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Among waterless fracturing fluids, supercritical carbon dioxide (Sc-CO 2 ) has been increasingly emphasized in recent years for hydrocarbon recovery from shale. Sc-CO 2 is the most feasible choice to be an alternative to conventional hydraulic fracturing with the ability to alleviate global warming. However, Sc-CO 2 fracturing is encumbered with problems such as poor proppant-carrying capacity, easy sand plugging, large displacement, and high frictional resistance. The main aim of this study is to investigate the thickening of Sc-CO 2 by adding viscoelastic surfactants (VESs) for increasing the proppant-carrying capacity and to understand the preferential adsorption of this thickened Sc-CO 2 over methane on a heterogeneous molecular shale model. From the literature, it was found that a fluorinated polymer provides good CO 2 solubility and also thickens CO 2 . As a result, fluorinated VES, N-ethyl perfluorooctyl sulfonamide (N-ETFOSA), and nonfluorinated VES, N,N,N′-trimethyl-1,3-propanediamine (N,N,N′-TM-1,3-PDA), were used in this study for comparison. The molecular simulation of thickening Sc-CO 2 employing N-ETFOSA and N,N,N′-TM-1,3-PDA was carried out at a temperature and pressure ranging from 298 to 305 K and 100 to 7400 kPa, respectively. Although N,N,N′-TM-1,3-PDA shows better solubility in Sc-CO 2 than N-ETFOSA, both of them cause an increase in the viscosity of Sc-CO 2 by 36 and 156 times, respectively, than its actual viscosity. Adsorption simulations of CO 2 -thickened Sc-CO 2 and methane (CH 4 ) were performed on a heterogeneous molecular shale model. With increasing pressure at a constant temperature, N-ETFOSA-thickened Sc-CO 2 showed better adsorption capacity on the molecular shale model than others. Accordingly, at higher pressure, N-ETFOSA-thickened Sc-CO 2 shows better selectivity over methane. The results of viscosity and adsorption simulations have been validated by literature experiments. Nonetheless, these outstanding simulation findings need more experimental backup to pave their implementation on real field scenarios. Thus, this study helps establish a theoretical ground for the optimization of shale gas extraction from shale plays and makes it viable storage for CO 2 sequestration.

Usage of supercritical CO2 (Sc-CO2) as fracturing and displacing fluid is given much attention in recent years. It enables the prevention of issues related to hydraulic fracturing such as formation damage, clay swelling, capillary trapping, and consumption of a high volume of water. However, the low proppant carrying capacity, high frictional resistance, and fast filtration of Sc-CO2 are the challenges that require further research. Characterization of shale samples for implementation of Sc-CO2 as a fracturing fluid consists of imaging and qualitative analysis, identification of crystalline phases presents in material and determination of pore size distribution, surface area, micropore volume, porosity, and matrix density. Shale samples from Eagle Ford (EF-1. EF-2), Mancos (MC), and Wolfcamp (WF) shale formations have been characterized using field-emission scanning electron microscope (FESEM), X-Ray diffraction (XRD), surface area analyzer and porosimetry system (SAP) and Helium Porosimeter. From FESEM and EDX experiment, among all the samples, EF-1 has the highest carbon content (25.97%), EF-2 is mostly calcium dominant (33.17%) and WF has quartz having the presence of 3.37% of silicon. The existence of these elements and compounds are also validated by the qualitative and quantitative analysis of the XRD patterns. FESEM estimates that all these shale samples have the presence of mostly mesopores. Results from SAP experiment show that BJH adsorption average pore diameter of EF-1, MC and WF 30.8490, 8.5128, and 26.4318 nm respectively and it validates FESEM result. In terms of porosity, MC has the highest (7.4%), while EF-1 has the lowest (2.01%). For eradicating the problem of low proppant carrying capacity of Sc-CO2, thickening agents such as N-ethyl perfluorooctyl sulfonamide, a viscoelastic surfactant (VES) is used in this study. The molecular simulation study of N-ethyl perfluorooctyl sulfonamide to Sc-CO2 increases the viscosity of Sc-CO2.170 times than the actual viscosity of Sc-CO2. Although this an excellent result to derive yet the experimental validation of this result is needed to pave its implementation on real field scenarios.

This study has been undertaken with a view to interpreting and analyzing different types of logs, detecting hydrocarbon-bearing sand zone, identifying the lithology, estimating shale volume, and determining water saturation of the formation of the Fenchuganj gas field. Fenchuganj gas field is in the southern part of Bangladesh in the Sylhet division. It lies in the Surma basin and characterized as a water drive gas field. Gamma Ray (GR) log and Spontaneous Potential (SP) log analysis help to interpret the formation lithology. After interpreting lithology, the gamma-ray log and SP log were analyzed further, and the hydrocarbon-bearing zone was detected. From the analysis of different logs, for well 4, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (1585-1595) m, (1600-1610) m, (2409-2420) m, (2265-2270) m, (2295-2303) m, (2435-2450) m, (2465-2480) m, (3150-3155) m, (2955- 2960) m. These are the gas-bearing zones of fenchugonj well-4 determined from the composite log of this field. Water-bearing sand zones are between (1708-1714) m and the fully compacted shale zone is between (1920-1930) m. From the analysis of different logs, for well 5, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (2365-2385.5) m, (1820-1830) m, (1782-1803) m, (305-308) m, (336.5-338.5) m, (607.5-609.5) m. These are the gas-bearing zone of fenchugonj well-5 determined from the composite log of the field. Shale volume has been estimated from the gamma-ray log and from resistivity logs by the true resistivity method. In well 4, the calculated value of shale volume by Gamma Ray method and true Resistivity methods were respectively 15% and 6%, in well 5 these values were 7.25% and 7.64%. Formation water resistivity was determined from the formula and taken as 0. 1ohm-m and mud filtrate resistivity 0.76 ohm-m. for well-4 and for well-5 it was taken as 0.7 ohm-m (from the provided composite log of well 4 and 5). Formation true resistivity Rt was estimated directly from the ILD log and true resistivity log. The average value of Rt for well-5 was 33.75 ohm-m and for well-4 the value is 34.09 ohm-m. From the RFOC log, flushed zone resistivity Rxo was calculated directly. Water saturation has been determined by three different techniques named Archie, Indonesia, and Simandoux method. For well 5, the value of average water saturation found from Archie, Indonesia, and Simandoux model was 8.5%,22%, and 24.84%, and for well-4. The value of average water saturation was found as 7.3%,18%, 20.51%respectively.