API 571 Sample Questions

Q1. In a hydroprocessing unit effluent train, you find whitish/greenish/brownish salt deposits that can be removed by water washing/steam-out. UT follow-up finds very localized pitting under the deposits. Which answer BEST fits the described observations AND the documented relationship between the salt deposits and acid formation?

• A. Hydrochloric acid corrosion (aqueous HCl) is the primary mechanism; ammonium chloride salting is unrelated to corrosion.
• B. Ammonium chloride corrosion/salting is the primary mechanism causing deposits and localized under-deposit pitting; aqueous HCl can also form beneath these deposits when water is present.
• C. Ammonium bisulfide corrosion is the primary mechanism because all sour-water salts look similar and always precipitate at 120–150 °F.
• D. Chloride stress corrosion cracking is the primary mechanism because chlorides always cause cracking when salts are present.

Q2. (Select ALL that apply) Which statements are explicitly supported for ammonium bisulfide corrosion (alkaline sour water) per API 571?

• A. For carbon steel, solutions below 2 wt% NH4HS are not generally corrosive; above 2 wt% they become increasingly corrosive.
• B. NH4HS can precipitate from the gas phase in reactor effluent streams when temperatures drop into about 120 °F to 150 °F, potentially causing fouling/plugging unless flushed with wash water.
• C. NH4HS salt deposits can lead to under-deposit corrosion; the salts are not corrosive unless they become hydrated.
• D. NH4HS corrosion severity in certain units can increase in the presence of cyanides because protective sulfide film protection is diminished.

Q3. In a hydroprocessing reactor effluent circuit, corrosion is worst at air cooler header boxes, exchanger inlets/outlets, and other high-turbulence areas. Operations reports salt precipitation/fouling around 120–150 °F and asks what concentration threshold matters for carbon steel. Which choice BEST matches API 571’s mechanism and critical-factor guidance?

• A. Ammonium bisulfide corrosion; below about 2 wt% NH4HS solutions are not generally corrosive to carbon steel, and NH4HS can precipitate around 120–150 °F, causing fouling unless flushed with wash water.
• B. Ammonium chloride corrosion; below 2 wt% NH4Cl solutions are not generally corrosive and salts precipitate at 120–150 °F.
• C. Hydrochloric acid corrosion; below pH 4.5 HCl becomes noncorrosive, and precipitation is controlled by TAN.
• D. Naphthenic acid corrosion; it precipitates around 120–150 °F and is controlled by cyanides.

Q4. (Select ALL that apply) Which statements correctly connect ammonium chloride/amine hydrochloride salt deposition with monitoring/mitigation expectations and the risk of aqueous HCl formation?

• A. Salts may deposit above the water dew point; a water wash injection may be required to dissolve them.
• B. Process simulation may be required to determine concentrations and dew point temperatures; controlling metal temperature above the calculated salt deposition temperature can be effective.
• C. Hydrogen chloride gas is normally not corrosive in dry streams but becomes very corrosive where water is available to form hydrochloric acid.
• D. 300 series SS and 400 series SS are usefully resistant to HCl at many refinery concentrations if temperature is controlled below the acid dew point.

Q5. Cracks are found on non-PWHT’d carbon steel near welds in an amine system. The cracks are parallel to the weld, can look similar to wet H2S cracking on the surface, and metallography shows intergranular, oxide-filled cracking with some branching. Which option BEST matches the mechanism identification AND the recommended minimum stress-relief temperature stated for mitigation?

• A. Caustic SCC; minimum stress relief temperature is 1150 °F (620 °C) minimum with 1 hr hold.
• B. Amine SCC; recommended minimum stress-relief temperature is 1175 ± 25 °F (635 ± 15 °C).
• C. Chloride SCC; recommended mitigation is stress relieving 300 series stainless steel after fabrication as a standard practice.
• D. Hydrochloric acid corrosion; mitigation is upgrading to Alloy 400 or titanium because 300 series SS is resistant.

Q6. (Select ALL that apply) A crack lab report says: “Cracking in 300 series SS appears transgranular and can be difficult to distinguish from chloride SCC; however, crack surfaces show a black magnetite layer.” Which statements are correct based on API 571’s guidance for distinguishing similar cracking mechanisms?

• A. The black magnetite layer on the crack surface supports caustic SCC rather than chloride SCC.
• B. Caustic SCC in carbon steel commonly propagates parallel to welds in adjacent base metal (high residual stress zone).
• C. Carbon steels and low-alloy steels are not susceptible to chloride SCC.
• D. External chloride SCC concern range is 140 °F to 400 °F when insulation gets wet.

Q7. An insulated 300-series stainless line develops spider-web/craze cracking with little or no visible corrosion. The insulation is known to get wet, and the operating temperature is in the range most concerning for this issue. Which answer BEST matches the mechanism AND the temperature range API 571 highlights for concern?

• A. External chloride stress corrosion cracking; most concern is 140 °F to 400 °F when insulation gets wet.
• B. Caustic SCC; most concern is 120 °F to 150 °F due to precipitation.
• C. Naphthenic acid corrosion; most concern is 425 °F to 800 °F with two-phase flow.
• D. CO2 corrosion; most concern is above 250 °F because surfaces are too dry for corrosion to occur.

Q8. (Select ALL that apply) Which statements are correct about amine SCC and caustic SCC based on the documented appearance/mitigation information?

• A. Amine SCC cracking can develop parallel to the weld and may look similar to wet H2S cracking on the surface; positive ID can be confirmed by metallography showing intergranular, oxide-filled cracking with some branching.
• B. The recommended minimum stress-relief temperature stated for carbon steel welds in amine service is 1175 ± 25 °F.
• C. Caustic SCC can occur at low caustic levels (e.g., 50 ppm to 100 ppm) if a concentrating mechanism is present.
• D. For caustic SCC, crack propagation rates can increase dramatically with temperature and through-wall cracking can occur in hours during temperature excursions.

Q9. A crude/vacuum circuit shows localized metal loss concentrated at high-velocity/turbulent areas and is worst in two-phase flow regions. The crude slate includes very low sulfur material, and the team is arguing whether TAN alone is enough to rank risk. Which mechanism BEST fits AND which key prediction limitation is explicitly stated?

• A. Naphthenic acid corrosion; whole crude TAN correlation with corrosion rate is poor because severity depends on the naphthenic acids present in the actual stream/cut, not just crude TAN.
• B. Hydrochloric acid corrosion; whole crude TAN is a strong predictor because HCl concentration is directly proportional to TAN.
• C. Ammonium chloride corrosion; TAN is the controlling factor for ammonium chloride deposition temperature.
• D. Ammonium bisulfide corrosion; TAN strongly predicts NH4HS concentration.

Q10. (Select ALL that apply) Which statements align with API 571’s discussion of naphthenic acid corrosion (NAC) severity drivers and material guidance?

• A. Whole crude TAN can be misleading because correlation between whole crude TAN and corrosion rate is poor; severity depends on the naphthenic acids present in the actual stream/cut.
• B. NAC primarily occurs above 425 °F, has been reported as low as 350 °F, and severity increases with temperature up to about 750 °F (with cases observed higher in certain services).
• C. Increasing molybdenum content improves resistance; while 316/316L (≈2% Mo) may be adequate in some applications, industry experience generally agrees that ≥3% Mo (e.g., 317/317L) is needed to avoid NAC in many cases.
• D. NAC is best controlled by ensuring metal temperatures remain below the water dew point so the surface stays wet and protective.