In the development process of fractured-vuggy carbonate reservoir with large-scale caves, the location and size of cave affect the development program. This paper takes the large-scale cave as equipotential body, treats matrix and fracture as double porous media, and establishes the flow model. Laplace transform is used to simplify the model, and then the model is solved using boundary element method. Considering the wellbore storage effect and skin effect, the bottomhole pressure-transient curve is obtained using Stefest numerical inversion method. Comparing the results of analytical solution and boundary element method in the dual porosity medium illustrate the accuracy of this model. The sensitivity of cave parameters is analyzed. It shows that the larger the cave radius is, the stronger the convex and concave of curve is. The convex is earlier and concave is sooner when cave is closer to the well. The segment of convex keeps longer and the concave margin is greater with the larger compressibility ratio. Finally, as an application example, actual test data from a large-scale cave reservoir is analyzed using this model, and the location and size of cave are obtained. It has a certain significance for the reserve evaluation and well test in this reservoir.

Accurate prediction of the temperature and pressure fields in carbon dioxide (CO₂) injection wells is critical for enhancing oil recovery efficiency and ensuring safe carbon sequestration. At present, the prediction model generally assumes that CO₂ is pure and does not consider the influence of impurities in CO₂ components. This study takes into account the common impurities, such as air and various alkanes in CO₂, and uses Refprop 9.0 software to calculate the physical parameters of the mixture. A comprehensive coupling model was developed to account for axial heat conduction, convective heat transfer, frictional heat generation, the soup coke effect, pressure work, and gas composition. The model was solved iteratively using numerical methods. We validated the accuracy of the calculated results by comparing our model with the Ramey model using measured injection well data. Compared with the measured bottom hole temperature and pressure data, the error percentage of our model to predict the bottom hole temperature and pressure is less than 1%, while the error percentage of Ramey model to predict the bottom hole temperature and pressure is 5.15% and 1.33%, respectively. Our model has higher bottom hole temperature and pressure prediction accuracy than the Ramey model. In addition, we use the model to simulate the influence of different injection parameters on wellbore temperature and pressure and consider the influence of different gas components. Each injection parameter uses three components. Based on the temperature and pressure data calculated by the model simulation, the phase state of CO₂ was analyzed. The results show that the impurities in CO₂ have a great influence on the predicted wellbore pressure, critical temperature, and critical pressure. In the process of CO₂ injection, increasing the injection pressure can significantly increase the bottom hole pressure, and changing the injection rate can adjust the bottom hole temperature. The research provides valuable insights for CO₂ sequestration and enhanced oil recovery (EOR).

There are various types of pores in shale, mainly consisting of nanopores and micropores, causing flow regime variations and apparent permeability cha

During the development of tight gas reservoir, the irreducible water saturation, rock permeability, and relative permeability change with formation pressure, which has a significant impact on well production. Based on capillary bundle model and fractal theory, the irreducible water saturation model, permeability model, and relative permeability model are constructed considering the influence of water film and stress sensitivity at the same time. The accuracy of this model is verified by results of nuclear magnetic experiment and comparison with previous models. The effects of some factors on irreducible water saturation, permeability, and relative permeability curves are discussed. The results show that the stress sensitivity will obviously reduce the formation permeability and increase the irreducible water saturation, and the existence of water film will reduce the permeability of gas phase. The increase of elastic modulus weakens the stress sensitivity of reservoir. The irreducible water saturation increases, and the relative permeability curve changes little with the increase of effective stress. When the minimum pore radius is constant, the ratio of maximum pore radius to minimum pore radius increases, the permeability increases, the irreducible water saturation decreases obviously, and the two-phase flow interval of relative permeability curve increases. When the displacement pressure increases, the irreducible water saturation decreases, and the interval of two-phase flow increases. These models can calculate the irreducible water saturation, permeability and relative permeability curves under any pressure in the development of tight gas reservoir. The findings of this study can help for better understanding of the productivity evaluation and performance prediction of tight sandstone gas reservoirs.

Stimulated reservoir volume is an effective stimulation measure and creates a complex fracture network, but the description and characterization of fracture network are very difficult. Well test analysis is a common method to describe the fracture network, and it is the key to build a proper interpretation model. However, most published works only consider the shape of the fractured area or the stress sensitivity effect, and few works take both factors into account. In this paper, based on reservoir properties and flow law after a stimulated reservoir volume, an interpretation model is established with an arbitrary shape of the fractured area and stress sensitivity effect of different flow areas. The model is solved to conduct the pressure response using Laplace transform, point source function, and boundary element theory. The influence of fractures’ parameters and stress sensitivity effect is analyzed on the pressure behavior. Results from this study show that the special flow regimes for a horizontal well with a stimulated reservoir volume are (1) bilinear flow dominated by hydraulic fractures, (2) linear flow dominated by formation around the hydraulic fractures, (3) crossflow from a matrix system to the fractured area, and (4) radial flow control by properties of the fractured area. Parameters of hydraulic fractures mainly affect the early stage of pressure behavior. On the contrary, the stress-sensitive effect mainly affects the middle and late stages; the stronger the stress sensitivity effect is, the more obvious the effect is. The findings of this study can help for better understanding of the fracture network in a tight oil reservoir with a stimulated reservoir volume.