Acid Gas Treating #1
Next to sales contract specifications, corrosion protection ranks highest among the reasons for the removal of acid gases. The partial pressure of the acid gases may be used as a measure to determine whether treatment is required. The partial pressure of a gas is defined as the total pressure of the system times the mole % of the gaseous component. Where CO2 is present with free water, a partial pressure of 30 psia or greater would indicate that CO2 corrosion should be expected. If CO2 is not
removed, inhibition and special metallurgy may be required. Below 15 psia, CO2 corrosion is not normally a problem, although inhibition may be required.
H2S may cause hydrogen embrittlement in certain metals. Figures 7-1 and 7-2 show the H2S concentration at which the National Association of Corrosion Engineers (NACE) recommends special metallurgy to guard against H2S corrosion.
In the sulfide stress cracking region, appropriate metallurgy is required in line piping, pressure vessels, etc. There is a listing of acceptable steels in the NACE standard. Steels with a hardness of less than 22
Rockwell C hardness should be used in areas where sulfide-stress cracking is a problem.
The concentration of H2S required for sulfide-stress cracking in a multiphase gas/liquid system (Figure 7-2) is somewhat higher than in pure gas streams (Figure 7-1). The liquid acts as an inhibitor.
This chapter discusses the different processes that are commonly used in field gas treating of acid gases and presents a method that can be used to select from among the various processes. Design procedures for determining critical sizing parameters for iron sponge and amine systems are presented, as these are the most common field gas treating processes currently employed and they are not proprietary in nature.
Categories: Acid Gas Treating | Tags: Acid Gas Treating | Leave a comment