Ultra-deep sandstone gas reservoirs have great potential for exploration and development and have become a major focus worldwide. Under the influence of ultra-high temperature, pressure and strong in-situ stress, the mechanical properties of rocks change significantly, resulting in the coexistence of diverse pores and fractures. This rock deformation, coupled with severely non-uniform water invasion, fundamentally hinders efficient reservoir development by promoting preferential flow channeling and early water breakthrough, which reduce sweep efficiency and increase remaining gas retention. In this paper, a microfocus CT scanning experiment is conducted on ultra-deep rock under in-situ stress loading. Based on the acquired scans, three-dimensional digital cores representing the deformed multiscale fracture-pore media are reconstructed under various stress conditions. Dynamic pore network simulations are performed to systematically investigate gas-water migration and distribution characteristics under the effects of stress, displacement pressure difference and fracture conductivity. The research shows that stress is the most critical factor governing the water invasion process. In the absence of applied stress, water preferentially invades well-connected pores, exhibiting a regular front and fast migration rate, while gas remains in small, poorly connected blind pores. When the stress is loaded to the linear elastic deformation stage, the core exhibits increased radial deformation, and pronounced dynamic changes occur during the water invasion process. Remaining gas easily accumulates in isolated pores at corner or dead-end regions, and a large amount of remaining gas appears in regions with low driving force. Upon reaching the plastic deformation stage, localized fracturing occurs, which increases the number of throats and enhances connectivity. This leads to a transition of the water invasion mode from uniform to non-uniform. In the fracture stage, the water phase preferentially moves along the fracture surface rapidly, thereby accelerating the water invasion process. The local pressure distribution between the fracture and the matrix is uneven, inducing the wetting phase fluid to continuously seep from the fracture into the matrix, expanding the swept range. Fracture conductivity directly affects the migration speed and morphology of the water invasion front, but its impact on the final water invasion effect is weak.

Owing to intricate geological and engineering factors, the hydraulic fractures in shale oil reservoirs sometimes are in heterogeneous and random lengths, which brings a difficulty in fracture estimation. To improve this situation, a simple and quick well-testing method is presented for fracturing evaluation and parameter estimation of multiple fractured horizontal wells with non-uniform fractures. The semianalytical method and Laplace transformation are used for model solution. With the proposed model, we estimate the properties of non-uniform fractures in shale oil wells from the Ordos Basin based on the buildup testing data. Results from the case studies show that there is a good relationship between fracturing treatment parameters and generated fracture properties, including fracture length and storativity ratio (or fracture volume ratio). The fracture parameter values increase with the increase in fracturing liquid volume, especially the inner region permeability and storativity ratio. When the fracturing liquid volume per stage increases by 200-300 m³, the fracture impacts are weaker on generated parameters, which indicates that there would be an optimized fracturing liquid volume in the field case.