API-571 Corrosion and Materials Professional Questions and Answers

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.

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 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.

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 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.

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.

API RP 571, Naphthenic Acid Corrosion:

“Molybdenum significantly improves resistance to naphthenic acid attack. Alloys such as 317, 316Mo, and Alloy 20 are used in severe NAC environments due to higher Mo content.”

“Chromium and nickel play secondary roles; molybdenum is the key element.”

Answer is A – Molybdenum.

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.

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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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.

API RP 571 details that:

“Sulfide Stress Cracking (SSC) susceptibility increases significantly with increased hardness of the steel.”

“NACE MR0175/ISO 15156 provides hardness limits for carbon and low-alloy steels to avoid SSC in sour environments. These are typically limited to 22 HRC or 248 Brinell.”

“High hardness promotes crack initiation under tensile stress in sour environments (i.e., containing H₂S).”

(Reference: API RP 571, Section 4.2.2.1 – Sulfide Stress Corrosion Cracking)

While hydrogen-induced cracking (HIC) and blistering are related to hydrogen charging, SSC is the only mechanism directly and critically impacted by hardness, making option B correct.

According to API RP 571 Section 5.2.1 (Fatigue – High Cycle and Low Cycle):

“Unsupported small-bore attachments like vents and drains are prone to high-cycle mechanical fatigue due to vibration. These attachments experience cyclic stress, especially near welds or bends.”

Thermal overload is unlikely without over-temperature data.

SSC (Option C) requires a wet H2S environment, which is not indicated.

Weld defects may contribute but are less likely the root cause without other signs.

Hence, mechanical fatigue (Option A) is most probable in this configuration.

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.

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.

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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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

According to API RP 571, under the section "Corrosion in Aqueous Environments – Cooling Water Corrosion", one of the key contributors to corrosion in carbon steel and other materials used in heat exchangers is the presence of dissolved oxygen. API RP 571 states:

"Oxygen is a primary contributor to corrosion in cooling water systems. Systems open to the atmosphere are typically more corrosive than closed systems due to the continual replenishment of oxygen."

"Corrosion rates are highest where oxygen concentration is the greatest, especially in systems using untreated or poorly treated water."

"Carbon steel corrodes in the presence of oxygen and water, forming corrosion products that may or may not adhere to the surface."

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

Therefore, increasing oxygen content directly increases corrosion activity in exchanger tubes, making option C the correct and documented answer.

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 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 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 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.

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:

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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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.

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:

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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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.

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 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.

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.

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.

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.

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, 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.

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.

From API RP 571 Section 5.3.2.1 (Creep and Stress Rupture):

“Short-term creep rupture is often associated with localized overheating and results in bulging and thinning, often with a characteristic ‘fish-mouth’ rupture appearance. These failures occur under sustained load in a short time (hours or days), typically in high-temperature service due to a sudden increase in temperature or poor heat distribution.”

Thus, Option B accurately describes the mechanism and visual indications of short-term stress rupture.

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.

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

According to API RP 571 Section 5.3.2.3 (Spheroidization):

“Spheroidization is a microstructural degradation that occurs in carbon steels and low alloy steels when exposed to elevated temperatures for long periods, typically beginning at temperatures as low as 650°F (345°C). It involves the transformation of lamellar pearlite into spherical cementite particles, reducing strength and hardness.”

Thus, Option A (650°F / 345°C) is the minimum threshold temperature for spheroidization to begin.

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.

Comprehensive and Detailed Explanation From Exact Extract:

According to API RP 571, graphitization is a high-temperature degradation mechanism that occurs in carbon and carbon-molybdenum steels exposed for long periods at temperatures typically above 800 °F (425 °C).

In this process:

Iron carbides decompose into free graphite nodules

The steel loses strength, ductility, and pressure-retaining capability

Failures can occur without significant wall loss

Graphitization does not occur in aluminum, stainless steels, or nickel-copper alloys such as Monel.

Referenced Documents (Study Basis):

API RP 571 – Section on Graphitization

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