Simulation of Combined Hydrate Control and H2S Removal Using Aspen Plus
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Removal of water (H2O) and acid gas contaminants, like hydrogen sulfide (H2S) and carbon dioxide (CO2), are essential in natural gas purification. Due to gas quality specifications and protection of installed equipment including subsea pipelines, impurities need to be removed efficiently. Well designed gas treatment processes have been developed, where fine removal of water and acid gas typically are performed by absorption utilizing glycols and alkanolamines. Inhibition of gas hydrates in pipelines is crucial upstream a processing facility, because pipeline blockages have the possibility of causing complete process shutdown. Research towards complete subsea processing is now conducted, where the aim is to develop new process technology that can enhance and increase the production efficiency of reservoirs already in operation. Hydrate inhibition, acid gas removal and fine removal of water are traditionally performed in three different processing units. Designing a process where these systems can be combined, may give more efficient and compact processing equipment. In this thesis, the main goal was to conduct a simulation of combined H2S and water removal from natural gas by absorption in methyldiethanolamine (MDEA) and monoethylene glycol (MEG). Simulations were performed in Aspen plus version 8.6 and the template ElecNRTL_Rate_Based_MDEA_model was used. The aim was to examine the absorption performance predicted by Aspen Plus of the combined process. A vapor liquid validation (VLE) was performed where H2S, CO2, methane (CH4) and H2O solubility in aqueous MDEA and pure MEG were compared to literature data. In total, 500 experimental data points were compared to the solubility curves predicted by Aspen Plus, which gave average absolute deviations ranging from 3.5% to 218.6% for temperatures from 25 oC to 130 oC. Validation of H2S and CO2 mixtures in a MDEA-MEG-H2O solvent with low water content, revealed high partial pressures of the acid gas components compared to literature data. It was found that absorption of H2S and CO2 required use of aqueous MDEA, because of how the chemical reactions were defined in the template. The absorption simulations were performed for three different natural gas compositions, which were defined to be CH4 saturated with water, having H2S and CO2 contents ranging from 49.8 ppm and 5.6% to 4.5% and 8%, respectively. The absorption performance using a mixed MDEA-MEG solvent in one contactor, where various solvent concentrations were examined, was found to be insufficient with respect to water removal. Absorption of H2S and CO2 in MDEA, and H2O in MEG, including regeneration of the solvents were simulated separately. No recommendations for optimal operating conditions were made, due to lack of operational data that could be used for comparison. However, some operational areas which were considered as energy efficient for the different composition cases, where chosen for further analysis. Molar liquid-gas ratios, for obtaining 4 ppm H2S in the sweet gas utilizing a 45 wt% MDEA solvent at 100 bar, ranged from 0.75 to 1.7 at these operational areas. Specific reboiler duties ranged from 3.79 MJ/kg acid gas to 4.96 MJ/kg acid gas. H2S and CO2 recoveries were up to 99.3% and 99.5%. Because equilibrium based calculations were defined in the absorber, the amount of absorbed CO2 were high for all simulations and results revealed less than 1% CO2 in the sweet gas for the same cases. For water removal, it was found that MEG concentrations above 99% should be used depending on the water content and temperature of the wet gas. Conventional regeneration of MEG in a distillation column to this level of purity, resulted in reboiler temperatures above 190 oC, and were found to exceed the recommended limits with respect to thermal degradation, which are around 165 oC.