API API-571 Corrosion and Materials Professional Exam Practice Test

As per API RP 571 Section 5.3.2.2 (Sigma Phase Embrittlement):

“Sigma phase embrittlement occurs in austenitic stainless steels (like 300 series) and duplex stainless steels exposed to 1000°F to 1800°F (540°C to 980°C)... This embrittlement results in a significant loss of toughness and ductility.”

Sigma phase is not a concern in Monel (nickel-copper alloy) or 5Cr steels.

400 series are ferritic and not typically affected by sigma phase.

Hence, Option A (300 series stainless steel) is correct.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, refractory materials are non-metallic and therefore do not experience metallic corrosion mechanisms such as carburization, sulfidation, or oxidation.

Instead, refractories degrade through:

Dusting (loss of material due to chemical or thermal attack)

Checking (crack formation caused by thermal cycling and differential expansion)

These are the primary and characteristic damage modes of refractories in high-temperature service.

Referenced Documents (Study Basis):

API RP 571 – Section on Refractory Degradation

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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 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 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.

API RP 571 states under Chloride Stress Corrosion Cracking (Cl-SCC):

“Nickel contents above approximately 35% provide significant resistance to chloride stress corrosion cracking. Alloys such as Alloy 625 and Alloy 825 exhibit excellent resistance.”

“Austenitic stainless steels with lower nickel contents, such as 304 and 316, are more susceptible to Cl-SCC.”

Hence, option C (35%) is correct.

API RP 571 on Brittle Fracture notes:

“The primary factor influencing brittle fracture is material toughness, especially at low temperatures.”

“Materials with low fracture toughness are susceptible to catastrophic failure when stressed below their ductile-to-brittle transition temperature.”

Hence, option A is correct.

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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In API RP 571, Carbonate SCC and Alkaline SCC are both discussed under mechanisms that occur in basic (high pH) environments, often with similar contributing conditions and prevention methods. The document highlights:

“Carbonate SCC is considered a subcategory of alkaline stress corrosion cracking. It results from the concentration of alkaline carbonates under thermal insulation or deposits.”

“Both mechanisms involve the same key parameters: elevated temperatures, tensile stress, and high pH solutions.”

(Reference: API RP 571, 3rd Edition, Section 4.2.2.4 and 4.2.2.3)

Because these mechanisms share similar material susceptibility and operating conditions, they are indeed closely related—option B is therefore the accurate and supported answer.

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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API RP 571 states under Galvanic Corrosion:

“Because galvanic corrosion usually manifests as thinning of the more anodic metal, ultrasonic thickness measurements taken near dissimilar metal joints are an effective way to detect this type of internal corrosion.”

“Surface NDE techniques like liquid penetrant or magnetic particle testing are not effective for detecting wall loss.”

Thus, option D (ultrasonic thickness testing) is correct.

Comprehensive and Detailed Explanation From Exact Extract:

Hydrochloric acid (HCl) corrosion in atmospheric crude units is primarily associated with the overhead system, where chloride salts hydrolyze to form HCl in the presence of condensed water. This damage mechanism is well documented in API RP 571 under “Chloride Stress Corrosion Cracking and Hydrochloric Acid Corrosion”.

The primary indicator of HCl corrosion risk is the acidity of the condensed water in the overhead system. The overhead accumulator boot water collects condensed water where dissolved HCl will be present. Monitoring the pH of this water provides a direct, real-time indication of acid formation and corrosion severity.

Low pH values (typically below 5.5) indicate active HCl corrosion conditions.

API RP 571 states that pH monitoring is a key operational control and surveillance tool for managing overhead corrosion.

Why the other options are incorrect:

Option A (UT at water injection points) does not address overhead acid formation and is not a susceptibility monitoring method.

Option C (Corrosion probes or coupons) provide general corrosion rate data, but they do not directly measure HCl formation or acid severity and often respond too slowly for operational control.

Option D (UT scanning or radiography) is a damage detection method, not a susceptibility or early-warning monitoring technique.

API RP 571 emphasizes that effective monitoring of HCl corrosion requires controlling and monitoring water chemistry, especially pH in the overhead accumulator boot, to prevent severe localized corrosion and ammonium chloride salt deposition.

