Controlling corrosion is the main reason for converting amine solutions in the C02 Removal Unit of the LNG Plant. In twenty years of its operating experience, we have used three kinds of amine solutions; MEA, formulated MDEA Type-A, and formulated MDEA Type-B.
Stress Corrosion Cracking (SCC) was the cause of vessel failure when operating with MEA solution in 1977-1989. SCC occurred in the Amine Regenerator and COz Absorber Columns. Prevention of further SCC and lost production due to unscheduled shutdowns for repairing corrosion damage were the main reasons for converting from MEA to an MDEA-based solution.
The replacement of MEA with formulated MDEA Type-A eliminated SCC. Steam consumption to regenerate the rich amine solution was also reduced due to weaker bonding between CO2 and MDEA solution. Unfortunately, COz easily releases in low pressure regions, causing corrosion from carbonic acid. The corrosion product, iron carbonate scale, was always observed in hot areas. Operating conditions and equipment were modified but improvement was minimal.
A one year test of an alternate solvent, formulated MDEA Type-B, in one train resulted in good CO/absorption, low corrosion rate measured by coupon, and very low iron content in solution. Visual inspection of main equipment after a one year test revealed negligible corrosion attack. After another half year operation, there was still very low, stable iron content in solution. Other benefits of converting to formulated MDEA Type-B are lower solvent makeup and lower steam consumption for regeneration compared to formulated MDEA Type-A for the same CO2 pick up.
The company is a natural gas liquefaction company, and currently operates seven LNG trains, named in alphabetical order A through G. One more train is under construction and scheduled to be on line in November 1999. The total capacity of the plant is 18.69 MM tons LNG/year and will be 21.64 MM tons LNG/year upon completion of Train H. Each train consists of five units: COg Removal (Amine Unit), Dehydration and Mercury Removal, Fractionation, Refrigeration, and Liquefaction.
The Amine Unit in the first two trains was originally designed to handle 305,900 Nm3/h of feed gas containing 5.88% vol. CO2 and trace H2S. The designed amine circulation rate was 740 m3/h at a monoethanolamine (MEA) solution concentration of 20% wt. The target of absorption was 50 ppmv maximum of CO2 in the treated gas outlet of the absorber. We debottle necked the amine unit in Trains A and B in 1982 to accommodate higher feed gas flow, in line with the construction of Trains C and D. Currently, the amine unit in all trains can handle feed gas flow rate of 495,000 Nm3/h containing 8% vol. CO2. Figure 1 shows the typical amine unit in Badak LNG Plant.
Removing CO2 from the feed gas is required by the process to avoid plugging of the cryogenic heat exchanger tubes with icing CO2 in the downstream process. The liquefaction of feed gas (methane) to LNG requires an extremely low gas condensation temperature, -156°C, at which CO2 would freeze.
STRESS CORROSION CRACKING WHEN USING MEA
Monoethanolamine (MEA) was used to absorb CO2 from the feed gas since the startup of Trains A and B in 1977 and Trains C and D in 1983. In January 1986, the first incident of amine stripper leak in Train B was detected. An internal crack of 10.7 cm long was found on a lace weld applied during the 1980 shutdown without stress relief after the repair. In the same year, other cracks were found on the amine stripper wall in Trains C and D. Ten unscheduled shutdowns were carried out because of SCC in the period of January 1986 to May 1989. ~
The crack on the vessel wal
