The pore fluid occurrence predominantly restricts shale oil production. Few studies have addressed both pore oil and water concurrently. In an effort to delineate the distribution of pore fluids within shale oil reservoirs, this study collected diverse shale samples from the Qingshankou Formation in the Sanzhao Sag, Songliao Basin, China. The in-situ pore fluids were initially resurrected under equilibrium moisture conditions and subsequently saturated with light oil. A comprehensive suite of analytical techniques was employed in tandem, encompassing total organic carbon (TOC), Rock-Eval, X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption-desorption, and nuclear magnetic resonance (NMR). The occurrence characterizations of pore fluids were clarified by NMR T₁–T₂ spectra across various states, shedding light on the governing factors. A pattern of pore-fluid occurrence in shale oil reservoirs was proposed. Results indicate that NMR T₁–T₂ combined with water and oil restoration effectively assesses the distribution of in-situ pore fluids. Capillary-bound water primarily contributes to pore fluids, with nearly half being depleted at the as-received state. Shale oil mainly comprises capillary-bound oil, succeeded by adsorbed and movable oil. The alterations in shale oil occurrence characteristics are synchronous with the depletion of pore fluids. NMR T₁–T₂ primarily detects the adsorbed oil in shale pores, whereas Rock-Eval is capable of quantifying oil adsorbed on pore surfaces and absorbed within organic matter. NMR T₁–T₂ offers a more precise technique for quantitatively evaluating shale pore fluids. Micropores (<25 nm) and minipores (25–100 nm) are primarily saturated with capillary-bound water, accompanied by a minor fraction of adsorbed oil. Capillary-bound and movable oil are primarily distributed within mesopores (100–1000 nm) and macropores (>1000 nm), respectively. Consequently, adsorbed oil is significantly influenced by pore water, followed by capillary-bound oil, while movable oil remains largely unaffected. Felsic-rich (FR) shales may represent the optimal lithology for shale oil enrichment, characterized by the development of interparticle pores, a lower Brunauer-Emmett-Teller (BET) specific surface area, and abundant meso- and macropores. These insights into the characteristics of pore fluids in shale oil reservoirs could bolster shale oil exploration in the Sanzhao Sag.

Porosity is a fundamental parameter in characterizing the pore structure of shale oil reservoirs, as it directly affects the accuracy of shale oil reserve estimations. Despite the availability of various measurement techniques, accurately quantifying porosity in such reservoirs remains a significant challenge. In an effort to identify the most effective porosity testing method, this study collected samples from four shale oil reservoir intervals across five sags in three different basins. Five porosity testing methods were employed to detect shale porosity, including helium porosity, low-temperature nitrogen adsorption−desorption (LTNA/D), oil-saturated wetting, and nuclear magnetic resonance (NMR) T₂ and T₁−T₂. NMR T₂ porosity acted as a touchstone against which the other methods were compared. The pros and cons of each evaluation technique were explored to select the optimal analysis method for shale oil reservoirs. Results indicate that LTNA/D porosity, derived from powdered samples, commonly fails to reflect shale porosity effectively. Helium porosity, widely used for detecting nanoscale pores, is constrained by extended equilibration times and the retention of residual pore fluids after oil washing and drying, leading to systematic underestimation. In contrast, oil-saturation wetting and NMR T₂ exhibit strong agreement, both reflecting pore fluid content. However, residual fluid distribution can also impact the accuracy of NMR T₂ measurements. NMR T₁–T₂ is an innovative technique for quantitatively evaluating shale oil reservoirs. NMR T₁–T₂ spectrum at the water and oil restoration state can provide accurate shale porosity. NMR T₁–T₂ porosity estimates generally align with those obtained from T₂ porosity. When residual pore fluids are not entirely removable, the NMR T₁–T₂ method offers a more realistic porosity assessment. The NMR technique is recommended for evaluating the porosity of shale oil reservoirs, and the combination of T₂ and T₁–T₂ can accurately determine the effective and total porosity. This research serves as a valuable reference for accurately determining porosity in shale oil reservoirs.