API-571 Corrosion and Materials Professional Questions and Answers

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

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 CO₂ and H₂S.

Thus, the correct answer is Option C.

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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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.

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 on Oxidation indicates:

“Oxidation is a surface loss phenomenon that generally results in uniform thinning. Ultrasonic thickness measurements are typically used to monitor metal loss in oxidizing environments.”

“Metallography may be used to confirm oxide scale structure but is not necessary for routine evaluation.”

Hence, option B is the most appropriate standard method.

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 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.

As per API RP 571 Section 5.3.2.3 (Spheroidization):

“Spheroidization is the transformation of the microstructure of steels into spherical carbides, leading to reduced strength and hardness, especially after extended high-temperature exposure. It’s commonly seen in carbon and low alloy steels in refining heaters and reactors.”

It reduces strength and sometimes hardness.

It increases ductility, not reduces.

SCC potential is not directly tied to this change.

Therefore, Option D (Loss of strength) is correct.

Comprehensive and Detailed Explanation From Exact Extract:

Concentration Cell Corrosion is defined in API RP 571 as a form of electrochemical corrosion driven by differences in concentration of corrosive species, most commonly oxygen, under deposits or within crevices.

This type of corrosion typically occurs:

Beneath deposits, scale, or fouling

In stagnant zones or crevices

Where oxygen concentration differs between adjacent areas

The area with lower oxygen concentration becomes anodic and corrodes preferentially, while the oxygen-rich area becomes cathodic.

Why the other options are incorrect:

Option B describes galvanic corrosion, not concentration cell corrosion.

Option C refers to high-temperature sulfidation, unrelated to concentration gradients.

Option D describes mechanical damage mechanisms, not electrochemical corrosion.

API RP 571 clearly categorizes concentration cell corrosion as being associated with deposits or crevice conditions, making Option A the correct description.

Referenced Documents (Study Basis):

API RP 571 – Section on Concentration Cell and Crevice Corrosion

API Corrosion Fundamentals Study Guide

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According to API RP 571, in the section on "Chloride Stress Corrosion Cracking (Cl-SCC)", several critical factors are outlined that contribute to the initiation and propagation of this mechanism. The document states:

“Critical factors include the presence of chlorides (even at ppm levels), oxygen, elevated temperatures, tensile stress, and susceptible materials such as austenitic stainless steels and some nickel alloys.”

“Oxygen is an accelerant and promotes pitting that can lead to SCC initiation.”

(Reference: API RP 571, 3rd Edition, Section 4.2.2.2)

Therefore, the presence of oxygen is a well-documented critical factor in Cl-SCC. It acts in conjunction with chlorides to initiate localized pitting, which then progresses into cracking. Hence, option B is the correct choice.

Comprehensive and Detailed Explanation From Exact Extract:

Grooving corrosion in cooling water systems is a well-documented damage mechanism in API RP 571, particularly associated with high-velocity flow conditions.

Flow-induced erosion (also referred to as erosion-corrosion or flow-assisted corrosion) occurs when:

High fluid velocity removes protective corrosion films

Local turbulence, elbows, or inlet zones focus mechanical wear

Soft metals or alloys are exposed to continuous impingement

This results in smooth, directional grooves or channels aligned with the flow direction, a classic signature described in API RP 571.

Why the other options are incorrect:

Option A: ERW defects affect weld seams, not general grooving patterns.

Option B: MIC typically causes localized pitting, not uniform grooving.

Option D: Underdeposit corrosion produces irregular pitting beneath deposits, not flow-aligned grooves.

API RP 571 specifically identifies flow-induced erosion as a primary cause of grooving in cooling water heat exchanger tubes.

Referenced Documents (Study Basis):

API RP 571 – Section on Erosion/Erosion-Corrosion

API Cooling Water System Corrosion Study Guide

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Comprehensive and Detailed Explanation From Exact Extract:

Wet H₂S damage mechanisms include hydrogen blistering, hydrogen-induced cracking (HIC), stepwise cracking (SWC), and stress-oriented hydrogen-induced cracking (SOHIC). These mechanisms are primarily internal and subsurface, as described in API RP 571.

