How to determine that you have sour service or seever corrosive environment for a vessel, when the only thing you are provided with is co2 content of the vapor?
Sour service refers specifically to the effects of H2S - if you do not have any, then sour service is not an issue.
CO2 corrosion is a different issue and many companies, like Shell for example, have developed assessment procedures for CO2 service.
A corrosive environment said to be sour if H2S(hydrogen sulphide) is present in that environment. If there is none,the environment is not sour.
In other to determine the corrosivity of the flüid in a vessel a knowledge the % composition of the vessel's content is required.The following substances are corrosive:CO2,SO2,Chlorides,H2S; acid forming salts and gases in general. The Oxygen content of the vessel aslo determines corrosivity. The temperature of the environment also plays important role. others such as the level of agitation, if liquid has effect,etc
1.0 NACEMR0175: Defines partial pressures of H2S that
would term the service "sour" exceptions to low
pressure systems below 235 psig. "0.05 psia <- if
memory helps"
2.0 Other forms of hydrogen damage such as HIC are not
addressed by NACEMR0175; several IOCs consider
sour service in liquid phase if H2S content exceeds
50 ppm. Noting that HIC failure has occured at
concentrations as low as 20 ppm and the phenomena is
not pressure dependent as is the case with Sulphide
Stress Cracking.
I believe, a new NACE Std was recently issued NACEMR0130 which is comprehensive is addressing sour service.
Full knowledge of the chemistry of the process fluid, and the temperature/pressure conditions are required to determine severity of corrosion. For example, will water vapor condense? I have had carbon steel pipe in sweet crudes that pitted at 0.120" per year because water condensed at approximately 140 F - 150 F just beyond the christmas tree. Corrosion was limited to about 300 ft of piping. Well analysis indicated small water content and < 2% CO2.
