Effect of sulfur content, iron ions, and acid value in tower distillate oil on equipment corrosion
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Dear teachers, I would like to ask: when the properties of the crude oil processed by the plant deteriorate, with significant increases in sulfur and acid value levels in the crude oil, sampling and analysis before and after these changes show that the sulfur, acid value, and iron content in the distillates from various columns have increased markedly. Are there any clear control criteria for such analysis data? How to determine the severity of corrosion? Or rather, what is the relationship with the corrosion rate?
This is generally determined by the iron ion content; generally, an iron ion level of 5 ppm or less is considered normal. This requirement can generally be met by adding a high-temperature oil-soluble corrosion inhibitor; feel free to contact me
Generally, an iron ion content of 5 ppm or less is considered normal. Could you please tell me where this value comes from?
The iron ion content in the condensate water at the top of the measuring tower can be determined by this
Maybe I expressed myself poorly. What I mean is, you said that an iron ion content of 5 ppm or less can be considered normal – where does this figure come from? Are there standards? Additionally, what I’m referring to is not the iron ion content in the condensate water at the top of the towers, but rather the iron content in the distillate oils from each tower