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We are fractionating the feedstock from natural gas condensates into Naphtha, Kerosene, gas oil and residual stream. The overhead condenser of the first distillation tower suffers from very bad corrosion. The fact is we are not desalting the incoming feed, due to the salt content is 0.5~1.5 ptb based on ASTM-D3230 test result. We only inject the neutralizing and filming amine to the condenser inlet header instead of feed desalting.
Upon condenser outlet piping replacement we found a huge amount of sludge sitting inside the old-thin piping. The sludge is >95% Fe.
The questions are :
1. Does ASTM D-3230 also reflect the Sulfates salt in the feed stock? Because the water boot contains total S more than total Cl. We worry that Sulfates salt also being hydrolyzed to produce h2SO4 that corrodes the overhead piping. If sulfates salts are also create corrosion problem than how to check the salt content other than Cl salt?
2. Beside chloride content, what are to be checked in the feedstock before deciding to stop desalting? What is the method to check?
3. We plan to install a water wash system in order to prevent sludge deposition and under deposit corrosion. The problem is the condenser pipe header is non balanced type ( E manifold, not C manifold). We are in doubt whether the water will be evenly distributed to all branch to condenser inlets.
 
Answers
14/03/2012 A: Sudhakara Babu Marpudi, Dangote Oil Refinery Company, m_sudhakarababu@yahoo.com
ASTM D 3230 is a method of assessing salt levels based on conductivity. Conductivity gets affected by the metals present in the system. The proven method for salts assessment is by IP 77 extraction of salt as NaCl. However, the 1.5 PTB of salts correlate to IP 77 values of ~ 0.8 PTB of salts. Gnerally the Desalters will be designed to lower the salt levels to either 99%of inlet salts or <1.0 PTB. If the salts are already at <1.0 PTB level Desalter will not be justified economically.
In my view corrosion can only be controlled but can not be prevented as the remaining salts (<1.0 PTB stuff) will continue to form acids. Best way to control corrosion is to maintain the overhead sour water pH in the range of 5.5 - 6.5 and have filming amine + Neutralising amine injection to the system. pH above 7.0 is the basic reason for sludge formation and this can be aggravated by the Ammonium Chloride deposition. Water injection is mainly for washing of the Ammonium Chlorides that are the reason for the under deposit corrosion. There are sophisticated water spray nozzle systems available in the market depending the budgets. Sludge with lessor Ammonium chloride will only foul the Top Pump Around system (exchangers if any) and that can be only be cleaned up periodically / physically. Prevention (maintaining the sour water pH slightly acidic and protect the system from Acid attack by the filming amine) is the best recommended practice in case of Sludge.
12/03/2012 A: Ralph Ragsdale, Ragsdale Refining Courses, ralph.ragsdale@att.net
As to the water wash system design: It has been emphasized several times at industry conferences the importance of injecting the water at each inlet to the air cooled condenser, and to use a properly designed and installed quill at each location, even with balanced piping arrangements, which you do not have.