Gas 2025 Issue

loading possibly contributed to the attack along with chlo- rides. It is also possible that the probe was made with a grade of stainless steel with poor chloride resistance (410SS, 304SS, for example). 316L should be the stainless steel of choice for facilities operating with elevated chloride levels. The amine unit was operating with a high lean and rich amine loading. High amine loadings corrode carbon steel rapidly. Normally, to return the rich amine loading within guidelines, the unit should increase the solvent circulation rate. However, the reboiler limitations could not regener- ate the current low solvent flow rates, and any increase in recirculation rates would require an increase in reboiler duty (25% increase in recirculation rates translates to an increase of 25% in reboiler duty). Another option to lower the rich amine loading was a higher solvent strength. However, a 20 wt% maximum concentration MEA is recommended (solution corrosivity increases as the strength increases). The regeneration of the rich amine appears to be occur- ring too low location-wise in the regenerator column. The prime reason for this is a low rich amine feed temperature entering the regenerator (rich outlet temperature from the L/R exchanger). The L/R exchanger needs to be upgraded to attain a minimum outlet rich amine temperature of 195°F (91ºC). Combined strategies The amine unit needs to target a regenerator overhead temperature of at least 215°F (102ºC), or corrosion in the hot lean amine circuit of the unit will continue to take place. The elevated stainless corrosion in the unit is not a normal occurrence when signs of carbon steel corrosion are low. High chloride levels in the solvent are most likely contrib- uting to corrosion of the stainless-steel sections along with the elevated acid gas content in the amine solvent. The most common pathway of chlorides ingression into amine units is dissolved in the produced water (brine) that enters with the inlet feed gas as water slugs, free water or aero- solized water. Ideally, liquid water should be removed prior to the amine unit using proper separation devices and gas-liquid coa- lescers. However, experience shows this is not the case in many facilities. Water slugs, pipeline foam, and vessel deficiencies can all cause produced water (brine) with high levels of salts and other dissolved contaminants to ingress the amine unit. In a future article, the possibility of using to an alternative amine solvent such as MDEA to mitigate cor - rosion in the process to acceptable levels will be explored. David B Engel is Managing Director at Nexo Solutions. He has been awarded 21 US Invention Patents and authored more than 100 papers and conferences. He holds a PhD in organic chemistry from Indiana University Bloomington. Email: david.engel@nexosolutions.com Scott Williams is a Process Engineer, responsible for engineer - ing, development, and onsite testing at Nexo Solutions based in The Woodlands, Texas. He holds a BS in chemical and biological engineering from University of Colorado at Boulder. Cody Ridge is a Chemical Engineer from Texas Tech and a lead process engineer at Nexo Solutions, responsible for engineering, development and sales. He has more than 10 published papers and has worked with more than 50 gas plants and refineries.

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