Persian Gulf UniversityJournal of Oil, Gas and Petrochemical Technology2383-27707Number 120201201A modifed UNIFAC model in predicting the solubility of CO2 and H 2S in imidazolium-based ionic liquids11311309110.22034/jogpt.2020.113091ENMohammad HashemSedghkerdarGas, Oil and Petrochemical Engineering Department, Persian Gulf University, Bushehr, IranVahidTaghikhaniDepartment of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, IranCyrusGhotbiDepartment of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, IranAlirezaShariatiSchool of Chemical and Petroleum Engineering, Shiraz University, Shiraz, IranJournal Article20200822< p>In this work, a modifed UNIFAC model was proposed to investigate the solubility of acid gases, i.e., CO2 and H2S in nine imidazolium-based ionic liquids (ILs). The influence of effective parameters including temperature, the nature of anions and cations of the ILs, and the length of alkyl chain<br />on the solubility of acid gases in the ILs were studied. The interaction parameters between the new functional subgroups of the fragmented ILs such as [IM], [BF4], [PF6], [Tf2N], CH3 and CH2 with CO2 and H2S molecules were reported using the original UNIFAC model. In the proposed model, the<br />segment fraction in the Flory-Huggins term of the UNIFAC combinatorial part was modifed considering the free-volume differences between the ionic liquid and the acid gas molecules. While the free-volume parameter represents the free-volume percent ratio of ionic liquid to that of the acid gas, it was regressed for each system using the extensive VLE experimental data from literature. It was verfed that the free-volume parameter can be a linear fuction of the molecular weight of the ionic liquids and, thus, only the values for the molecular weight of the ionic liquids are required to estimate the free-volume parameters. The modeling results were compared with those of the original UNIFAC model. The results showed that the proposed model accurately correlated the VLE experimental data for the systems containing ILs in the presence of CO2 and/or H2S at pressures up to 150 bar.https://jogpt.pgu.ac.ir/article_113091_a6e2a675cdac496d595c1ccd8f899fd2.pdfPersian Gulf UniversityJournal of Oil, Gas and Petrochemical Technology2383-27707Number 120201201Synthesis Well Logs Generation in a Naturally Fractured Reservoir Using Multi-Layer Perceptron Networks142911312810.22034/jogpt.2020.113128ENMojtabaGhaediDepartment of Petroleum Engineering, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, IranShahabAyatollahiSchool of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, IranJournal Article20200823Well logs which are considered as robust tools for the reservoir description cost a lot in the petroleum industry. The challenges in this process result in missing or incomplete data in some cases. Generating synthesis logs have already been proposed to fix this problem. This study presents a methodology to develop the synthesis logs for a naturally fractured reservoir. In this approach, multi-layer perceptron neural networks are used with available conventional wireline logs data from a naturally fractured oil reservoir to develop the missing or incomplete logs. In this study, three different approaches were used to utilize the available data including depth, Gamma Ray, Resistivity, Density and Sonic logs of five wells for training, testing and verification stages to predict the missed logs. The results showed that the generated synthesis Sonic and Density logs have very good accuracy with 0.93 and 0.92 average R2 values, respectively. The precision of the generated Gamma Ray is satisfactory with 0.82 average R2 value. Furthermore, the average R2 value for the prediction of the Resistivity log is 0.76 and the designed neural network failed to predict the Resistivity log in certain circumstances well. Therefore, care must be taken in this regard.https://jogpt.pgu.ac.ir/article_113128_d5bd558ee4bafb62e417ca3a05074417.pdfPersian Gulf UniversityJournal of Oil, Gas and Petrochemical Technology2383-27707Number 120201201Petrophysical Evaluation of Bangestan Group Formations in an Iranian Oil Field304211308910.22034/jogpt.2020.113089ENMehdiShabaniPhD in Petroleum Engineering, Assistant Professor at Amirkabir University of Technology (AUT), Tehran, IranZahraSadeghtabaghiPhD in Petroleum Engineering, Assistant Professor at Amirkabir University of Technology (AUT), Tehran, IranZeinabKhoshsiarPhD in Petroleum Engineering, Assistant Professor at Amirkabir University of Technology (AUT), Tehran, IranJournal Article20200822Ilam and Sarvak are two productive reservoirs in Iran. Despite wide petrophysical assessments, these two reservoirs have not been well investigated in Abadan plain located in the southwest of Iran. Reservoir investigation of Ilam and Sarvak formations as two important reserves is the main topic of this article. To that way, two wells of the studied field which are located in the Abadan plain were investigated. Well-logging data were used for the determination of petrophysical parameters of porosity, water saturation, and shale volume. Furthermore, core data were applied for the validation of final results. The best-fitted curve for the porosity and permeability of core data was selected for the permeability prediction throughout both reservoirs. Final consequences indicated that the lithology of Ilam and Sarvak formations are limestone and limestone-dolomite respectively. The two mentioned reservoirs have a shale volume of less than 10%, so they can be classified as clean formations. Average effective porosity ranges between 13.4 and 16% for Ilam Formation, while it varies from 10.6 to 11.4% for Sarvak Formation. Comparing porosities, Ilam Formation has a higher porosity than Sarvak Formation over depth in both studied wells. The results of water saturation show Sarvak Formation has relatively higher water than Ilam Formation. Moreover, the Net to Gross<br /> Ratio (NGR) index was calculated to 80 % in Ilam Formation. Although, Sarvak possessed proper reservoir properties in limited thicknesses, the overall value of NGR for this Formation was between 6-9%. Eventually, Ilam Formation had