Prediction of phase equilibrium of clathrate hydrates of multicomponent natural gases containing CO₂ and H₂S

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• 作者：Prathyusha Mekala ; Jitendra S. Sangwai ; ^{jitendrasangwai@iitm.ac.in" class="auth_mail}
• 关键词：carbon dioxide ; hydrogen sulfide ; natural gas hydrate ; phase equilibria ; sour gas
• 刊名：Journal of Petroleum Science and Engineering
• 出版年：April, 2014
• 年：2014
• 卷：116
• 期：Complete
• 页码：81-89
• 全文大小：767 K

文摘

The sour natural gas readily forms hydrates and stays stable at higher temperatures and lower pressures and hence is responsible for plugging, corroding the pipelines and causing other flow assurance-related issues. Predictions of formation and dissociation conditions of these hydrates are necessary in applications for preventing such hazards primarily due to the blockages of pipelines. However, natural gases from the gas reservoirs can have combinations of different concentrations of each of the following constituents, CH₄, C₂H₆, C₃H₈, C₄H₁₀, N₂, CO₂ and H₂S. Presence of high concentrations of CO₂ and/or H₂S along with other components is often found in natural gas, thereby limiting the accurate functioning of several of the available phase behavior models. The major limitation for their inaccuracy can be attributed to the complexity involving CO₂ and H₂S in hydrate systems. In this work, a new thermodynamic computing approach is developed for predicting the phase equilibria for hydrates of multicomponent sour natural gases (with CO₂ and H₂S) from different natural gas systems. The model of (Chem. Eng. J., 71, 145, 1998) is extended for the multicomponent sour natural gas hydrate system using the Kihara potential functions to model the guest-host interaction energies. In addition, a semi-empirical form is proposed to calculate the equilibrium hydrate temperature for hydrates of natural gas with and without CO₂ and H₂S. The developed model is fitted with 12 sets of experimental data on the phase equilibria of sour natural gas hydrate system and found to be satisfactory. The average absolute deviation pressure percentage (AADP%) for most of the cases studied is observed to be well within 10%, thus proving its efficacy. The present model can, therefore, find potential applications for developing mitigation techniques for flow assurance issues and for robust natural gas and hydrate reservoir models containing sour gases.