Referenced Documents (Study Basis):

API RP 571 – Section on Hydrochloric Acid Corrosion in Crude Unit Overhead Systems

API Corrosion and Materials Study Guides – Atmospheric Crude Unit Overhead Corrosion

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.

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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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.

Comprehensive and Detailed Explanation From Exact Extract:

Per API RP 571, 885 °F (475 °C) embrittlement primarily affects carbon and low-alloy steels, causing a loss of toughness without obvious microstructural changes visible by routine metallography. Because the damage mechanism manifests as a shift in ductile-to-brittle transition temperature (DBTT), confirmation requires mechanical property testing, not surface or volumetric NDE.

Impact testing (Charpy V-notch) and bend testing are specifically cited as effective methods to demonstrate the loss of toughness and increased brittleness associated with 475 °C embrittlement.

Why the other options are incorrect:

Metallography often shows little or no visible change.

Magnetic particle testing only detects surface-breaking flaws.

Ductility testing alone is not as definitive as impact toughness testing.

Referenced Documents (Study Basis):

API RP 571 – Section on 885 °F (475 °C) Embrittlement

API Corrosion and Materials Study Guide

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Comprehensive and Detailed Explanation From Exact Extract:

Per API RP 571, deaerators often operate in environments where concentrated caustic solutions can form locally due to oxygen scavengers and water chemistry control additives.

When postweld heat treatment (PWHT) is not performed:

High residual welding stresses remain

Conditions are ideal for caustic stress corrosion cracking (Caustic SCC)

API RP 571 identifies deaerators as classic examples of equipment that has experienced caustic SCC when PWHT was omitted.

Referenced Documents (Study Basis):

API RP 571 – Section on Caustic Stress Corrosion Cracking

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API RP 571 on Chloride Stress Corrosion Cracking (Cl-SCC) clearly states:

“Austenitic stainless steels such as 304 and 316 are highly susceptible to Cl-SCC when subjected to tensile stress and exposed to chloride-bearing environments.”

“Susceptibility is greatest in non-stress-relieved weldments or cold-worked areas.”

Brass and carbon steels are not typical Cl-SCC candidates; low alloy steels such as 1.25Cr-0.5Mo are also not commonly affected.

Thus, option C is the correct answer.

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.

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 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, 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 and API RP 583 (CUI-specific guidance):

“Neutron backscatter techniques are effective in detecting moisture within insulation systems, which can indicate areas of concern for corrosion under insulation (CUI).”

“This method provides non-invasive, quick identification of wet insulation without removing cladding.”

(Reference: API RP 571, Section 4.5.1 – Corrosion Under Insulation and API RP 583 – CUI Detection Techniques)

Thus, neutron backscatter is the preferred NDE method for moisture detection, making option B correct.

API RP 571 discusses Hydrogen-Induced Cracking (HIC) and Blistering under the section:

“HIC and blistering are most strongly influenced by non-metallic inclusions, particularly elongated manganese sulfide (MnS) inclusions, which serve as trap sites for hydrogen atoms.”

“These inclusions create local planes of weakness where atomic hydrogen recombines into molecular hydrogen (H₂), causing high pressure and cracking.”

(Reference: API RP 571, Section 4.2.2.7 – Hydrogen Blistering and HIC)

Thus, inclusions are the critical material factor, making option A correct.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, temper embrittlement is a metallurgical condition that affects Cr-Mo low-alloy steels, including 1-1/4 Cr-1/2 Mo, when exposed to temperatures typically in the range of 650 °F to 1100 °F (345 °C to 595 °C) over extended periods. This damage mechanism results in a significant loss of fracture toughness and ductility, particularly at lower temperatures.

API RP 939-C further explains that temper embrittlement does not significantly reduce tensile strength, but it raises the ductile-to-brittle transition temperature (DBTT). As a result, equipment that appears structurally sound may fail catastrophically under sudden loading conditions.

Once ductility is reduced, the material becomes especially vulnerable to rapid temperature changes, which induce high thermal stresses. Thermal shock is therefore a critical secondary damage mechanism. Sudden quenching, cold feed introduction, startup, shutdown, or uneven heating can cause cracking because the embrittled material can no longer accommodate strain plastically.