Shear Wave Ultrasonic Testing (SWUT) is specifically highlighted in API RP 571 as a preferred screening and detection method for wet H₂S damage because it can detect subsurface planar defects with minimal surface preparation. Typically, only basic coupling and access are required.

Why the other options are incorrect:

Option A (ACFM) is a surface crack detection technique and requires relatively clean surfaces; it is not suitable for subsurface hydrogen damage.

Option C (WFMT – Wet Fluorescent Magnetic Particle Testing) requires extensive surface preparation, coating removal, and direct access to the surface, and only detects surface-breaking flaws.

Option D (LPT – Liquid Penetrant Testing) also requires clean, bare metal surfaces and cannot detect subsurface damage.

API RP 571 explicitly notes that ultrasonic techniques, particularly shear wave UT, are widely used for detecting internal hydrogen-related cracking with minimal disruption and surface preparation, making it the most effective choice for wet H₂S damage screening.

Referenced Documents (Study Basis):

API RP 571 – Section on Wet H₂S Damage (HIC, SOHIC, Blistering)

API Corrosion and Materials Inspection Study Guide

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, chromium is the most effective alloying element for improving oxidation resistance in steels.

Chromium:

Forms a stable, adherent chromium oxide (Cr₂O₃) scale

Greatly reduces oxidation rates at elevated temperatures

Is the basis for oxidation-resistant alloys and stainless steels

Other alloying elements may provide secondary benefits, but chromium is the primary contributor to oxidation resistance.

Referenced Documents (Study Basis):

API RP 571 – Section on Oxidation and High-Temperature Corrosion

API RP 571, in its discussion on Wet H₂S 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.

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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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.

Per API RP 571, susceptibility to hydrogen embrittlement is strongly influenced by:

Material strength level

Microstructure

Heat treatment condition

Heat treatment determines:

Dislocation density

Trap sites for hydrogen

Residual stress state

The modulus of elasticity does not significantly affect hydrogen embrittlement susceptibility, making Option A incorrect.

Referenced Documents (Study Basis):

API RP 571 – Section on Hydrogen Embrittlement

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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.

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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Comprehensive and Detailed Explanation From Exact Extract:

Per API RP 571, chloride stress corrosion cracking (Cl-SCC) of austenitic stainless steels is strongly influenced by low pH environments in the presence of chlorides, tensile stress, and elevated temperature.

API RP 571 identifies that:

Chloride SCC can initiate at very low pH levels

pH values near 2 represent a threshold where aggressive chloride attack and cracking become possible

Increasing acidity dramatically increases SCC susceptibility

Therefore, pH = 2 is the lowest and most critical value listed where chloride SCC can begin.

Referenced Documents (Study Basis):

API RP 571 – Section on Chloride Stress Corrosion Cracking

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API RP 571 states in the section on Creep Damage:

“Creep damage in carbon steels generally becomes a concern above 700°F (371°C), especially for steels with higher tensile strength (greater than 60 ksi).”

“For prolonged exposure above this temperature, time-dependent deformation can lead to material degradation and cracking, especially at weldments and stress concentrations.”

Thus, the lowest threshold for creep in high-strength carbon steels is 700°F (371°C), making option B correct.

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.

According to API RP 571:

“Ammonium chloride corrosion is most aggressive when dry salts are exposed to a small amount of free water. This condition allows the formation of a concentrated acidic aqueous solution, which is highly corrosive to carbon steel.”

“The corrosion mechanism is activated especially during startup and shutdown when condensation may occur on salt deposits.”

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

Hence, while salt deposition begins as temperatures drop, the most aggressive corrosion happens when water is introduced to dry salt, making option D 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).

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.

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.

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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Galvanic corrosion occurs when two dissimilar metals are electrically connected in the presence of an electrolyte such as brackish water or seawater. The rate and severity of galvanic corrosion depend on:

The relative position of the metals on the galvanic series (potential difference)

Area ratio between anode and cathode

Conductivity of the electrolyte

API RP 571 explains:

“The more active (anodic) metal in the galvanic couple corrodes preferentially. The more noble (cathodic) metal is protected.”

