stainless steels like 316 and 410 are not suitable in the presence of free chlorides at low pH and elevated temperatures.”

(Reference: API RP 571, Section 4.3.3.3 – Hydrochloric Acid Corrosion)

Thus, Titanium is the preferred alloy under the described acidic and high-temperature conditions, making option B correct.

From API RP 571 on Microbiologically Influenced Corrosion (MIC):

“MIC depends on the presence of water, nutrients, and specific microbial species such as SRB (sulfate-reducing bacteria).”

“While flow velocity may influence deposition and oxygen content, MIC can occur in both stagnant and flowing systems. Hence, it's not strongly dependent on velocity.”

Thus, option D is correct — MIC is largely independent of flow velocity.

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

Comprehensive and Detailed Explanation From Exact Extract:

Carbolic acid corrosion (phenol corrosion) is described in API RP 571 as a process-specific corrosion mechanism that may not produce distinct or easily detectable wall-loss patterns using conventional NDE methods.

API RP 571 emphasizes that confirmation of carbolic acid corrosion often requires:

Chemical identification of corrosion products

Metallurgical examination

Verification of acid presence and metal interaction

A boat sample (also known as a coupon or scoop sample) removed from the affected area and analyzed in a laboratory allows:

Identification of corrosion morphology

Chemical analysis of deposits

Confirmation of phenol-related attack

Why the other options are incorrect:

UT and RT detect wall loss but cannot identify the corrosion mechanism.

Acoustic emission detects active cracking, not specific corrosion chemistry.

Angle beam UT is for crack detection, not corrosion identification.

Therefore, laboratory analysis of a removed sample is the most useful method.

Referenced Documents (Study Basis):

API RP 571 – Section on Organic Acid Corrosion (Phenols)

API Corrosion Failure Analysis Study Guide

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