packing material for crude distillation column 1

[PAN]

Normally, 410 S.S. is selected as packing material in the distillation column. This packing would be replaced every 5-7 years. Does anyone know the alternative materials for the longer service life in this application? Please comment.

 

[ggordonstewart]

What is causing the corrossion? Is it H2S and other sulphur based components, CO2 or salt? G. Gordon Stewart, P.Eng.
Gas & Oil Process Engineering Consultant

http://www.ggordonstewart.com/

ggstewar@telusplanet.net

 

[PAN]

I understand that there would be HCl (from salt content of feed), H2S and other sulfur compound.

Thanks for your comment.

 

[ggordonstewart]

With a properly designed De-salter, you can reduce the salt content so that it is not a significant corrosive agent. If you need help with this, let me know. G. Gordon Stewart, P.Eng.
Gas & Oil Process Engineering Consultant

http://www.ggordonstewart.com/

ggstewar@telusplanet.net

 

[0707]

If usual you process high TAN crudes may be it wil be useful to use a serie 300 austenitic stainless steel. If that is not the case I sugest you to consult a packing producer such as Glitsh Sulzer or anyother else.

 

[ggordonstewart]

Is there a reason why you cannot use ceramic packing. It is usually impervious to corrosion, but can break under certain process upsets or maintainance procedures. However, it is usually considerably cheaper than stainless steel, so you can afford to replace it more often. G. Gordon Stewart, P.Eng.
Gas & Oil Process Engineering Consultant

http://www.ggordonstewart.com/

ggstewar@telusplanet.net

 

[RichardH]

Consider 317L, the 3% Mo will help if H2S is a problem in the lower section of the column

 

[PAN]

Thanks RichardH. The random packing is in the top part of column. For the lower section, now we use 316L as internal lining. If you have further comment, please advise.

 

[25362]

The kero and gas oil fractions may have naphthenic acidity considered corrosive when boiling and particularly when condensing. Both 316 SS and 317 SS are recommended, the higher Moly content of the later seems to better help vis a vis these corroding acids. From what I've heard most of the acids come in with the crude oil, some are generated by thermal decomposition of pre-existing complex molecules. Kero streams containing these acids may suffer from cloudiness.
The vacuum circuit may also be prone to attack by naphthenic acidity with two additional enhancing factors: high eroding two-phase (V+L) velocities with shearing stresses that eliminate any passivation or filming corrosion inhibitor present, and high turbulence and impingement (impact) of liquid drops. This acidity may appear in the VGOs which, when fed to lube extraction units, may cause corrosion over there. That's another good reason to start the lube refining train with a hydrotreating step.

 

[rolledalloy]

If greater life extension is desired a higher molybdenum alloy such as a 6% Moly stainless steel, like AL-6XN, could also be considered.

It has been used in several refineries that are processing sour crudes. One such gulf coast refinery replaced the top 9 trays from its atmospheric tower. Life was typically 2-3 years with 410 trays that were 11ga (0.120&quot thick. These were replaced by 14ga (0.083&quot thick trays using the 6% moly stainless. Even though the trays were thinner no replacement was required until the trays were in service for 10 years.