In view of the limited insights into the threshold pressure gradients (TPGs) of low-permeability reservoirs and inadequate methods for determining their drainage radii, we present a detailed analysis of the variation characteristics and mechanisms of the TPG in combining experiments with numerical simulations, and propose a method for calculating the drainage radii of low-permeability reservoirs which considering the stress conditions of actual reservoirs. The results indicate that the TPG of a reservoir is not a fixed value. Instead, it changes with the net confining pressure, exhibiting a strong positive correlation. The curve showing the relationship between the TPG and the net confining pressure follows a three-stage pattern. In the first stage, plastic deformations occur, primarily involving the closure of microfractures and the sharp contraction of large pore throats. This stage has a significant impact on the seepage capacity of reservoirs, with the TPG increasing by more than five times. The second stage is characterized by pseudoplastic deformations, principally reflected in the contraction of large pore throats and microfractures, with the TPG increasing by over 40 %. The third stage shows elastic deformations, characterized primarily by the contraction of small pore throats. This stage has a minimal impact on the seepage capacity, with the TPG increasing by only 17 %. Notably, the stress state of rocks in most actual low-permeability reservoirs corresponds to this elastic deformation stage. Based on the dynamic changes in the TPG and the presence of pressure drop funnels in actual reservoirs, we determine the changes in the net overburden pressure and then calculate the threshold pressure along a certain seepage distance in reservoirs through integration. Assuming that the threshold pressure equals the driving pressure difference, we derive the seepage distance (i.e., the driving drainage radius) through inversion. Finally, the feasibility of the proposed method for determining the drainage radius is verified through practical application. This study enhances the understanding of the characteristics of low-permeability reservoirs while also providing a significant theoretical basis and technical support for the assessment and exploitation scheme optimization of low-permeability reservoirs.

The process of spontaneous imbibition is the basis of oil recovery from tight oil reservoirs. In this study,spontaneous imbibition experiments were conducted based on tight oil weakly hydrophilic sandstone cores from the Honghe oilfield in the Ordos Basin. Four different types of surfactants,such as nonionic Triton X-100,nonionic Tween-80,cationic dodecyl trimethyl ammonium bromide,and anionic sodium dodecyl benzene sulfonate,were separately dissolved in 30 g/L potassium chloride solution as simulated formation water. The effects of surfactant type on spontaneous imbibition were analyzed,and the results indicated that,because the nonions are adsorbed on the surface via Van der Waals force and adsorb H⁺ through hydrogen bonds,the two nonionic surfactants altered the wettability of the core from weakly hydrophilic to strongly hydrophilic,the recovery rate was relatively high. The Triton X-100 was selected for subsequent spontaneous imbibition experiments by changing the mass concentration to adjust interfacial tension. It was found that the maximum recovery rate was 32% when the Triton X-100 mass concentration was 0.1%,which indicates that the enhanced recovery rate of spontaneous imbibition requires a sufficiently low wettability factor and a suitably high interfacial tension factor. Finally,the surfactants mixed with 0.03% sodium dodecylbenzene sulfonate and 0.1% Triton X-100 were used for spontaneous imbibition,attaining an oil recovery of up to 45%,which was 21.6% higher than that of single-surfactant imbibition. It was established that the synergistic mechanism depends on the wettability alteration of nonionic surfactant facilitating the spontaneous imbibition,while the anion accelerates oil removal from the core by continuously encasing oil droplets in the aqueous phase. This paper provides a theoretical basis for the imbibition development of weakly hydrophilic tight sandstone with high-salinity formation water.