What causes the acidic water at the top of an atmospheric pressure tower to turn black?
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Recently, the acidic water at the top of the atmospheric tower in the atmospheric and vacuum distillation unit has been turning black, and the naphtha occasionally turns black as well; there are also some solid-like particles present, mixed between the water and gasoline. The level of iron ions can be high at times and low at other times; the acidic water and the dark substances in naphtha are deliberately heated to high temperatures until they burn away, and what remains is all rust, which can be attracted by a magnet. The operation is stable, all parameters remain unchanged, and the amount of neutralizing and corrosion-inhibiting agents has even been increased. No abnormalities were found in the thickness measurement of the atmospheric tower overhead distillate line. Moreover, the impellers of the top circulation pump have all corroded away. Has anyone else encountered such a situation? Attached is a photo:
What kind of crude oil is being processed, and what is the salt content after desalting?
Lula, a small amount of Marique crude oil, U.S. shale oil.
Is there no online corrosion probe monitoring? Let’s first increase the number of thickness control points. Let’s control the corrosion risk first. Also, the temperature at the top of your tower and the temperature in the top recirculation tower are both quite low, right?
1. Situation of electrodesalination 2. Organochlorines in crude oil
In your case, you should consider the issue of dew point corrosion. First, it’s necessary to analyze and test whether there have been any changes in the neutralizing and corrosion-inhibiting agents. Additionally, since the temperature at the top of the tower hasn’t changed, it’s possible that this has led to a shift in the dew point, thereby causing corrosion in the cooling system at the top of the tower.
Due to chronic corrosion issues, large amounts of FeS accumulate on the pipe walls, causing under-scale corrosion. Whenever some of this scale is washed away, iron ion levels rise above the normal range; if no scale is washed away, those levels remain low. Increasing the amount of neutralizing corrosion inhibitor is not the only way to address corrosion, as the stronger the alkalinity, the easier it is for FeS to precipitate. Generally, it is reasonable to neutralize the corrosion inhibitor to a pH value between 6 and 8, as long as there is sufficient amount of the corrosion-inhibiting component. Under these current conditions, corrosion is difficult to control; either the operation must be halted, the FeS in the pipelines must be passivated and cleaned, followed by re-applying a protective coating while maintaining a pH level between 6 and 8, along with the addition of sufficient corrosion inhibitors – this approach can resolve the problem completely ； Alternatively, the amount of neutralizing corrosion inhibitor added can be reduced, with the pH value kept around 6 to facilitate the in-line dissolution of FeS. However, the in-line cleaning time is generally long, and strict control over the pH level is required – it must not drop below 5, otherwise corrosion will be exacerbated.
The corrosion inhibitor is fine; there’s no change in the initial or subsequent pressure drops, and the same corrosion inhibitor is being used. Dew point corrosion has not moved backward; samples taken from the top of the tower are all black water.
Fluctuations in pH value have a significant impact on corrosion; it is essential to keep it stable and make frequent adjustments. Because when the pH is below 6, corrosion tends to occur at an excessive rate, while a pH above 8 causes the iron that has corroded to turn into FeS precipitates. Repeated fluctuations only increase the amount of these precipitates, making it difficult to achieve stability. FeS gradually forms into large deposits that adhere to the pipe walls, preventing the corrosion inhibitor from forming a protective film; this in turn leads to corrosion beneath the deposits.