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Heavy naphtha main tower corrosion

Home Forums Coking Technical Fractionation & Process Fractionation Heavy naphtha main tower corrosion

This topic contains 4 replies, has 3 voices, and was last updated by  Hedewandro Lucredi 3 years, 4 months ago.

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  • #27467

    Hedewandro Lucredi
    Participant

    We are suffering a huge corrosion problem in the heavy naphtha packing bed of the DCU main tower. The packing bed material is SS 316. Is it possible to inject anti corrosion chemicals in this specific point of the main tower ? Or even in the heavy naphtha stream circuit ? Or in the reflux tower ? what is it the experience about that ?

  • #27468

    dblewis
    Participant

    What is the temperature of this portion of the tower? If it is too cold, steam will start to condense and cause corrosion. It is also possible that salts can form and actually plug the bed.

  • #27472

    Mike Kimbrell
    Participant

    I agree that low tower temperatures resulting in salt deposition is a likely cause for this corrosion. The first point is to ensure that the top temperature of the fractionator is above the water dew point. A typical margin is 25 F (15 C) over the calculated water dew point as a minimum. The next is to calculate the salt point based on ammonium chloride salts. Chlorides in the fractionator overhead water should be no more than 10 ppm and should be less than 5 ppm typically. This is primarily controlled by how well the feed to the unit was desalted in the upstream crude unit. Any slops streams feed to the Coker should be checked for chlorides to keep that feed from being a source of chlorides in the overhead.

    I have copied some comments I posted to another similar question that is relevant:

    Corrosion in the upper portion of the Coker fractionator is normally due to ammonium chloride salts depositing in the tower. If that is the case for your unit, raising the top temperature of the fractionator above the salt point will prevent corrosion in the tower. One of the products from the thermal decomposition reactions is ammonia. Salts in the feed to the unit will be hydrolyzed and generate HCl that will form ammonium chloride salts at a low enough temperature. At typical conditions for the fractionator overhead system, moderate concentrations of chlorides result in relatively high salt points. My normal recommendation is to keep the fractionator top temperature above 250 F (120 C). This assumes that the chloride level in the overhead water is less than 5 ppm. With good desalting in the upstream crude unit, the chlorides in the overhead water of the Coker fractionator will be well below 5 ppm. If the chloride concentrations are higher, then salt point is higher and those ammonium chloride salts are extremely corrosive.
    Tramp amines can form amine chloride salts as well. One of the decomposition products of some of the H2S scavengers is MEA (mono ethanol amine) that forms a very corrosive amine chloride salt at lower temperatures than ammonium chloride salts.
    If you have ammonium chloride or amine chloride salt corrosion occurring in the Coker fractionator, raise the fractionator top temperature or lower the chlorides in the overhead system by improving desalting in the upstream units. Some crude towers inject an imidazolene based filming amine into the top of the tower to move the salts out of the tower and into the pump around systems. The chemical vendors also sell an ammonium chloride salt dispersant chemical that has had good performance in FCC and other main fractionators. You could consider using one of those, if it is confirmed you have ammonium chloride salt deposition.

  • #27501

    Hedewandro Lucredi
    Participant

    The temperature is around 150 Celsius. The corrosion products are from chlorides of our poor desalter

  • #27512

    Hedewandro Lucredi
    Participant

    It was confirmed that the fractionator top temperature is around 10 degree C above the estimated water dew point. Additionally, there are no salting problems at this region.

    The severe corrosion is found around packing bed #2 (heavy naphtha). The salt point was estimated, based on chloride and ammonia concentrations, and it was confirmed that NH4Cl deposition can be occurring at this region. That is why we are interested to know about the use of corrosion inhibitors in intermediate tower sections…
    The refinery is trying to solve some known desalting problems in order to reduce the chloride content in the DCU feed.

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