Ultra-deep tight sandstone gas reservoirs are key targets for natural gas exploration, yet their pore structures under high temperature, pressure, and stress greatly affect gas occurrence and flow. This study investigates representative reservoirs in the Kelasu structural belt, Tarim Basin. Porosity–permeability were measured under in situ conditions, and multi-scale pore structures were analyzed using thin sections, a SEM, mercury intrusion, and nitrogen adsorption. The results show that (1) the median permeability of cores at an ambient temperature and a confining stress of 3 MPa is 13.33–29.63 times that under the in situ temperature and pressure conditions. When the core permeability is lower than 0.1 mD, the stress sensitivity effect is significantly enhanced; (2) nanopores and micron-fractures are well developed yet exhibit poor connectivity. The majority of a core’s porosity is derived from the intergranular pores in clay minerals; (3) the volume of nano-sized pores within the 100 nm diameter range is mainly composed of mesopores, with an average proportion of 73.37%, while the average proportions of macropores and micropores are 22.29% and 4.34%, respectively; (4) full-scale pore sizes show bimodal peaks at 100–1000 nm and >100 μm, which are poorly connected; (5) the pore structure exhibits distinct fractal characteristics. The fractal dimension D_f1 (2.65 on average) corresponds to the larger pore diameters of the primary intergranular pores, residual intergranular pores, and intragranular dissolution pores. The fractal dimension D_f2 (2.10 on average) corresponds to the grain margin fractures, micron-fractures and partial throats. The pore types corresponding to the fractal dimensions D_f3 (2.36 on average) and D_f4 (2.58 on average) are mainly intercrystalline pores of clay minerals and a small number of intraparticle dissolution pores. These findings clarify the pore structure of ultra-deep tight sandstones and provide insights into their gas occurrence and flow mechanisms.

Ultra-deep fractured tight sandstone reservoirs are key targets for natural gas development, where gas flow is controlled by pore structure, capillary forces, and water saturation. Using the ultra-deep tight sandstones from the Tarim Basin as study object, this paper investigates the gas flow behavior in matrix and fractured cores under high-temperature, high-pressure, and various water saturation conditions. The controlling factors of gas flow are investigated through scanning electron microscopy, casting thin-section, and high-pressure mercury intrusion measurements. The results show that increasing the water saturation can significantly reduce the permeability. The permeability of matrix and fractured cores decreases by 71.15% and 79.67%, respectively, when water saturation reaches 50%. The gas slippage is negligible, but the effect of gas threshold pressure is significant, which is primarily controlled by the pore structure and water saturation. The threshold pressure gradient of gas flow ranges from 0.0004 to 0.8762 MPa/cm, with the matrix cores exhibiting values approximately 13.21 times higher than the fractured cores. The water phase preferentially occupies the larger pores, forcing gas flow to rely on the finer pores. The pores with a maximum radius of 0.21 μm require 0.66 MPa of driving pressure for gas, whereas pores with a median radius of 0.033 μm require 4.18 MPa. The fracture networks can significantly reduce the lower limit for gas flow, serving as the key flow channels for the efficient development of ultra-deep tight sandstone gas. These findings not only reveal the gas flow mechanisms under water invasion but also provide theoretical and practical guidance for enhancing gas recovery from ultra-deep tight sandstone reservoirs.

Retained water associated with water-locking can restrict gas production in heterogeneous tight sandstones, and the activity and phase stability of many surfactant treatments are reduced under high-temperature, high-salinity (HTHS) conditions. In this study, a composite surfactant formulation, CSF-1, designed to lower gas–brine capillary resistance and adjust sandstone wettability under representative reservoir constraints, is reported. Its performance was evaluated using thermal aging, surface tension and contact angle measurements, geochemical compatibility tests, laser diffraction, SEM/EDS, and core flooding combined with stagewise low-field nuclear magnetic resonance (LF-NMR). CSF-1 remained macroscopically homogeneous after aging at 170 °C in 188.314 g/L hypersaline brine and retained low gas–brine surface tension when measured at 25 °C after aging. In core flooding tests, CSF-1 increased the apparent gas permeability from 0.203 to 0.388 mD relative to the SFW-saturated water-locked state, corresponding to a 91.1% improvement. One- and two-dimensional NMR measurements provided comparative relaxation domain evidence that CSF-1 promoted the removal and redistribution of relatively mobile and weakly restricted fluid signals and reduced residual signal clustering. The shortest T₂ relaxation domains were less affected. The absence of replicate core flooding and associated LF-NMR runs, together with the non-equivalent Ref-S comparison, precludes a statistically rigorous cross-agent performance ranking. These results support the laboratory water-locking mitigation potential under the tested conditions, without implying calibrated pore-size-resolved removal or field-scale confirmation.