Option A (Ductile rupture) is incorrect because temper embrittlement promotes brittle fracture, not ductile failure.

Option B (885 °F embrittlement) is incorrect because 885 °F (475 °C) embrittlement primarily affects carbon steels and some stainless steels, not Cr-Mo steels.

Option D (Graphitization) occurs at prolonged exposure above approximately 800 °F (425 °C) in carbon steels and is not the dominant concern for 1-1/4 Cr-1/2 Mo steel in this context.

API RP 571 explicitly emphasizes that embrittled Cr-Mo steels are highly susceptible to cracking during thermal transients, making thermal shock the most likely and dangerous subsequent damage mechanism.

Referenced Documents (Study Basis):

API RP 571 – Section on Temper Embrittlement of Low-Alloy Steels

API RP 939-C – Metallurgical Effects and Service Risks of Temper Embrittlement

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According to API RP 571 Section 5.3.2.1 (Creep):

“Creep damage is exponentially dependent on temperature. A small increase in temperature (e.g., 25°F or 15°C) can reduce remaining life by more than half. This is because the creep rate increases rapidly with temperature, especially above design limits.”

Stress is a contributing factor, but the dominant and most sensitive variable is temperature.

Thus, Option C (increase in temperature of 25°F/15°C) is the correct answer.

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 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.

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 and API RP 941 (Nelson Curves), 1 Cr–0.5 Mo steel is no longer recommended for services susceptible to High-Temperature Hydrogen Attack (HTHA).

API RP 941 documents industry experience showing that 1 Cr–0.5 Mo steels have suffered HTHA damage below previously assumed safe operating limits, due to insufficient carbide stability. As a result, this material has been removed from the Nelson Curves as an acceptable choice for new construction in hydrogen service.

By contrast:

Mn–0.5 Mo, C–0.5 Mo, and 1.25 Cr–0.5 Mo steels retain higher resistance due to more stable carbide structures.

Referenced Documents (Study Basis):

API RP 571 – Section on High-Temperature Hydrogen Attack

API RP 941 – Updated Nelson Curves and Material Recommendations

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Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, carbon steel exhibits a minimum corrosion rate in sulfuric acid at concentrations around 65–70 wt% due to formation of a protective iron sulfate film.

When sulfuric acid concentration drops below approximately 65%, this protective film becomes unstable and corrosion rates increase dramatically.

Referenced Documents (Study Basis):

API RP 571 – Section on Sulfuric Acid Corrosion

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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.

According to API RP 571, under Caustic Stress Corrosion Cracking (Caustic Embrittlement):

“Cracking occurs in stressed components exposed to caustic (e.g., sodium hydroxide).”

“The most effective mitigation strategy is postweld heat treatment (PWHT), which relieves residual stress that promotes cracking.”

“Upgrading materials or controlling concentration may help, but do not replace stress relief.”

(Reference: API RP 571, Section 4.2.2.3 – Caustic SCC)

Thus, PWHT is the most effective prevention technique, making option A correct.

API RP 571 describes Temper Embrittlement as:

“A metallurgical degradation mechanism that leads to a reduction in fracture toughness due to long-term exposure in the temperature range of 650°F to 1070°F (345°C to 575°C).”

“It affects Cr-Mo steels and is not easily detected except by impact testing.”

Therefore, option C most accurately defines the condition based on the recognized API description.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, hydrogen embrittlement (HE) of carbon steels is a low-temperature damage mechanism. It occurs when atomic hydrogen enters the steel lattice, reducing ductility and toughness and potentially causing cracking or delayed failure.

API RP 571 clearly differentiates HE from high-temperature hydrogen damage mechanisms (such as HTHA). Hydrogen embrittlement is most severe at ambient to moderately elevated temperatures, typically below about 200 °F (93 °C), where hydrogen mobility and trapping promote embrittlement.

At higher temperatures, hydrogen tends to diffuse out of the steel and embrittlement effects diminish.

