Fracture-driven interactions (FDIs) in unconventional reservoirs significantly affect well production and have thus garnered extensive attention from the scientific community. Furthermore, since the industry transitioned to using large completion designs with closer well spacing and infill drilling, FDIs have occurred more frequently and featured more prominently, which has primarily led to destructive interference. When infill wells (i.e., “child” wells) are fractured, older, adjacent producing wells (i.e., “parent” wells) are put directly at risk of premature changes in production behavior. Some wells may never fully recover following exposure to severe FDIs and, in the worst case scenario, will permanently stop producing. To date, previous investigations into FDIs have focused mainly on diagnosis and detection. As such, their formation mechanism is not well understood. To address this deficiency, a three-dimensional, multi-fracture propagation simulator was constructed based on the unconventional fracture model (UFM) and applied to a system that included both an older, adjacent passive well (“parent” well) and an active well (“child” well). Herein, the theoretical framework for overall complex fracture modeling is described. Furthermore, numerical simulation results are presented, demonstrating the critical roles of in-situ stress distribution and pre-existing natural fractures and aiding in the development of appropriate strategies for managing FDIs.

The fault-karst reservoir takes the fault-controlled fracture-cavity system as storage space, which is surrounded by a large number of high permeability zones. The distribution of reservoir seepage field has an important influence on fracture propagation behavior during the hydraulic fracturing process. Based on statistical damage mechanics theory and finite element method, this paper established a seepage-stress coupling numerical model of fracture propagation under the complex medium condition of matrix-cave-natural fracture in fault-karst carbonate reservoir. This new model innovatively considers the effects of matrix seepage, which is generally ignored by the traditional numerical models, for simulating the fluid–solid coupled fracture propagation behavior. The communication mechanism between fracture and cave is first revealed. The influence of geologic and engineering factors, e.g., permeability in high permeability zone around cave and injection rate etc., on hydraulic fracture propagation in fault-karst reservoir is studied. The results show that the high permeability zone around cave can provide sufficient infiltration capacity to communicate fracture with cave in the form of fluid pressure through fluid flow and fluid pressure conduction, even if hydraulic fracture does not directly communicate the cave. Hydraulic fracture is deflected to the direction of cave under the influence of seepage field, but the deflection angle is mostly within 10°. The high permeability of high permeability zone around cave and the short cave offset distance are conducive to the virtual communication between fracture and cave. Communicating fracture with cave in the non-principal stress direction can be accomplished by fluid flow and fluid pressure conduction, optimizing hydraulic fracturing treatment parameters should be performed by choosing lower injection rates and lower fracturing fluid viscosities. This study can provide key technical support and theoretical guidance for oil and gas development in fault-karst reservoir.

This study systematically performs multi-scale numerical investigation of supercritical CO₂-energized fracturing, widely employed for enhanced oil recovery (EOR) in tight oil and gas reservoirs. Two distinct models, spanning from core scale to field scale, are designed to explore the diffusion patterns of CO₂ into the matrix and its impact on crude oil production at varying scales. The core-scale model employs discrete grid regions to simulate the interaction between fractures and the core, facilitating a comprehensive understanding of CO₂ diffusion and its interaction with crude oil. Based on the core-scale numerical model, the wellbore treatment process is simulated, investigating CO₂ distribution within the core and its influence on crude oil during the well treatment phase. The field-scale model employs a series of grids to simulate fractures, the matrix, and the treatment zone. Additionally, a dilation model is employed to simulate fracture initiation and closure during CO₂ fracturing and production processes. The model explores CO₂ diffusion and its interaction with crude oil at different shut-in times and various injection rates, analyzing their impact on cumulative oil production within a year. The study concludes that during shut-in, CO₂ continues to diffuse deeper into the matrix until CO₂ concentration reaches an equilibrium within a certain range. At the core scale, CO₂ penetrates approximately 4 cm into the core after a 15-day shut-in, effectively reducing the viscosity within a range of about 3.5 cm. At the field scale, CO₂ diffusion extends up to approximately 4 m, with an effective viscosity reduction zone of about 3 m. Results suggest that, theoretically, higher injection rates and longer shut-in times yield better EOR results. However, considering economic factors, a 20-day shut-in period is preferred. Different injection rates indicate varying fracture conduction capabilities upon gas injection completion.