Q & A > Question Details
In our naphtha hydrotreating unit, iron contents in stripper overhead boot are being reported on higher side for the last month. So far we have tried the following:
1. Increased corrosion inhibitor injection from 3 wt ppm (design) to 7 wt ppm.
2. Replaced the corrosion inhibitor
3. Cold condensate injection in reactor effluent increased from 3 to 5.5% of feed.
But iron contents are still high (2~3 ppm).
What could be the possible cause and what is the solution?
02/09/2007 A: Amarjit Bakshi, Refining Hydrocarbon Technologies LLC, abakshi@rhtgulfcoast.com
Addendum to earlier response:
What is the PH of the boot condensate/water ?
If it is acidic which one would expect, our earlier answer should solve the problem.
If you have a very high nitrogen content in the crude, then ammonium bisulfite/ammonia could be another problem.
Both will exacerbate corrosion, but running the condenser hotter as suggested and directing the vent together with lights to wet gas compressor should solve the problem, or additional stage of condensing from 70 C to 40 C should also take care of this situation. ......
02/09/2007 A: Amarjit Bakshi, Refining Hydrocarbon Technologies LLC, abakshi@rhtgulfcoast.com
Thanks for follow up.
Well, it might be that I did not make myself clear that the 60 to 70 C (140 -158 F) was the condensing temperature of the Stripper overhead stream rather than 40 C, and not the stripper overhead temperature, so as to reduce the solubility of H2S in cold condensate which will be in the boot and would increase corrosion in the Condenser itself and all downstream equipment, reflux drum including boot.
You do mention about desalter not operating properly, but that will be chloride stress cracking which is a separate issue. One should keep an eye on chloride based stress cracking which is another issue as regards to safety and failure of equipment.
As mentioned above. raising the condensing temperature will keep most of H2S in vapor phase, and the solubility of H2S in condensate will be reduced which will provide less acidic water/condensate in the boot which should take care of the problem. If you need to discuss further please call at +1- 281- 398- 8408 and we might be talk about providing some technical service in this area.......
31/08/2007 A: Original Questioner, Follow Up,
Thanks for your reply. Here are some process conditions.
Our stripper top temperature is on lower side 80~90°C (Design 101°C). This is because of our crude. We are using crude which is mixture of AL, UZ, Murban and local. IBP of stablized naphtha coming o NHT is also on lower side (38~42°C). Yes, CDU desalter has not been working normally since April 2004. But the sulfur content in NHT feed are normal (<0.015 wt%).
We have also checked the Chlorides in overhead boot (~27 ppm). Results of CC are normal.
Problem still persists.
29/08/2007 A: Amarjit Bakshi, Refining Hydrocarbon Technologies LLC, abakshi@rhtgulfcoast.com
The answer to the present problem would be to run the Naphtha hydrotreater stripper a little hotter: at about 60 to 70 degrees Celsius ( 140 to 158 F). This will reduce the corrosion in the stripper overhead and iron content of the boot.
The vent either can be routed to Wet Gas compressor in FCC unit or provide a vent condenser and small drum with boot. This should reduce the corrosion problems.
Now, here are some questions regarding why the corrosion has increased:
1. Has the Feed sulphur drastically increased to the Naphtha Hydrotreater, which has increased the H2S Content in the overhead of stripper system?
2. Have you changed the stripper overhead temperature or cold condensate quantity or any other conditions which has enhanced the corrosion.
Anyway, the above answer should solve the problem even if your problems are due to changes as mentioned in item 1 and 2 above.
Please see the Selective Hydrogenation (including HDS) article in PTQ Q3 2007 which details new developments in HDS area and consultancy services and solution to oil refining operation problems. Also look at www.rhtgulfcoast.com.