Research on Fluid–Solid Coupling Mechanism around Openhole Wellbore under Transient Seepage Conditions

• Published in: Processes 2024-02, Vol.12 (2), p.412
• Main Authors: Liu, Erhu, Zhou, Desheng, Su, Xu, Wang, Haiyang, Liu, Xiong, Xu, Jinze
• Format: Article
• Language: English
• Subjects: Boundary conditions; Carbon dioxide; Coupling; Crack initiation; Decomposition; Deformation; Enhanced oil recovery; Exact solutions; Finite difference method; Fluid injection; Fracture mechanics; Hydraulic fracturing; Mathematical models; Mechanical properties; Modulus of elasticity; Oil wells; Permeability; Pressurization; Propagation; Reservoirs; Rocks; Seepage; Stability analysis; Stress distribution; Viscosity
• ISSN: 2227-9717; 2227-9717
• DOI: 10.3390/pr12020412

Hydraulic fracturing is one of the most important enhanced oil recovery technologies currently used to develop unconventional oil and gas reservoirs. During hydraulic fracture initiation, fluid seeps into the reservoir rocks surrounding the wellbore, inducing rock deformation and changes in the stress field. Analyzing the fluid–solid coupling mechanism around the wellbore is crucial to the construction design of fracturing technologies such as pulse fracturing and supercritical carbon dioxide fracturing. In this study, a new transient fluid–solid coupling model, capable of simulating the pore pressure field and effective stress field around the wellbore, was established based on the Biot consolidation theory combined with the finite difference method. The numerical results are in excellent agreement with the analytical solutions, indicating the reliability of the model and the stability of the computational approach. Using this model, the influence of seepage parameters and reservoir properties on the fluid–solid coupling around the open-hole wellbore was investigated. The simulation results demonstrate that, during wellbore pressurization, significant changes occur in the pore pressure field and effective stress field near the wellbore. The fluid–solid coupling effect around the wellbore returns to its initial state when the distance exceeds four times the radius away from the wellbore. As the fluid viscosity and wellbore pressurization rate decrease, the pore pressure field and effective circumferential stress (ECS) field around the wellbore become stronger. Adjusting the fluid viscosity and wellbore pressurization rate can control the effect of seepage forces on the rock skeleton during wellbore fluid injection. For the same injection conditions, rocks with q higher Young’s modulus and Poisson’s ratio exhibit stronger pore pressure fields and ECS fields near the wellbore. This model furnishes a dependable numerical framework for examining the fluid–solid coupling mechanism surrounding the open-hole wellbore in the initiation phase of hydraulic fractures.