Combined subsea hydrate control and H2S removal
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In Norway natural gas production mostly comes from offshore facilities and contains impurities such as acid gases (hydrogen sulfide (H2S) & carbon dioxide (CO2)), water vapor, and mercury, etc. These impurities can cause corrosion and can form hydrates, while H2S can also cause instant death at concentrations over 500 parts per million (ppm). Traditionally, acid gases and water vapors are removed separately in two absorption processes, which increases the capital and operational costs. Therefore, developing a combined subsea selective acid gas removal along with dehydration can reduce the environmental footprint as well as operational costs. Amine loss due to high process temperatures and equipment corrosion are known problems in amine-based gas treatment processes. Amine loss also decreases the acid gas absorption capacity of the solution. Main focus of this work is to identify various potential solutions for H2S absorption with higher absorption capacity, thermal stability and lower corrosivity. Various investigations are done in this work to deal with aforementioned issues and for the development of combined desulfurization and dehydration process. H2S absorption was studied in both aqueous and non-aqueous solutions of one secondary hindered amine, one tertiary hindered amine, and ten tertiary alkanol amines. The amines in this study were chosen systematically to see the effect of amine alkanol groups, alkyl chain length, and hydroxyl group on H2S absorption capacity. Amine structure and solvent type affected the H2S absorption capacity. Higher temperature and lower inlet pH2S generally decreased the H2S absorption except in DEAE-EO solutions, while (DEAE-EO). MEG solution showed higher H2S loading than aqueous MDEA solution. A spectroscopic technique using Fourier-transform infrared spectroscopy (FTIR) along with PLS regression was developed to measure individual components in combined acid gas and water removalsystems. The model successfully predicted individual components in thermally degraded CO2 loaded solutions of MDEA-MEG/TEG and MDEA-H2O-MEG/TEG. Thermal stability and corrosivity of amine solutions was studied for both H2S and CO2 loaded amine solutions in 316 stainless steel cylinders at 135°C for five and seven weeks respectively. Linear regression was used to calculate first order rate constants. CO2 loaded solutions of nine tertiary amines and one primary amine in both aqueous and non-aqueous forms were studied. The effect of amine structure, solvent type, metal, initial acid gas loading, initial amine concentration, and pKa were investigated. It was observed that tertiary amines were more thermally stable and caused less corrosion than MEA. Amine structure and addition/replacement of MEG/TEG affected both thermal stability and corrosivity. Thermal stability appeared to be weakly dependent on pKa. Increase in both initial amine concentration and CO2 loading reduced the amine thermal stability and increased corrosivity. Four H2S loaded tertiary amine solutions in both aqueous and non-aqueous forms were also studied for thermal stability and corrosivity. Replacement of water with MEG decreased the thermal stability and increased the corrosivity. Higher amine loss triggered more corrosion in all solutions.