With the development of gas well exploitation, the calculation of wellbore with single-phase state affected by single factor cannot meet the actual needs of engineering. We need to consider the simulation calculation of complex wellbore environment under the coupling of multiphase and multiple factors, so as to better serve the petroleum industry. In view of the problem that the commonly used temperature and pressure model can only be used for single-phase state under complex well conditions, and the error is large. Combined with the wellbore heat transfer mechanism and the calculation method of pipe flow pressure drop gradient, this study analyzes the shortcomings of Ramey model and Hassan & Kabir model through transient analysis. Based on the equations of mass conservation, momentum conservation and energy conservation, and considering the interaction between fluid physical parameters and temperature and pressure, the wellbore pressure coupling model of water-bearing gas well is established, and the Newton Raphael iterative method is used for MATLAB programming. On this basis, the relationship between tubing diameter, gas production, gas–water ratio, and wellbore temperature field and pressure field in high water-bearing gas wells is discussed. The results show that the wellbore temperature pressure coupling model of high water-bearing gas well considering the coupling of gas–liquid two-phase flow wellbore temperature pressure field has higher accuracy than Ramey model and Hassan & Kabir model, and the minimum coefficients of variation of each model are 0.022, 0.037 and 0.042, respectively. Therefore, the model in this study is highly consistent with the field measured data. Therefore, the findings of this study are helpful to better calculate the wellbore temperature and pressure parameters under complex well conditions.

The accumulation of liquid in gas wells has become a prevalent problem in the middle and later stages of gas well development with different wellbore structures, which seriously affects the production efficiency of gas wells. To precisely forecast the generation time of liquid accumulation in gas wells and timely adopt drainage gas production technology, the literatures on gas critical liquid‐carrying flow calculation models for vertical wells, inclined wells and horizontal wells were analyzed and summarized. The results show that the research on the calculation models for gas critical liquid‐carrying flow rate in vertical and inclined wells is relatively mature. However, because of the unique wellbore structure of horizontal wells, the gas‐liquid two‐phase flow pattern and distribution of droplets and liquid‐film are complex, leading to a lack of understanding of gas liquid carrying mechanism throughout the whole wellbore of existing horizontal wells, and we established a calculation model of gas critical liquid‐carrying flow rate in horizontal wells considers single factors. Based on the above summary and analysis, the research direction of the calculation model for gas critical liquid‐carrying flow rate in the entire wellbore of horizontal wells is pointed out. Combining the gas liquid‐carrying test of entire wellbore of the horizontal well, considering the distribution form of droplets and liquid‐film, the aggregation and fission between droplets, and the energy exchange between gas and liquid, the gas liquid‐carrying mechanism of the entire wellbore of horizontal well is revealed, clarifying the most easy to liquid‐accumulating well sections in the whole horizontal well, and a calculation model of gas critical liquid‐carrying flow rate of horizontal well considering multiple factors is established, providing crucial theoretical foundation and technical support for the drainage and gas recovery of a horizontal well.

This article reviews recent research on wax deposition, with the aim of understanding the formation mechanisms and influencing factors of wax deposition during the pipeline transportation of wax-bearing crude oil. It provides a summary and analysis of the roles of molecular diffusion and aging mechanisms in wax deposition, offering deeper insights into the formation and development of wax. The article also explores in detail how factors such as oil flow temperature, pipeline pressure, flow velocity, and the chemical composition of crude oil affect the characteristics of wax deposition. These insights provide a scientific foundation for understanding deposition mechanisms, optimizing pipeline parameters, and developing effective prevention and control measures. Regarding wax deposition modeling, a model based on molecular diffusion theory, experimental data, and heat transfer mechanisms is presented. Finally, various techniques for inhibiting wax deposition are discussed, with an analysis of their advantages and disadvantages, as well as an identification of existing challenges and future research directions. Therefore, this study not only contributes significantly to the advancement of wax deposition theory but also plays a crucial role in enhancing pipeline operation safety and efficiency, as well as advancing flow safety technologies in the petroleum industry.

Summary: To solve problems such as additional tubing/casing load, casing deformation, and packer failure caused by changes in annular temperature during oil and gas reservoir fracturing and production, based on the well structure of oil and gas reservoirs and transition transient heat transfer mechanism, a four-field coupling simulation model of the temperature field in the main fluid domain of the tubing, the temperature field in the solid domain of the tubing, the temperature field in the annular fluid domain, and the temperature field in the solid domain of the casing is proposed. Considering the coupling of fluid temperature, pressure, and physical parameters, boundary conditions are established based on reservoir characteristics, wellbore heat transfer characteristics, and fracturing and production conditions, and are compiled into Fluent software for simulation through the user-defined function (UDF) method. The effects of the temperature and flow rate of injected fracturing fluid and produced oil and gas on the distribution of the wellbore temperature field and temperature gradient are studied. The research results show that by applying D14-1 and D5-5 gas wells to the model, the simulated temperature is in good agreement with the measured wellbore temperature, and the maximum errors of the simulated values of the two different wells are 6.4% and 4.3%, respectively. As the injection and production operation time increase, the heat transfer between the wellbore and the formation gradually stabilizes. At this time, the injection and production flow rate have little impact on the wellbore temperature field, while the injection and production temperature have a greater impact on the wellbore temperature field. The injection and production temperature will cause changes in annular temperature and temperature gradient, leading to an increase or decrease in pressure within a limited annular volume, resulting in local stress on the tubing and casing. The research results can provide a theoretical basis for the analysis of the temperature field and pressure field of the wellbore during fracturing and oil and gas production, ensuring the safety and stability of fracturing and production.