Referenced Documents (Study Basis):

API RP 571 – Section on Hydrogen Embrittlement

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From API RP 571 Section 5.1.2.5 (Polythionic Acid Stress Corrosion Cracking):

“PTASCC typically occurs on the surface of stainless steels that have been sensitized. Since cracks are open to the surface, liquid penetrant testing (PT) is the most effective detection method.”

Magnetic particle testing is ineffective for non-magnetic materials like austenitic stainless steels.

UT is less effective for fine surface-connected cracks.

Hardness testing is unrelated to detecting cracking.

Thus, Option C (Liquid penetrant testing) is the correct and preferred method for detecting PTASCC.

API RP 571 under Atmospheric Corrosion notes:

“The highest corrosion rates are typically observed between 80°F and 120°F (27°C–49°C), particularly when relative humidity is high and surfaces are wet from condensation or rain.”

“At higher temperatures, surface dryness generally reduces corrosion activity despite increased reaction kinetics.”

(Reference: API RP 571, Section 4.3.1.3 – Atmospheric Corrosion)

Thus, among the listed temperatures, 175°F is closest to the upper end of the most active corrosion window, making option A the most accurate answer.

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.

According to API RP 571 Section 5.1.2.1 (Hydrogen-Induced Cracking) and Publ 939-A, blistering in carbon and low alloy steels exposed to wet H2S environments can be exacerbated by the presence of cyanides. These accelerate hydrogen entry into steel, increasing the chance of hydrogen blistering.

API RP 571 states:

“HIC and blistering are forms of hydrogen damage that occur in wet H2S environments. The presence of cyanides can significantly increase hydrogen entry and the risk of blistering.”

Publ 939-A (Research on Cracking in Wet H2S Service) also notes:

“Cyanides act as catalytic agents in hydrogen charging, which promotes internal pressure build-up and increases blistering.”

Thus, cyanides (Option B) are the most critical in enhancing blistering in H2S environments.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, amine stress corrosion cracking (Amine SCC) is a form of environmentally assisted cracking that occurs in alkanolamine systems (e.g., MEA, DEA, DGA) used for acid gas treating. The cracking mechanism requires the simultaneous presence of tensile stress, susceptible microstructure, and an amine environment.

API RP 571 clearly states that Amine SCC occurs primarily in the weld heat affected zone (HAZ) of carbon and low-alloy steels. The reasons include:

The HAZ contains high residual stresses from welding.

The microstructure in the HAZ is metallurgically altered, making it more susceptible than base metal.

Cracks often initiate adjacent to welds, not in the weld metal itself.

Why the other options are incorrect:

Option A (Weld fusion line) is not the primary cracking location.

Option C (Weld metal) generally has different chemistry and lower susceptibility.

Option D (Base metal) typically has lower residual stress and is less prone.

API RP 571 specifically identifies the weld HAZ as the dominant cracking location for Amine SCC.

Referenced Documents (Study Basis):

API RP 571 – Section on Amine Stress Corrosion Cracking

API Corrosion and Materials Study Guide

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API RP 571 describes under Caustic Corrosion:

“One of the significant contributing factors is caustic accumulation in low-flow or stagnant areas, especially in heat-traced lines or around steam injection points.”

“Localized heating can concentrate caustic solutions, promoting corrosion even in carbon or stainless steels.”

Thus, option C (heat-traced equipment) is the correct and technically accurate choice.

Comprehensive and Detailed Explanation From Exact Extract:

In HF Alkylation units, API RP 571 identifies certain residual alloying elements in carbon steel that can significantly increase corrosion rates in HF acid service.

The most detrimental residual elements are:

Chromium (Cr)

Copper (Cu)

Nickel (Ni)

These elements:

Disrupt formation of protective iron fluoride films

Increase general and localized corrosion rates

Are tightly controlled in carbon steel specifications for HF service

Referenced Documents (Study Basis):

API RP 571 – Section on Hydrofluoric Acid Corrosion

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From API RP 571 and RP 932-B:

“In hydroprocessing reactor effluent systems, the most common corrosion mechanism is ammonium bisulfide (NH₄HS) corrosion, which forms in the presence of hydrogen sulfide and ammonia.”

“NH₄HS attacks carbon steel aggressively under turbulent flow and at low pH.”

Correct answer is B – ammonium bisulfide corrosion.

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.