“The greater the difference in potential between the two metals, the more aggressive the galvanic reaction.”

“Aluminum is highly anodic compared to steel. In seawater or brackish conditions, aluminum will corrode rapidly when electrically coupled to steel, especially if the aluminum surface area is small relative to the steel.”

(Reference: API RP 571, Section 4.3.5.1 – Galvanic Corrosion)

Referring to the galvanic series presented in your table:

Aluminum is much higher (more anodic) than steel.

This makes aluminum the sacrificial metal in such a pair.

This is not the case for brass-to-nickel or cast iron-to-Ni-Resist, which are much closer together on the galvanic scale.

Therefore, among all the listed pairs, Aluminum coupled to Steel creates the most significant galvanic potential difference and is most likely to result in galvanic corrosion in brackish or seawater service.

Correct Answer: B

From API RP 571 Section 4.2.3 (Galvanic Corrosion):

“Galvanic corrosion occurs when two dissimilar metals are in electrical contact in the presence of an electrolyte. The more anodic metal corrodes preferentially.”

Contact without insulation and in presence of an electrolyte (like water or brine) is key to galvanic action.

Insulating or coating prevents electrical connection or electrolyte contact, reducing corrosion risk.

Hence, Option D correctly describes the condition that increases galvanic corrosion potential.

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.

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.

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.

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.

API RP 571 explains the typical location of dissimilar metal weld (DMW) cracks as follows:

“DMW cracking usually occurs in the heat-affected zone (HAZ) on the ferritic side of the weld.”

“The difference in thermal expansion coefficients, grain structures, and creep rates between the ferritic and austenitic materials contributes to the development of high stress and strain concentrations in the HAZ of the ferritic material.”

(Reference: API RP 571, Section 4.2.1.6 – Dissimilar Metal Weld Cracking)

Thus, these cracks do not occur in the center of the weld or on the austenitic side, but rather at the ferritic HAZ, making option A 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.

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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Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, creep damage is a time-dependent, high-temperature damage mechanism that occurs when materials are exposed to stress at temperatures typically above about 700 °F (370 °C) for extended periods. Creep damage results in void formation, microcracking, grain boundary separation, and eventual rupture.

Once creep damage has occurred, it is considered irreversible metallurgical degradation. API RP 571 clearly states that heat treatments cannot restore creep life because the material’s microstructure has already been permanently damaged.

Option A (PWHT at 1150 °F) may relieve residual stresses but does not heal creep voids or microcracks.

Option B (Solution annealing) is applicable to certain stainless steels but is not effective for reversing creep damage, particularly in low-alloy and Cr-Mo steels.

Option D (Preheating during welding) helps prevent hydrogen-related cracking but has no effect on existing creep damage.

API RP 571 emphasizes that the only effective mitigation for creep damage is to remove the affected material and replace it with sound material, or to retire the component if damage is widespread. Fitness-for-service assessments (API 579-1/ASME FFS-1) may be used to evaluate remaining life, but mitigation requires material removal.

Referenced Documents (Study Basis):

API RP 571 – Section on Creep and Stress Rupture Damage

API Corrosion and Materials Study Guide

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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.

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

“Postweld heat treatment (PWHT) does not significantly reduce susceptibility to HIC, as the mechanism is primarily driven by hydrogen charging in wet H₂S environments and steel cleanliness, not residual stresses.”

“PWHT is more effective for SSC, SOHIC, and other stress-driven mechanisms.”

Thus, HIC will not benefit much from PWHT, making option C correct.

API RP 571 notes that for detecting existing cracks or flaws that may lead to brittle fracture, especially those that initiate at welds or surface stress points:

“Wet fluorescent magnetic-particle inspection is highly effective for detecting surface-breaking flaws in ferromagnetic materials that are susceptible to brittle fracture.”

“It is sensitive to tight cracks and surface discontinuities that may serve as initiation sites for brittle fracture.”

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

Therefore, option A is correct as it is the most effective NDE technique for detecting early signs of brittle cracking.