befitting reservoir quality whereas the quality of Sarvak Formation was low. The findings of this study can contribute to a better understanding of zonation and prospects of the penetration.https://jogpt.pgu.ac.ir/article_113089_252620ed21db1b30cde293ff67d624ec.pdfPersian Gulf UniversityJournal of Oil, Gas and Petrochemical Technology2383-27707Number 120201201Deviations due to Ignoring the Skin Layer in Modelling of CO2 Absorption in Asymmetric Hollow Fiber Membrane Contactors435811982910.22034/jogpt.2020.119829ENS. A.HashemifardSustainable Membrane Technology Research Group (SMTRG), Faculty of Petroleum, Gas and Petrochemical Engineering (FPGPE), Persian Gulf University (PGU), Bushehr 75169-13817, Iran.K.Nasim AfzaSustainable Membrane Technology Research Group (SMTRG), Faculty of Petroleum, Gas and Petrochemical Engineering (FPGPE), Persian Gulf University (PGU), Bushehr 75169-13817, Iran.M.AbbasiSustainable Membrane Technology Research Group (SMTRG), Faculty of Petroleum, Gas and Petrochemical Engineering (FPGPE), Persian Gulf University (PGU), Bushehr 75169-13817, Iran.Journal Article20201130The scope of this study is to model the absorption of CO2 in water via an asymmetric hollow fiber membrane contactor based on the resistance modelling approach. In the previous research, membrane structure was divided into only three regions of shell stream, bulk of membrane and lumen stream, i.e. a symmetric structure, whereas in the current study the role of another important resistance i.e. skin layer was deeply considered. In this way, without considering illegal values for the system tuning parameters the modelling results were enhanced e.g. 1.5 versus 4 for tortuosity. The predictions of the proposed model were confirmed by the experimental data i.e. a percentage of average absolute relative error of less than 6%. The results also showed that the increase in effective surface porosity leads to more descending trend of the mass transfer resistance relative to the bulk porosity that is due to the higher order of magnitude (2 order) of the skin layer resistance in comparison to that of the substrate. In addition, the findings demonstrated that, the model proposed in this work is prone to offer a useful tool to improve our knowledge about the asymmetric membrane contactors.<br /> <br /> https://jogpt.pgu.ac.ir/article_119829_ed145f39c5c7529179e018f16096a0cf.pdfPersian Gulf UniversityJournal of Oil, Gas and Petrochemical Technology2383-27707Number 120201201Evaluation of Analytical Methods for Measuring the Molecular Diffusion Coefficient in Gas-Oil Systems by the Pressure Decay Method597411983010.22034/jogpt.2020.119830ENFereshteZareieDepartment of Chemical Engineering, Faculty of Oil, Gas and Petrochemical Engineering, Persian Gulf University, Bushehr, IranRezaAzinDepartment of Petroleum Engineering, Faculty of Oil, Gas and Petrochemical Engineering, Persian Gulf University, Bushehr, IranShahryarOsfouriDepartment of Chemical Engineering, Faculty of Oil, Gas and Petrochemical Engineering, Persian Gulf University, Bushehr, IranHosseinRahideDepartment of Chemical Engineering, Faculty of Oil, Gas and Petrochemical Engineering, Persian Gulf University, Bushehr, IranJournal Article20201130Gas is injected into reservoirs for pressure maintenance, enhanced oil recovery and greenhouse gas storage. The molecular diffusion coefficient is one of the most important mechanisms in describing the mass transfer of gas during injection. The molecular diffusion coefficient is determined using indirect methods like pressure decay method associated with appropriate models and analyzing the experimental results. In this study, analytical methods for analyzing the experimental data from the pressure decay method were evaluated. For this purpose, three analytical solution methods of diffusivity equation were introduced using equilibrium, quasi-equilibrium and non-equilibrium boundary conditions at the interface of two phases in contact with the diffusion cell. Then, the models were applied for determining diffusivity in different fluid systems of heavy and light oil. The evaluation of the proposed models was based on the difference between the production pressure by these models and the experimental pressure. The results showed that for heavy oil systems, the boundary conditions on the surface is dependent on the type of the injection gas and the experimental conditions. Equilibrium boundary conditions are used for light oil systems because of their lower viscosity and continuity at the interface of two phases.https://jogpt.pgu.ac.ir/article_119830_14b91c73a3b67f741d93122aaf961eec.pdfPersian Gulf UniversityJournal of Oil, Gas and Petrochemical Technology2383-27707Number 120201201A Mechanistic Study on the Behavior of Injected Hydrogels in Porous Media for Enhanced Oil Recovery758711998010.22034/jogpt.2020.119980ENSeyed HosseinHayatolgheibiSchool of Chemical Engineering, Oil and Gas, Iran University of Science and Technology, Tehran 16846–13114, IranForoughAmeliSchool of Chemical Engineering, Oil and Gas, Iran University of Science and Technology, Tehran 16846–13114, IranJournal Article20201205In this communication, the process of hydrogel injection to micromodel was studied. This process consisted of water flooding in an oil saturated model until the breakthrough time and then the injection of hydrogels. Sensitivity analysis was performed on effective parameters of this process including wettability, injection rate, temperature and viscosity. Simultaneous effects of injection rate, viscosity and wettability were also studied on oil recovery factor in water flooding. Considering the simultaneous effects of injection rate and viscosity, the best recovery factor (50.87%) was obtained at flow rate of 2 10<sup>-4 </sup>cc/min and viscosity of 8.3 cp. During the hydrogel injection, they might deform, pass, or plug the throats depending on the throat diameter, or might break into smaller particles. These mechanisms including pressure variations were reviewed in this study. Finally, the performance of hydrogels was confirmed in a heterogeneous porous media. https://jogpt.pgu.ac.ir/article_119980_1d8cbd168b6fce11358dc085c6cfa94d.pdf