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To reveal the shale oil occurrence state and its controlling factors of the Jurassic Lianggaoshan Formation in the Sichuan Basin, experimental analyses, including total organic content, X-ray diffraction, low-temperature nitrogen adsorption-desorption, nuclear magnetic resonance, conventional, and multistage rock-eval, were conducted on the shale samples. The shale oil occurrence state, the amount/proportion of adsorbed/free oil, and their control factors were clarified. Moreover, the classification evaluation standard of shale oil resources was then determined. The results show that the selected shales are characterized by large oil contents. Total oil ranges from 0.08 mg/g to 10.06 mg/g (mean 2.82 mg/g). Adsorbed oil is between 0.03 mg/g and 5.66 mg/g (1.64 mg/g), while free oil spans from 0.05 mg/g to 4.94 mg/g (1.21 mg/g). The higher the total oil content, the higher the free oil content, indicating that the free oil sweet spot corresponds to the shale oil resource sweet spot. Shale oil is mainly adsorbed in organic matter; the larger TOC content results in the higher adsorbed oil content. Residual shale oil primarily occurs in pores less than 100 nm in diameter, and a higher pore volume corresponds to a higher total oil content. The shale oil enrichment resources refer to the shale with the TOC > 1.5%, S1 > 1.5 mg/g, and S1/TOC > 45 mg/g. This study is helpful for the prediction of shale oil resources and optimizing sweet spots in the Jurassic Lianggaoshan Formation of the Sichuan Basin. [ABSTRACT FROM AUTHOR]

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing–Huangfu area of the Ordos Basin. [ABSTRACT FROM AUTHOR]

Overmature continental shales are widely distributed in China, while few investigations have been conducted. The pore structure is a critical parameter controlling the resource potential of shale gas. However, the pore structure and heterogeneity of continental shales from the Shahezi Formation, Xujiaweizi Fault, Songliao Basin are not well revealed. In this study, helium porosity and permeability, low-temperature N2 adsorption (NGA), mercury intrusion capillary pressure (MICP), and nuclear magnetic resonance (NMR) were applied and characterized to the pore structures of continental shales. Moreover, the heterogeneity and complexity of the pore structure were revealed by the multifractal based on the NMR T 2 spectrum. The results showed that clay minerals, quartz, and feldspar are the dominant minerals in the continental shales, and the most content of the clay minerals is the illite-smectite. The studied shales are the low porosity (mean 1.73%) and the ultralow permeability (mean 0.0707 mD) tight reservoirs. The hysteresis loops of ten shales belong to Types H2 and H3, characterized by high special surface area (mean 5.28 m2/g) and pore volume (mean 14.15 × 10 − 3 c m 3 / g). The pore size distributions are unimodal, and Type H3 shales have more larger pores than Type H2 shales. MICP results indicate that the pore-throats are almost less than 20 nm. NMR T 2 spectra commonly show three peeks, i.e., p1 (<1 ms), p2 (1~20 ms), and p3 (>20 ms) with the small T 2 , g m values, ranging from 0.18 ms to 1.36 ms (0.69 ms), which suggests that more nanopores are in the continental shales. Moreover, the average movable fluid percentage is low, ranging from 1.22% to 15.08% (mean 6.84%). The singularity strength range (Δ α) shows that pore structures are heterogeneous. And the heterogeneity and complexity can be better revealed by the multifractal spectra rather than a monofractal model. [ABSTRACT FROM AUTHOR]

The occurrence states (adsorbed or free) directly control the transport and production of shale oil, and free oil is the most common potential product available using existing technologies. A variety of theories and experimental methods have been developed to estimate the adsorbed and free oil amounts in shale pore-fracture systems, however, it is difficult to clarify the microdistribution characteristics of shale oil in in-situ pore systems using these methods. In the study described here, by integrating experimental and theoretical models, an effective method was developed to reveal the microdistribution of oil confined in nanoporous shales from the Dongying Sag, in the Bohai Bay basin, China. Centrifugation–nuclear magnetic resonance (NMR) experiments were combined with the modified Langmuir equation, and then applied to estimating amounts of adsorbed and free oil. And the microdistribution characteristics of shale oil were then analyzed by the adsorption ratio theoretical model. Furthermore, the mechanisms of controlling the adsorbed, free amounts and microdistribution of shale oil were also discussed. The primary results demonstrated that the modified Langmuir equation (Langmuir-like equation) was an effective and accurate technique for evaluating the adsorbed and free oil amounts in shales. We estimated that adsorbed and free oil amounts ranged from 5.8023 to 29.7995 mg/g, and from 3.9510 to 25.6410 mg/g, respectively, at a temperature of 20 °C, while the adsorbed oil weight ratios were 0.2778–0.7023 (mean 0.5438). The average value of the adsorbed oil density was approximately 2.0231 g/cm³, which was 2.6994 times that of the free oil. The average adsorbed layer thickness was 0.7433 nm, which equaled nearly two molecular diameters. The adsorbed and free oil microdistribution was clearly described by the adsorption ratio theoretical model and the T₂ spectrum. The adsorbed oil was mainly confined to micropores, while free oil was stored in meso- and macropores—and that pore microstructures affected shale oil microdistribution characteristics. The amount of adsorbed oil was mainly controlled by micropore volume and specific surface area, while the amount of free oil was closely associated with total volume of the larger pores. We also noted that the more complex the pore structure, the lower the free oil content and the higher the adsorption ratio. The amount of adsorbed oil was closely related to the shale composition, and increased with TOC content. The amount (ratio) of adsorbed oil also increased with increasing clay mineral content, and was negatively proportional to the quartz + feldspar content. The authors are confident that the study described in this paper has delivered new insights into the microdistribution of adsorbed and free oil in shale pore-fracture systems. • An innovative method evaluating the microdistribution of adsorbed and free oil were developed. • The average value of the adsorbed oil density and adsorbed layer thickness were revealed. • The adsorbed and free oil microdistribution in shale pore systems was clearly described. [ABSTRACT FROM AUTHOR]