The Dabei deep high-pressure condensate gas field occupies the paramount position in the Tarim Oilfield in China, the exploration and developments of which have been progressing. Since the initial development, the wax deposition and plugging in the wellbore and gathering pipeline have been the most bothering issues, resulting in the reduction or even shutdown of condensate gas well production. Therefore, the wax appearance temperature of Dabei condensate oil was studied using the capillary viscometer, differential scanning calorimetry (DSC), and polarizing microscope observation. The wax content was tested by using the DSC and crystallization separation test method. Finally, the wax appearance temperatures of degassed condensate oil and equilibrium condensate oil under different pressures were tested. Experimental results show that the wax appearance temperature measured by polarizing microscope observation was higher than that measured by the DSC and capillary viscometer, the lag of which can be recorded as the cloud point. The wax appearance temperature measured by polarizing microscope observation is of high accuracy. Secondly, the DSC method is not sufficient for measuring wax precipitation at low temperatures, showing a lower wax content than the crystallization separation test method. Thus, the wax content of Dabei condensate oil can be better measured by using the crystallization separation test method. Additionally, the wax precipitation law of equilibrium condensate oil is opposite to that of degassed condensate oil. The wax appearance temperature of equilibrium condensate oil increases as the pressure decreases. The results of wax appearance temperature of equilibrium condensate oil provide a useful and quick index to judge the potential risk of wax precipitation in the Tarim Oilfield, which can provide an efficient strategy for the development of waxy condensate gas reservoirs and the optimization of wax prevention and treatment technology.

To enhance the wettability between Ag atoms and graphene of graphene-reinforced silver-based composite filler, the adsorption behavior of Ag atoms on graphene was studied by first-principles calculation. This was based on band structure analysis, both p-type doping and n-type doping form, of the vacancy-defected and Ce-doped graphene. It was verified by the subsequent investigation on the density of states. According to the charge transfer calculation, p-type doping can promote the electron transport ability between Ag atoms and graphene. The adsorption energy and population analysis show that both defect and Ce doping can improve the wettability and stability of the Ag-graphene system. Seen from these theoretical calculations, this study provides useful guidance for the preparation of Ag-graphene composite fillers.

Accurately describing the behavior of a gas-water two-phase flow in shale gas reservoirs is crucial for analyzing production dynamics in the field. Current research generally lacks consideration of the differences in physical properties and adsorption characteristics between the oleophilic organic matrix and the hydrophilic inorganic matrix. This study considers the organic matrix system as a single-phase gas flow, while the inorganic matrix and fracture systems involve a gas-water two-phase flow. Taking into account the impact of the adsorbed water layer on permeability at the surface of nanoscale pores in an inorganic matrix, the model comprehensively incorporates multiple mechanisms such as adsorption-desorption, the slippage effect, and Knudsen diffusion in the organic matrix and clay minerals. A multiscale gas-water two-phase comprehensive flow model for shale gas reservoirs has been established, and the results of the numerical model were validated against commercial software and actual field data. Simulation results over 1000 days indicate that early production from gas wells is primarily supplied by fractures, whereas free gas or desorbed gas from inorganic and organic matrices gradually contributes to the flow during the middle and later stages of production. As the Langmuir pressure and volume in the organic matrix and clay minerals increase, so does the corresponding gas production. The adsorbed water layer on the surface of inorganic nanopores reduces permeability, leading to a decrease in single-well cumulative gas production by 8.41%. The impact of the adsorbed water layer on gas production cannot be overlooked. The simulation method proposed in this study provides theoretical support for analyzing the gas-water two-phase flow behavior in shale gas reservoirs.

In this study, we propose a dynamic fractal dimension modeling (DFDM) framework that integrates image analysis, wavelet-based fractal methods, and structural fractal geometry to quantify the evolution of pore complexity. Unlike conventional static fractal approaches, our method captures time-dependent scaling laws and captures the spatiotemporal evolution of pore networks. The results demonstrate that dynamic fractal dimensions provide a robust descriptor of multi-scale heterogeneity, effectively bridging pore-scale processes with reservoir-scale behavior. This framework not only advances the theoretical understanding of fractal pore dynamics but also establishes a predictive tool with potential applications in unconventional hydrocarbon recovery, geological CO₂ sequestration, and multi-phase flow in porous media.

During gas production, the wellbore operates under high temperature and high pressure conditions, where gas–liquid two-phase flow is commonly present. Thus, it is important to understand the holdup of different flow patterns of gas–liquid two-phase flow in the wellbore. Currently, prediction models for flow patterns and holdup are mainly based on experimental data obtained under normal temperature and pressure, judged by researchers’ subjective observations, resulting in the lack of a unified flow pattern boundary so far. This article uses CFD simulation to study the characteristics of high temperature and high pressure gas–liquid two-phase flow in wellbores and obtains data such as flow pattern, probability density distribution of gas content, and liquid holdup. The results indicate that pressure is the dominant factor affecting the transition of gas–liquid two-phase flow patterns in wellbores. Under high temperature and pressure, each flow pattern has unique probability density distribution characteristics of gas content, which can be used as a basis for flow pattern identification. Flow pattern diagrams of gas–liquid two-phase flow at room temperature and pressure as well as high temperature and high pressure were drawn, and a boundary model for the transition of gas–liquid two-phase flow patterns in wellbores under the influence of variable pressure was established, verifying the rationality of the flow patterns’ transition boundaries. Based on the simulation of high temperature and high pressure gas–liquid two-phase flow in the wellbore, a calculation model for gas–liquid two-phase flow in the wellbore was established. The absolute percentage error between this model and the Fluent simulation results is within 10%, which can achieve the calculation of gas–liquid two-phase flow in the wellbore under different temperature and pressure conditions.