API-571 Corrosion and Materials Professional Question and Answers

API RP 571 – Polythionic Acid Stress Corrosion Cracking:

“Polythionic acid SCC may be mistaken for wet H₂S damage because both involve cracking in austenitic stainless steels under certain conditions.”

Thus, option D is correct.

Dissimilar Metal Cracking (DMC) is a form of high-temperature cracking that frequently occurs in weld joints between carbon steel and austenitic stainless steel (such as Type 316 SS) due to differences in thermal expansion coefficients and mechanical properties.

From API RP 571 Section 5.2.3.1 (Dissimilar Metal Weld Cracking):

“Cracking frequently occurs in weld joints between ferritic and austenitic materials such as carbon steel to 300 series stainless steels due to thermal expansion mismatch during high temperature operation.”

Therefore, Option D (Carbon steel to 316 stainless steel) is the most susceptible combination and the correct answer.

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 that both Sulfide Stress Cracking (SSC) and SOHIC are:

“Strongly influenced by material hardness. Carbon and low alloy steels with hardness exceeding 22 HRC (248 Brinell) are most susceptible.”

“They occur in hardened steels under tensile stress, in the presence of wet H₂S environments.”

(Reference: API RP 571, Sections 4.2.2.1 and 4.2.2.7 – SSC and SOHIC)

Therefore, hardened steels are the common factor for both mechanisms, making option C the correct choice.

From API RP 571, under Cooling Water Corrosion:

“If proper water treatment is not feasible or consistently maintained, upgrading the metallurgy of exchanger tubes to more corrosion-resistant materials such as stainless steel or titanium may be necessary.”

“This is especially important in seawater or brackish water cooling applications or in once-through systems.”

(Reference: API RP 571, Section 4.3.1.1 – Cooling Water Corrosion)

Thus, the most effective long-term solution in cases of uncontrolled water quality is to upgrade metallurgy, making option C correct.

API RP 571 under Oxidation states:

“Resistance to oxidation is improved significantly by increasing chromium content, as it promotes the formation of a protective chromium oxide (Cr₂O₃) layer.”

“Nickel may aid in high-temperature strength but does not directly improve oxidation resistance like chromium does.”

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

Hence, option A is correct.

API RP 571 provides detailed insights:

“Brittle fracture generally occurs at low temperatures, specifically below the ductile-to-brittle transition temperature as defined by the Charpy impact test.”

“Most carbon and low-alloy steels are ductile above their Charpy transition temperature but may fracture suddenly without ductility below it.”

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

Hence, option C is correct and technically accurate based on the material behavior curve.

According to API RP 571, Section 4.2.1.1 – Sulfidation, and also echoed in API RP 939-C, the presence of certain compounds significantly increases sulfidic corrosion:

“Chlorides are known to accelerate sulfidation and other high-temperature corrosion mechanisms by forming low-melting eutectics and breaking down protective scales on alloy surfaces.”

“Chlorine-containing species also interfere with the formation of stable sulfide or oxide scales, leading to more aggressive metal loss.”

Therefore, chlorides are the most critical accelerant among the listed substances in high-temperature sulfur compound environments, making option C correct.

According to API RP 571:

“Oxidation is the reaction of metal and oxygen to form oxides. It generally occurs in high temperature environments with excess oxygen.”

“Sulfidation is a high temperature corrosion mechanism that occurs due to interaction between sulfur-containing compounds and metal surfaces, forming metal sulfides. Like oxidation, sulfidation occurs in environments above 500 °F (260 °C).”

“Both oxidation and sulfidation can occur concurrently, particularly in mixed environments of oxygen and sulfur.”

(Reference: API RP 571, Sections 5.1.1 and 5.1.3 – Oxidation & Sulfidation)

These two mechanisms are thermally activated and occur in elevated temperature conditions found in heaters, furnaces, and piping systems. Hence, option B is correct.

From API RP 571 Section 5.1.1.3 (Amine Corrosion):

“Amine corrosion is a form of general or localized corrosion caused by the presence of amine solutions used to remove acid gases (H₂S and CO₂)... Corrosion is most severe in areas where acid gas loading is high.”

While temperature and concentration are contributing factors, the primary driver is dissolved acid gases such as COâ‚‚ and Hâ‚‚S.

Thus, the correct answer is Option C.

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).

API RP 571 under Oxidation:

“Carbon steels and low alloy steels, such as 9 Cr, have poor oxidation resistance at temperatures above 1000°F (540°C), rapidly losing thickness.”

“Stainless steels with higher Cr and Ni content (like 310) have superior oxidation resistance.”

Thus, 9 Cr steel will corrode fastest at 1350°F, making option D correct.

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 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.

