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The unstabilized naphtha streams from our CDU preflash and crude columns and off gases from hydroprocessing units are processed in Saturated gas plant (SGP). Processing separate out the gas and liquid products by a combination of compression, cooling and fractionation.
The gases are compressed and combined with hydrocarbon liquid, cooled in a high pressure receiver to separate the mixture into vapor and hydrocarbon liquids.
The vapor after C3,C4 recovery and amine treatment is sent to fuel gas system while the liquid hydrocarbon rich in Naphtha/LPG is pumped to Stripper followed by naphtha stabilizer and finally naphtha splitter to split naphtha into Heavy naphtha and light naphtha.
The Stripper is a reboiled 32 tray column with top tray feed provided to remove C2 and lighter components from the liquid product.
The stream composition and process condition of stripper overhead vapor is as follows:

Stream Description - Stripper OVHD
Stream Phase - Vapor
Total Molar Rate KG-MOL/HR - 1,021.58
Total Mass Rate KG/HR - 46,931.65
Temperature - C 87.15
Pressure - KG/CM2G 10.3
Total Molar Comp. Rates KG-MOL/HR
H2O 12.02
H2 26.49
NH3 0.78
H2S 205.46
METHANE 18.78
ETHANE 179.66
PROPANE 200.35
IBUTANE 91.72
BUTANE 153.85
IPENTANE 33.23
PENTANE 36.16
CP 0.02
C6+ 63.05816096

We are not injecting any corrosion inhibitor in stripper overhead stream. Is it a concern? Should we be dosing a corrosion inhibitor in stripper overhead stream based on the ammonia, water and H2S levels in stripper overhead?
 
Answers
13/06/2013 A: Ralph Ragsdale, Ragsdale Refining Courses, ralph.ragsdale@att.net
My understanding is that this is the stripper overhead stream, non-condensed vapor, feeding the absorber. The pipe should be traced and insulated, but is not usual practice to inject corrosion inhibitor. If the absorber and the stripper were stacked as a "reboiled absorber", this line would be the feed tray of the single column. That's the way I have designed this service in Saturates Gas Plants.