API API-571 Corrosion and Materials Professional Exam Practice Test

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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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.

According to API RP 571 and API RP 751:

“In HF alkylation units, carbon steel can be used if weld hardness is controlled to ≤ 200 Brinell (BHN). Exceeding this can significantly increase the corrosion rate and susceptibility to cracking.”

“Hard welds act as preferential corrosion sites due to microstructural inhomogeneity and stress concentration.”

(Reference: API RP 571, Section 4.3.3.4 – Hydrofluoric Acid Corrosion; API RP 751, Section 5.3 – Materials of Construction)

Thus, option D is correct.

Erosion and erosion-corrosion are mechanical degradation mechanisms enhanced by fluid motion, and typically result in directional or flow-oriented metal loss patterns.

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

“Erosion typically results in localized thinning, often described as grooves, gullies, or horseshoe-shaped patterns... The metal loss is directional and may occur in elbows, tees, reducers, and pumps.”

Hence, Option C (grooves and gullies) most accurately describes erosion and erosion-corrosion characteristics.

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.

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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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.

API RP 571 under Ammonium Chloride Corrosion details:

“The corrosion results from the deposition of ammonium chloride salts from high-temperature process streams as they cool.”

“This typically occurs in crude unit overheads or other systems where salts condense out as the stream temperature drops below their dew point.”

“Corrosion becomes especially aggressive when the salts are wetted by condensation.”

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

Therefore, option A is technically accurate and supported.

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 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 578 (Material Verification Program), referenced in API RP 571, specifically calls out sulfidation failures as a major driver for Positive Material Identification (PMI):

“PMI programs are particularly important in services prone to sulfidation where incorrect alloying elements (e.g., carbon steel used in place of low Cr alloy) have led to catastrophic failures.”

“Many failures have occurred when carbon steel was mistakenly installed in place of specified Cr-alloys in sulfidation-prone environments.”

(Reference: API RP 578 and API RP 571, Section 4.2.1.1 – Sulfidation)

Thus, option C is the most appropriate answer.

As per API RP 571 on Sigma Phase Embrittlement:

“Sigma phase embrittlement occurs in stainless steels and nickel-based alloys due to the formation of a brittle intermetallic phase in the temperature range of 1050°F to 1650°F (565°C to 900°C).”

“This damage mechanism is not easily detected through surface or hardness testing and typically requires metallographic examination to confirm the presence of sigma phase in the microstructure.”

Metallographic testing allows clear identification of sigma phase particles and is thus the most reliable method, making option D correct.

According to API RP 571, in the section on Boiler Water Condensate Corrosion:

“The major contributors to condensate corrosion are dissolved CO₂ and O₂. Carbon dioxide forms carbonic acid in the presence of water, lowering pH and causing generalized corrosion.”

“Oxygen causes pitting and localized corrosion unless chemically treated.”

Thus, option B (Carbon dioxide and oxygen) is the primary root cause and the correct answer.

According to API RP 571, under Naphthenic Acid Corrosion (NAC):

“The most severe corrosion is typically found in areas of high velocity and turbulence, such as at pump around nozzles, transfer lines, elbows, reducers, and orifices.”

“NAC is characterized by uniform thinning and can accelerate significantly where flow-induced erosion is present.”

(Reference: API RP 571, Section 4.3.4.1 – Naphthenic Acid Corrosion)

This clearly establishes that high velocity and turbulence increase NAC severity, making option D correct.

Comprehensive and Detailed Explanation From Exact Extract:

Ethanol stress corrosion cracking (SCC) of carbon steel is strongly dependent on the presence of water.

Per API RP 571, moisture content is the primary controlling factor, because:

Water enables formation of corrosive species

Dry or very low-water ethanol does not cause SCC

Even small amounts of water significantly increase cracking risk

Other factors influence severity, but without moisture, ethanol SCC does not occur.

Referenced Documents (Study Basis):

API RP 571 – Section on Ethanol Stress Corrosion Cracking

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Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, corrosion fatigue results from the combined action of a cyclic stress and a corrosive environment. One of the most important distinguishing features between corrosion fatigue and SCC is crack morphology.

Corrosion fatigue cracks are typically transgranular and show little or no branching

Stress corrosion cracking is characterized by extensive crack branching

Therefore, the absence of significant branching is a key diagnostic feature of corrosion fatigue.

Referenced Documents (Study Basis):

API RP 571 – Section on Corrosion Fatigue

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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.

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.

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 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.

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.

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 discusses this under Wet H₂S Damage – Hydrogen Blistering, HIC, SOHIC:

“Hydrogen generation is reduced as pH increases. At pH 9 and above, the corrosion potential is less favorable for hydrogen charging and thus permeation into the steel is minimal.”

“Most wet H₂S cracking damage mechanisms are accelerated under acidic conditions (pH < 7).”

Hence, high pH (around 9) environments offer the most protection against hydrogen damage, making option D 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 "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.

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 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.

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.

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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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.

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

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:

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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API RP 571 under Thermal Fatigue highlights:

“Differential thermal expansion between dissimilar materials (e.g., carbon steel and stainless steel) in welds causes high cyclic stresses that can result in thermal fatigue cracking.”

“These stresses typically occur during transient thermal cycling such as startup/shutdown operations.”

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

Thus, the correct mechanism resulting from differential expansion in bimetallic welds is thermal fatigue, making option B correct.

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

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.

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.

Comprehensive and Detailed Explanation From Exact Extract:

Amine stress corrosion cracking is most frequently associated with rich amine services, where:

Acid gas loading (H₂S / CO₂) is high

Corrosive contaminants and degradation products are present

Higher operating temperatures and stresses exist

Per API RP 571, cracking is far more common in rich amine systems than in lean amine circuits.

Why the other options are incorrect:

Lean amine has lower acid gas content and reduced SCC risk

SCC is not limited to low temperatures

Concentration alone is not the dominant factor

Referenced Documents (Study Basis):

API RP 571 – Section on Amine Stress Corrosion Cracking

According to API RP 941, and also noted in RP 571:

“Nickel significantly improves resistance to HTHA (High Temperature Hydrogen Attack) by stabilizing austenitic phases and reducing carbide decomposition.”

Hence, option C is 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).

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 5.1.1.3 (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:

High-Temperature Hydrogen Attack (HTHA) is described in API RP 571 and API RP 941 as a damage mechanism where hydrogen reacts with carbides at elevated temperature and pressure, forming methane and causing loss of strength and fissuring.

Prevention is primarily achieved by selecting materials with stable carbides that resist hydrogen attack. Chromium and molybdenum alloying elements:

Form more stable carbides

Reduce susceptibility to methane formation

Extend safe operating limits

Why the other options are incorrect:

Option B may be used in some services but is not the usual prevention method.

Option C is incorrect because RP 941 does not recommend high-nickel alloys as the primary solution.

Option D low-carbon steels are more susceptible, not resistant.

API RP 571 clearly identifies Cr-Mo alloy steels as the standard mitigation approach.

Referenced Documents (Study Basis):

API RP 571 – Section on High-Temperature Hydrogen Attack

API RP 941 – Nelson Curves and Material Selection

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Comprehensive and Detailed Explanation From Exact Extract:

Per API RP 571, mechanical fatigue failures are identified by the presence of beach marks or clam shell patterns on the fracture surface.

These features:

Appear as concentric rings

Represent successive crack growth increments

Radiate outward from the crack initiation site

This “clam shell” or “beach mark” appearance is one of the most recognizable signatures of fatigue failure.

Referenced Documents (Study Basis):

API RP 571 – Section on Mechanical Fatigue

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