No abstract

No abstract

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.

Shale rocks are one of the world's most important unconventional gas resources today, thanks to technical advancements. Fluid adsorption in tight rocks like shale is critical for designing fracturing and treatment fluids. However, adsorption of fluids in shale is not fully understood, and quantifying it remains difficult. In addition, the complicated pore structure of shale rocks makes characterisation challenging. Wettability can be used to understand the affinity of a solid surface to adhere certain fluid. Shales present several basic problems when employing standard techniques because of their small grain size, low permeability, and reactive components. We assessed and compare the wettability of shale using contact angle and spontaneous imbibition methods in two shale samples. The findings showed no correlation between contact angle and imbibition curves. Such behaviour is due heterogeneity of shale surface. Contact angle produces local wetting characteristics, but shale sample is rather complex and contact angle is therefore not representative. Imbibition results might be more reliable since fluids contacts with the whole sample.

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.