Summary As a mature technology to enhance the permeability of geological formations, hydraulic fracturing has widely been used in geothermal energy development and in the petroleum industry. Due to its effectiveness in practical applications, it attracts many research efforts. Because of the complexity of hydraulic fracturing itself and the complex distribution of stresses around wellbores, accurately describing the behaviors of hydraulic fractures is still a challenging task. In this study, a numerical model is developed to simulate curved propagation of hydraulic fractures from a wellbore, and emphases are placed on influence of in-situ stress and near wellbore stress redistribution. In the developed hydromechanical model, special considerations are given to its ability to simulate curved propagation of hydraulic fractures. The propagation of fractures is modeled through the phase-field method. Several cases on hydraulic fracture initiation and propagation from horizontal wellbores are studied through the proposed model. The model has been successfully verified through analytical solutions. The influence of stress redistribution caused by wellbore pressurization on hydraulic fracture initiation from wellbores is analyzed. Under different in-situ stress configurations and initial fracture orientations (perforation or flaws around wellbores are represented by the initial fractures), several patterns of hydraulic fracture propagation around the wellbores are recognized. It is found that the stress redistribution in the close vicinity of wellbores has great influences on the fracture initiation and propagation, and it makes hydraulic fractures propagate in nonplanar, complex manners. As hydraulic fractures propagate away from the stress redistribution regions around the wellbores, in-situ stress then determines the directions of fracture propagation; the curvature of fracture growth paths is mainly determined by the difference in in-situ stress, for example, σv − σhmin in this study. It has also been demonstrated that, when analyzing fracture propagation from wellbores, the wellbore stability or nonlinear deformation of a wellbore should be considered together with the fracture propagation conditions.

In the process of continuous production of natural gas wells, formation pressure and gas flow rate decrease continuously. The ability to carry liquid decreases continuously, thus gradually forming bottom hole liquid. Bottom hole liquid accumulation is an important reason for the decrease of production or shutdown of natural gas wells. How to diagnose whether there is liquid accumulation in natural gas wells and identify the degree of liquid accumulation, to adopt drainage gas recovery operation in time, is the research focus of efficient development of natural gas reservoirs. In this paper, a method for diagnosing bottom hole liquid accumulation combining production performance curve and modified Fernando inclined well critical liquid-carrying model is designed for a large scale double-branch horizontal well used in unconventional reservoirs. The method is applied to the Well X2 of He 8 Member in PCOC. The application results showed that there was no liquid accumulation in the horizontal and vertical sections of the Well X2. The liquid in the wellbore was generated at the bottom of the inclined section and the liquid accumulation is upward along the wellbore from the bottom of the inclined section, with the height of 3 m.

The problem of bottom hole effusion is an important reason for the reduction and even shutdown of natural gas wells. Downward velocity string is an important drainage gas recovery process, which can improve the flow rate of gas and discharge more liquid from the wellhead. However, the depth and timing of the velocity string is a technical problem that has been difficult to solve by field engineers. To solve this problem, this paper designs a method to select the depth and timing of the velocity string in the case of highly deviated wells and applies this method to Well X6–2 and Well X2–1 of PCOC in Ordos Basin, China. The optimization results show that when the wellhead pressure is 6.26 MPa, Well X6–2 should lower the 2–1.71 in. or 2.375–1.995 in. velocity string to 3337.9 m before the formation pressure decays to 8.800 MPa, which is most conducive to improve the liquid carrying capacity of gas wells. When the wellhead pressure is 4 MPa, Well X2–1 should lower 2–1.71in. velocity string to 3401.3 m before the formation pressure decays to 5.800 MPa, or lower 2.375–1.995 in. velocity string to 3401.3 m before the formation pressure decays to 5.900 MPa.