API RP 571 on Thermal Fatigue emphasizes:

“Thermal fatigue results from cyclic thermal stresses during startup, shutdown, or transient operations.”

“The best mitigation strategy is to control heating and cooling rates to reduce temperature differentials and resulting stress.”

(Reference: API RP 571, Section 4.2.1.5 – Thermal Fatigue)

Hence, option D correctly identifies the preventive action.

API RP 571 under Cooling Water Corrosion and Scaling:

“Cooling water scaling tends to occur more rapidly as water temperature increases. To minimize scaling, inlet temperatures to exchangers should be kept below 140°F (60°C) where possible.”

“Above this temperature, calcium carbonate and other salts tend to precipitate more readily.”

Thus, option A is correct.

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.

API RP 571 and RP 939-C define sulfidation conditions as:

“Sulfidation of iron-based alloys generally becomes significant at temperatures above 500°F (260°C) in hydrocarbon streams with sulfur but without hydrogen.”

“For hydrogen-containing environments, this threshold may be reduced to 450°F (230°C).”

(Reference: API RP 571, Section 4.2.1.1 – Sulfidation; API RP 939-C, Section 3.1)

Therefore, the correct answer is D.

Chloride Stress Corrosion Cracking (Cl-SCC) is a serious form of corrosion primarily affecting austenitic stainless steels and some duplex stainless steels, particularly when exposed to chloride-containing environments at elevated temperatures.

According to API RP 571 Section 5.1.2.3 (Chloride Stress Corrosion Cracking – Cl-SCC):

“Austenitic stainless steels (e.g., 300 series such as Types 304 and 316) are the most susceptible to Cl-SCC... Duplex stainless steels have greater resistance but are not immune, especially at temperatures >150°F (65°C)... Ferritic stainless steels (400 series) are generally not susceptible.”

Thus, Option A (400 Series Stainless Steel) is not susceptible to chloride SCC, making it the correct answer.

API RP 571 on Naphthenic Acid Corrosion (NAC):

“NAC results in thinning, especially in areas of high velocity and turbulence. Standard UT or radiographic inspection followed by UT thickness monitoring is typically used to detect wall loss.”

“Advanced techniques like angle-beam or eddy current are not typically required.”

So, option A correctly reflects the most effective and widely used method.

According to API RP 571, under the section on High Temperature Hydrogen Attack (HTHA) and Decarburization:

“Decarburization is typically confirmed by metallographic examination. This method reveals carbon loss and microstructural changes such as spheroidization or softening of pearlite.”

“Tensile or impact testing may not reveal early-stage decarburization, especially in partial layers.”

Therefore, metallographic testing is the standard and most direct method to confirm decarburization damage, making option D correct.

API RP 571 on Naphthenic Acid Corrosion (NAC) details:

“NAC is most aggressive in two-phase flow where the shear stress is high, such as in elbows, reducers, and at orifices.”

“High velocity and turbulence in two-phase flow strip protective layers and accelerate corrosion.”

Therefore, option A is the correct and most critical phase.

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 provides the following guidance regarding temper embrittlement:

“For materials that contain impurity levels which make them susceptible to temper embrittlement, the most effective preventive measure is to specify low FATT or Charpy impact energy requirements.”

“These requirements ensure the material retains adequate toughness even if embrittlement occurs.”

“While temper embrittlement itself cannot always be fully prevented during long-term exposure to temperatures between 650°F and 1070°F (343°C–577°C), its effects can be identified and mitigated through impact testing criteria.”

Therefore, option C is correct. Specification of Charpy V-notch testing ensures material selection accounts for embrittlement susceptibility and maintains service integrity.

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.

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.

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).

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.

From API RP 571 Section 5.3.3.2 (Caustic Corrosion):

“Caustic corrosion, also known as caustic gouging, occurs in boiler systems when caustic concentrates in under-deposit areas or due to improper steam drum and boiler water design. Good design and water treatment practices are key preventive measures.”

Temperature control or acid injection are not practical or effective mitigation techniques. Design considerations—such as proper water flow, material selection, and minimizing deposits—are essential.

Hence, the correct answer is Option C.

API RP 571, in its discussion on Wet Hâ‚‚S Damage, including HIC, SOHIC, and SSC, consistently identifies a shared mechanism:

“All wet H₂S-related damage mechanisms involve the absorption of atomic hydrogen, formed at the steel surface by the corrosion reaction in the presence of H₂S.”

“The absorbed hydrogen may diffuse into the steel, accumulate at trap sites, and cause cracking or blistering.”

(Reference: API RP 571, Section 4.2.2.7 – Wet H₂S Damage Mechanisms)

Thus, hydrogen absorption and permeation is a unifying mechanism across all these damage modes. Therefore, option D is correct.