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In our refinery Crude column overhead liquid is condensed in Fin fan coolers. Condensed liquid then collected in receiver. Recently we had problem of severe fouling in fin fan coolers inlet line. Can you explain the possible cause for that? Also suggest some recommendation to avoid such kind of fouling in fin fan inlet header.
 
Answers
06/04/2010 A: Mike Watson, Tube Tech International Ltd, mike.watson@tubetech.com
Specialising in cleaning severely fouled shell and tube exchangers, e.g. Fin Fan condenser tubes / Fins, Tubetech often find traditional, local jetting contractors leave heavy washings / sediment inside the header as no drain exists nor off the shelf technology to extract the waste from the header boxes.
Not knowing the pipe layout, is there a chance that sediment has remained in the system, which can be vast, has travelled back into the inlet line? Perhaps an On-Line cleaning system is of value to you.
05/04/2010 A: Eric Vetters, ProCorr Consulting Services, ewvetters@yahoo.com
Most likely you are getting salts formed in the overhead line. The salts will normally be either ammonium chloride or an amine chloride (either from your neutralizer, tramp refinery amines or an H2S scavenger in the crude). When the salt formation temperature is higher than the water dew point, you can expect to get salt precipitation with associated fouling and corrosion. If the salt point is close enough to the tower overhead temperature then heat losses in the overhead line, which is typically uninsulated, can create localized cold spots that allow the salts to form.

The most sure fire solution is to install a water wash in the overhead line that will force the water dew point and prevent salt formation. If the salts are ammonium chloride, then trying to reduce the amount of ammonia in the desalter wash water (changing water source or improving sour water stripper operation) may help. If it's amine neutralizer salts, then you may need to change to a chemistry with a lower salt formation temperature. If it's tramp amines then you may be able to trace back to find amine losses and how they are getting to your crude unit. Eliminating the source would then solve the problem. If it's H2S scavengers, then you may need to figure out which crude contains them and eliminate that crude from your supply.

Your chemical supplier should be able to analyze the water from your overhead accumulator boot and run their own proprietary ionic model to help you figure out what is causing your problem.
03/04/2010 A: Ralph Ragsdale, Ragsdale Refining Courses, ralph.ragsdale@att.net
Fouling in the overhead can be caused by several things, including the results of corrosion or chemical reactions. Here is an excerpt from my course manual:
"Corrosion in the overhead of the atmospheric column is controlled in some plants by the injection of filming amines and wash water circulation to force water condensation to occur in the piping upstream of the condenser/exchanger. Some plants have upgraded the metallurgy in this section as well. Sometimes ammonia is injected to neutralize HCl and CO2. However, if the condenser is monel, the ammonia will attack it. Sometimes caustic is injected downstream of the desalter to reduce the chlorides that would hydrolyze and go overhead, and to neutralize CO2. A global survey indicated that approximately one-half of refiners inject caustic ahead of the hot train or crude furnace inlet for overhead chloride control.
A new class of crudes have low total acidity but yield low molecular weight acids such as formic, acetic, and proprionic acids during the atmospheric distillation process. Mitigation steps being practiced includes water wash, neutralzer addition, and filming amine injection.
Amine based scavengers used when shipping synthetic crudes can result in HCl salt deposits in the crude unit. Such tramp amines can more readily be removed by the use of an extraction aid in the water to the desalter."
03/04/2010 A: keith bowers, B and B Consulting, kebowers47@gmail.com
It would assist our efforts to help if you could provide more information on the TYPE of fouling--polymeric? water soluble?
If the recent experience coincided with a new crude, it is possible heater outlet temperature was too high for that crude and thermal cracking was taking place. In a similar fashion, corrosion products may be the culprit. OR, the desalting operation was not operating correctly.