From API RP 571, brittle fracture prevention measures include:

“Postweld Heat Treatment (PWHT) reduces residual stresses in the heat affected zone and base metal, thus lowering susceptibility to brittle fracture.”

“PWHT is particularly effective when applied to pressure-containing components fabricated from carbon steel or low-alloy steel that will experience low-temperature service.”

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

Therefore, while other measures may reduce stress or detect flaws, PWHT directly targets one of the root causes: residual stress. Thus, option D is the best prevention method.

According to API RP 571 and API RP 583:

“The most effective mitigation of CUI is the use of appropriate coatings underneath the insulation, which are resistant to moisture and chloride ingress.”

“Inspection and insulation selection are also important but are secondary controls.”

(Reference: API RP 571, Section 4.3.4 – Corrosion Under Insulation; API RP 583)

Hence, option D is correct.

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.

Same as above. Sigma phase formation is a microstructural phenomenon and not typically detected by NDE methods like magnetic particle or surface hardness testing.

Therefore, metallographic testing remains the definitive detection method, confirming option D again as the correct answer.

API RP 571 – Sulfidation:

“Sulfidation generally results in uniform thinning of iron-based alloys at temperatures above 500°F (260°C).”

“It is classified as a form of general corrosion, although it can be accelerated in turbulent flow areas.”

So, option A is correct.

As defined in API RP 571, under Hydrogen Blistering and HIC/SOHIC:

“SOHIC typically manifests as subsurface stepwise cracking, generally oriented perpendicular to the direction of stress.”

“This mechanism initiates below the surface, typically in weld heat-affected zones, and requires metallographic or advanced ultrasonic methods to detect.”

By contrast, SSC, caustic cracking, and amine SCC are primarily surface-initiated, stress-related cracking mechanisms.

Thus, SOHIC is the subsurface mechanism in this list, making option D correct.

API RP 571 under Polythionic Acid Stress Corrosion Cracking (PTA SCC) specifies:

“Cracking is usually intergranular, and often localized, especially in sensitized austenitic stainless steels exposed to sulfur-containing environments during shutdown or cleaning.”

“It is not always visible on inspection and may only become evident when a leak occurs.”

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

Hence, option C is correct as it best describes the detection difficulty and behavior of PTA SCC.

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.

In TR 942-B and API RP 582, it is emphasized:

“Nickel-based buttering is often used as an intermediate layer to reduce thermal stress mismatch during welding of ferritic and austenitic materials.”

“Nickel alloys have a coefficient of thermal expansion closer to that of both stainless steels and carbon steels, reducing stress concentrations and mitigating dissimilar weld cracking.”

“This technique also assists in achieving metallurgical compatibility and mitigating solidification cracking.”

Hence, option C is correct as it directly relates to minimizing thermal expansion mismatches.

API RP 571 defines Hydrogen Embrittlement as:

“Improper PWHT can trap hydrogen within the microstructure of carbon steel or fail to relieve residual stresses, both of which increase the risk of hydrogen embrittlement.”

“Moisture in electrodes contributes to hydrogen-induced cracking, but embrittlement from atomic hydrogen is more directly tied to heat treatment and microstructure.”

Thus, option D is the most accurate.

API RP 571 on Thermal Fatigue:

“Mixing of hot and cold streams, particularly where hydrogen is present, can induce thermal cycling stresses, leading to thermal fatigue cracking, especially at fittings like tees.”

“Hydrogen embrittlement typically affects stressed zones, but this pattern strongly indicates thermal fatigue.”

So the correct answer is C – Thermal fatigue.

As per API RP 945 (4th Edition, 2022):

“Post-weld heat treatment (PWHT) is the most effective method for reducing residual stresses that contribute to amine SCC. PWHT minimizes the stress intensity required for crack initiation and growth.”

Lowering temperature helps but is not always feasible.

Water content and amine concentration affect SCC but are not as impactful as PWHT.

Thus, Option A (Post-weld heat treatment) is the most effective mitigation.

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.

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.

API RP 571 states under the section Phosphoric Acid Corrosion:

“Corrosion usually occurs when the acid dries out and forms concentrated phosphoric acid deposits, which are very aggressive to carbon steel.”

“Drying or concentration occurs due to poor flow distribution or operational upsets. Localized areas may experience acid concentration due to vaporization.”

(Reference: API RP 571, Section 4.3.3.8 – Phosphoric Acid Corrosion)

Therefore, the most aggressive corrosion occurs when the acid dries out, making option D correct.

According to API RP 571 Section 5.4.2 (Erosion and Erosion/Corrosion):

“Erosion can occur downstream of flow disturbances such as control valves, orifice plates, elbows... It is characterized by localized metal loss with a directional pattern such as grooves or sharp-edged pits in areas of high velocity or turbulence.”

Cavitation and flashing cause damage with different signatures like pitting and spongy surface texture, while sharp-edged pitting strongly indicates erosion, especially downstream of flow restriction devices.

Thus, the correct answer is Option C (Erosion).

API RP 571, under Organic Acid Corrosion, highlights:

“Corrosive organic acids in overhead systems are those that condense at temperatures above the water dew point. These acids condense independently of water and can form highly concentrated corrosive films.”

“When acids condense first, they aggressively corrode carbon steel prior to any water wash mitigation.”

(Reference: API RP 571, Section 4.3.3.9 – Organic Acid Corrosion)

Hence, option D correctly identifies the most aggressive corrosion scenario.

