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In our CDU unit we have a problem in the heat exchangers of the top reflex ( top reflex 160 C exchange with crude oil 60 C ) after 2 years of the starting of the unit , suddenly we have damage in the Heat Exchangers ( there is 8 exchangers A - H and each tow exchangers in parallel and after condensation of naphtha it accumulated in reflex drum 130 C ) so the damage was observed only in the bottom exchangers ( B-D-F-H ) on top of tube bundle . the chemical injection are : Corr. inhbt and N. Amine on the top tower reflex and Filming amine and N. Amine on the vapor line from the reflex drum to the air coolers and Trim coolers . so what the reasons of the corrosin in these exchangers ?

Jan-2025

Answers

JAYA KULSHRESHTH, EIL, jaya.kulshreshth@gmail.com

The corrosion damage observed in the bottom heat exchangers (B, D, F, H) at the top of the tube bundle in your CDU unit is likely caused by ammonium salt deposition, under-deposit corrosion, and acidic attack due to chloride contamination. Given that the top reflux stream at 160°C contains neutralizing amine, ammonium chloride (NH₄Cl) or ammonium bisulfate (NH₄HSO₄) salts may form as the stream cools, leading to localized corrosion at condensation points. The presence of condensed naphtha in the reflux drum suggests possible phase separation issues, which may contribute to uneven chemical distribution and inadequate protection in certain areas. Overdosing or improper distribution of neutralizing and filming amines could also create imbalances in pH, resulting in localized acid formation and increased corrosion rates. Additionally, hydrochloric acid (HCl) formation from chloride contamination in crude oil may further exacerbate the problem, particularly in areas where water is insufficient to wash out corrosive deposits. To mitigate these issues, it is recommended to analyze salt deposition on the tube bundle, monitor ammonium salt dew points, and ensure process temperatures remain above the deposition threshold. Optimizing chemical injection strategies, such as balancing neutralizing amine dosages and ensuring proper filming amine coverage, is crucial. Implementing controlled water washing upstream can help remove chloride salts before condensation, while corrosion probes and periodic UT thickness measurements can provide early detection and monitoring of corrosion trends.

Feb-2025
sam lordo, Becht, salordo@comcast.net

This indicates a couple of possible issues 1) maldistribution of the chemical additive injection and process flow on the shell side. I would need to see the configuration of the overhead, bear in mind there is never a prefect symmetrical design 2) since it sounds like it it is just between the exchanger banks that would be the location you are getting initial condensation and if the neutralizer is not properly added this would be low pH water (1-2); quick fix would be to make sure each exchanger bank is getting filmer, and then triple the dosage. 3) injecting neutralizer into your reflux back to the tower (if i understood you correctly) is not a good idea... you can corrosive salts forming in the tower if you don't have a water wash (properly designed) you should consider it ,, water should be injected into each of the exchanger banks... if you do have a water wash as i described , the add filmer to the water wash to make sure it gets well distributed.

Feb-2025
Marcio Wagner da Silva, Petrobras, marciows@petrobras.com.br

Considering the information in the question the processing unit is suffering from salt deposition, it' important to confirm this through the analysis of the corrosion mechanism predominant in the bundle of the heat exchanges, probably the predominant mechanism is under deposit corrosion. There is a growing concern related to chloride concentration in the feed of processing units which can lead to severe corrosive process due to salt deposition, this is a special issue for refiners processing crudes with high concentration of nitrogen which can lead to formation of ammonium chloride (NH4Cl) in higher temperatures than it's normally observed. It's necessary to understand how is the performance of the desalting system aiming to keep under control the chloride content in the desalted crude as well as to manage the chloride content in the sour water of the top drum of the atmospheric tower, normally this chloride concentration is considered adequate below than 40ppm. It's important to analyze the content of chloride salts (MgCl2 and CaCl2) in the processed crude. These salts can suffer hydrolysis and generate hydrogen chloride (HCl) which can cause drastic reduction in the pH. According to the concentration of chloride salts in the crude oil it's possible to minimize this problem by injecting sodium hydroxide (NaOH) upstream of the desalting vessels aiming to neutralize the hydrochlorides compounds. Another alternative to control the corrosion process provoked by salt deposition is to apply water injection in critical points aiming to ensure a washing process of the deposited salts. The information that the corrosion process is occurring only in the bottom exchangers (B-D-F-H) can mean that these equipment can operate under lower velocity of the process stream, favoring the salt deposition. Another relevant action is to calculate and monitor the salt precipitation temperature of the unit. There is good references in the literature containing some precipitation charts for the Ammonium Bisulphide (NH4HS) and NH4Cl (Ammonium Chloride), through the measure of the ammonium and chloride content it's possible to determine the precipitation temperature and control the operating temperature some grades above to avoid salt precipitation and, consequently, the corrosion process.

Jan-2025