This presentation summarizes the development and expansion of a comprehensive information system for corrosion of metals and alloys in high temperature gases. New insights in analysis of thermochemical data for the Fe-Ni-Cr-Co-C-O-S-N system are being compiled. Corrosion mechanisms emphasized are oxidation, sulfidation, sulfidation/oxidation, and carburization.
Many alloys exposed in high-temperature process equipment corrode by sulfidation corrosion in the presence of H2-H2S gases. This paper discusses the latest results of an extensive testing program for a diverse group of about 15 commercial alloys exposed to temperatures of 300 - 900°C with exposure times up to 6,000 hours.
The corrosivity of four mercaptans and selected crude oil fractions were measured in lab tests. Conclusion: Mercaptan corrosion can contribute significantly to the total sulfur related corrosion in the temperature range 235–300°C, which agrees with observations of elevated temperature corrosion in refinery distillation equipment.
Sulfur and acidic impurities in crude oils pose serious hot oil corrosion problems in crude distillation units (CDU) and associated vacuum distillation units (VDU), especially with the increase in processing of lowquality, opportunity crudes.1-4 In the range of 200-400˚C, reactive sulfur compounds cause sulfidation corrosion of ferritic carbon and chrome steels in CDU, VDU, and front ends of downstream units operating at hot oil temperatures.5-7 Over the same temperature range, naturally occurring carboxylic acids in crudes can be so aggressive that higher alloy, austenitic stainless steels containing >2.5% Mo are required for processing high acid oils.8-11 Although sulfidation and acid corrosion occur over the same temperature range, they differ in two significant ways. Sulfidation forms an iron sulfide solid that is semiresistant to further corrosion and relatively insensitive to flow velocity. Acids form oil soluble organic salts that can be washed away especially in areas of high turbulence.12-14
Naphthenic acids and sulfur species in crude oil cause severe corrosion of the steel equipment of crude distillation units in oil refineries.1–3 Because of rapidly changing oil economics, the refineries have inclined towards cheaper “opportunity crudes”, but the high levels of corrosive species, mainly naphthenic acids and organosulfur compounds, in these crudes would reduce the life of the equipment, and also increase the risk of catastrophic failure.3 So the opportunity crudes are often blended with the crudes containing lower levels of corrosive species; this decreases overall concentration of corrosive species and the corrosion rates.4,5 However, corrosion rates are not simply proportional to the concentrations of naphthenic acids and sulfur species that are present in the crude oil.4,5 Without accurate estimation of corrosion rates by crude oils or their “blends”, carbon steel equipment needs to be constructed with higher wall thickness for safety; if still insufficient, high alloy steels are required.
In Corrosion/2021, the authors introduced a molecular mechanistic model that quantifies and predicts SNAPS corrosion rates. During Corrosion/2022, we presented the mechanistic corrosion prediction framework describing the molecular basis of the model’s reactions, kinetics, and mass transport of ROSC to vessel walls. In this molecular model, sulfidation corrosion is calculated for direct heterolytic reaction of ROSC with solid surfaces.
In Corrosion/2021, the authors introduced a molecular mechanistic model that quantifies and predicts simultaneous naphthenic acid and sulfidation (SNAPS) corrosion rates. During Corrosion/2022, we presented the mechanistic corrosion prediction framework describing the molecular basis of the model’s reactions, kinetics, and mass transport of reactive organic sulfur compounds (ROSC) to vessel walls. In this molecular model, sulfidation corrosion is calculated for direct heterolytic reaction of ROSC with solid surfaces.
A sulfur recovery unit (SRU) train in a gas processing facility went under an emergency shutdown due to the failure of a reaction furnace waste heat boiler (WHB) tube. The failed tube had been in service for approximately 18 years. The failed tube was subjected to a number of metallurgical laboratory examinations in order to determine the damage mechanism and root cause(s) of the failure. Examinations included visual inspection, scale analysis, chemical analysis, metallographic examination and mechanical testing. The examination revealed internal corrosion thinning in the tube which led to rupture since the tube could no longer withstand the pressure. Metallographic examination revealed spheroidized microstructure indicating that the tube experienced high metal temperature. This is suggesting that something was impeding heat transfer between the tube and water. Scale analysis results from a sample collected from the tube internal surface indicated the presence of iron sulfide corrosion products. Based on the aforementioned findings, it was concluded that the corrosion thinning was caused by sulfidation. Sulfidation is one of the potential damage mechanisms in WHB tubes and is caused by reactive sulfur species as a result of the thermal decomposition of sulfur compounds at high temperatures (above 500oF). Failure contributing factors as well as corrective actions to prevent recurrence of such failure are discussed in this paper.