API RP 751 (referenced in RP 571) lists materials appropriate for HF acid alkylation service. It specifies:

“Chrome-moly steels such as ASTM A-193 B5 (5% Cr) bolts are preferred for their resistance to HF acid-induced cracking.”

“Standard low alloy steels (e.g., B7) are not considered adequately resistant.”

(Reference: API RP 571 summary & API RP 751, Section 5.6.3 – Bolting Materials)

Therefore, the correct and industry-approved answer is option A.

As per API RP 571 Section 5.1.4.2 (Metal Dusting):

“Metal dusting is a type of carburization attack that typically occurs in high carbon activity environments, with temperatures generally between 900°F and 1200°F (480°C to 650°C), although damage has been reported as low as 600°F (315°C).”

Therefore, the commonly accepted operational range is best described by Option A: 600°F–1200°F (315°C–650°C).

API RP 571, under "Caustic Corrosion" (also referred to as Caustic Stress Corrosion Cracking or Caustic Cracking), notes that this form of damage is:

“Most commonly associated with the injection points of caustic (e.g., NaOH) in crude units, particularly upstream of desalter vessels and heat exchanger circuits.”

“This damage occurs due to the combination of caustic environment and tensile stress, especially in carbon steel and low alloy steels.”

“Stress relief heat treatment of welds can mitigate susceptibility.”

(Reference: API RP 571, 3rd Edition, Section 4.2.2.3)

Thus, among the options, caustic injections in crude units are the most typical area of concern, making option C the correct answer.

API RP 571, under Chloride Stress Corrosion Cracking, notes:

“Cracking often appears as highly branched or ‘crazed’ networks on the surface, especially in austenitic stainless steels exposed to chlorides under tensile stress.”

“These cracks often initiate in the heat-affected zones or cold-worked areas and are intergranular in nature.”

This signature ‘crazed’ appearance with branching is diagnostic of Cl-SCC, making option C the correct and most descriptive answer.

API RP 945, dedicated to environmental cracking in amine units, states:

“Carbon steel is widely used in amine systems but is particularly susceptible to localized corrosion, under-deposit corrosion, and stress corrosion cracking, especially in high-pressure or rich amine environments.”

“Proper control of amine quality, oxygen ingress, and temperature is critical to avoid accelerated corrosion in carbon steel equipment.”

Thus, carbon steels are the most commonly affected materials, making option C correct.

As per API RP 571 and further clarified in API RP 939-C:

“An arbitrary threshold of 50 ppmw H₂S in the aqueous phase is often used to define when carbon and low alloy steels become susceptible to cracking damage in wet H₂S environments.”

“Below this level, the risk of SSC, HIC, and SOHIC is considered lower, although damage has still occurred at lower concentrations depending on stress and metallurgical conditions.”

Therefore, the correct answer is option D (50 ppmw).

According to API RP 941 and API RP 571, High Temperature Hydrogen Attack (HTHA) is highly influenced by hydrogen partial pressure at elevated temperatures:

“The likelihood and rate of HTHA increase with both temperature and hydrogen partial pressure. Operating beyond established material limits on the Nelson Curves can lead to internal decarburization and methane formation in the steel.”

(Reference: API RP 571, Section 4.2.1.3 – High Temperature Hydrogen Attack)

Therefore, among all listed damage types, HTHA is the most directly affected by high hydrogen partial pressures, making option D correct.

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.

According to API RP 571, under High Temperature Hydrogen Attack (HTHA):

“HTHA occurs when hydrogen diffuses into steel at elevated temperatures and reacts with carbides in the steel matrix to form methane (CH₄).”

“The methane is unable to diffuse out of the steel and forms internal pressures, leading to fissuring, decarburization, and eventual failure.”

“HTHA typically affects carbon steels and low alloy steels exposed to high temperature hydrogen services, particularly above 400°F (204°C) depending on partial pressure of hydrogen.”

(Reference: API RP 571, Section 4.2.1.3 – High Temperature Hydrogen Attack)

Hence, option D is the correct and technically supported answer.

From API RP 571 Section 5.1.2.1 and RP 941:

“High strength low alloy steels (HSLA) are more susceptible to hydrogen embrittlement, especially during cold work, forming, or welding. These materials, due to their higher tensile strengths, are more prone to cracking when exposed to hydrogen, particularly during fabrication or post-weld heat treatment operations.”

Therefore, Option A (High Strength Low Alloys) is the correct answer due to their known susceptibility during manufacturing and processing.

API RP 571 – Hydrogen Stress Cracking – HF Acid Service:

“HF acid environments can cause hydrogen stress cracking (HSC) in carbon steel, particularly in areas with high hardness or residual stress.”

“This is distinct from general corrosion and requires specific inspection focus.”

So, option A is correct.

From API RP 571 Section 5.1.2.7 (Amine Stress Corrosion Cracking) and API RP 945 (Avoiding Environmental Cracking in Amine Units):

MEA (Monoethanolamine) systems are most aggressive due to:

“Their high reactivity and degradation potential producing corrosive by-products that promote cracking.”

API RP 945:

“SCC in carbon steel is most frequently reported in MEA units, especially where localized concentrations of heat-stable salts exist.”

Thus, Option C (MEA) is the correct answer due to its high SCC risk.

According to API RP 571 and API RP 751 (HF Alkylation Units):

“HF acid corrosion rates increase with elevated temperature and higher water content. This is because water acts as an ionizing agent that facilitates the acid’s attack on steel.”

“Corrosion is minimized when water content is strictly controlled, usually between 0.5–1.5%.”

“Contrary to some assumptions, increasing HF acid concentration actually decreases corrosivity.”

Hence, option B is correct.