New insights into spontaneous imbibition in tight oil sandstones with NMR

Abstract

Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under all-faces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.