Large-scale karst caves are the principal storage spaces for hydrocarbon resources in fracture–cavity carbonate reservoirs. Drilling directly into these caves is considered the ideal mode of development, but many wells do not effectively penetrate karst caves. Therefore, acid fracturing is employed to generate artificial fractures that can connect with these caves. However, there are no appropriate well test methods for fracturing wells in fracture–cavity reservoirs. This study establishes a novel pressure transient analysis model for such wells. A new mathematical model is proposed that couples linear flow in acid fracturing cracks with radial flow in the oil drainage area. The Laplace transform and Stehfest numerical inversion provided analytical solutions for the bottomhole pressure. Typical log–log well testing curves were plotted to analyze oil flow, which occurs in ten stages. During the flow stage in fracturing cracks, the pressure and pressure derivative curves are parallel lines with a slope of 0.5. In the stage of karst cave storage, the pressure derivative curve is a straight line with a slope of 1. A comparison with previous models confirmed the validity of the proposed model. The influence of key parameters on the behavior of typical curves is analyzed. A field case study of the proposed model was carried out. Parameters related to fracturing cracks and karst caves, such as the crack length and cave radius, were successfully estimated. The proposed model has great potential for determining formation parameters of fracture–cavity reservoirs.

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.

As gas wells enter later production stages, the formation pressure decreases and liquid accumulates at the bottom of the gas well. The formation pressure is insufficient to lift the accumulated liquid from the bottom of the well to the surface. At this time, a large number of gas wells need to undergo intermittent production to maintain their production capacity. This article focuses on the four stages of intermittent production in gas wells, considering the changes in slip gas holdup, pressure, and gas–liquid flow in and out of tubing and casing, and establishes a transient mathematical model for intermittent production in gas wells in stages. By using the dynamic tracking technology of moving liquid slugs to divide the wellbore grid and solve it in stages, the optimal shut-in time for intermittent production of gas wells was obtained. The transient mathematical model developed for intermittent gas well production achieved a high historical fit accuracy of over 90%. This indicates that the simulation results are in line with the actual situation of gas well intermittent production and can effectively guide intermittent production. The optimized intermittent production system of gas wells has a higher cumulative gas production compared to the original system, achieving the optimization of intermittent production system. This method is beneficial for guiding efficient production of gas wells in low-pressure formations.