The Gulong Sag in the Songliao Basin is an important region of China where significant breakthroughs have been achieved in the exploration of medium- and high-maturity lacustrine shale oil. However, the major controlling factors and evolution patterns of shale reservoirs in this sag remain poorly understood. This study focuses on shales in the 1st member of the Qingshankou Formation (also referred to as the Qing 1 Member) in the Gulong Sag. By integrating multiple analytical techniques, including Rock-Eval pyrolysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), nitrogen adsorption, high-pressure mercury injection (HPMI), and nuclear magnetic resonance (NMR), we systematically analyze the organic geochemical characteristics of the shales, as well as the reservoir space types and their sizes and distribution patterns. The analytical results show that the shales in the sag contain organic matter dominated by high-quality Type Ⅰ kerogen. These shales were deposited in a semi-deep to deep lacustrine anoxic environment and are currently in oil generation state with moderate to high maturity. Reservoir development in the shales is jointly governed by the sedimentary environment, diagenesis, organic matter type, and thermal evolution. Specifically, intense compaction and cementation in the early stage lead to substantial loss of primary pores. With an increase in thermal maturity, the dissolution of minerals such as feldspars, together with the hydrocarbon generation of organic matter, collectively contribute to secondary pore growth. Consequently, reservoir spaces in the shales progressively evolve into an organic-matter- and clay-hosted composite pore system dominated by nano-scale pores. The reservoir space evolution pattern of shales in the Qing 1 Member established in this study provides an important theoretical basis for shale oil exploration in the Gulong Sag. Furthermore, other relevant patterns and research approaches involved in this study may provide references for the exploration of other shale oil plays.

The Jurassic Lianggaoshan Formation shale is a key exploration interval in the Sichuan Basin, but its pore structure and shale oil mobility are still unclear. In order to reveal the reservoir space characteristics and the mobility of shale oil in the Lianggaoshan Formation, this paper divided lithofacies types according to sedimentary structure and mineral composition. Basic geochemical characteristics were obtained by total organic carbon determination, rock pyrolysis and vitrinite reflectance experiments. The porosity and pore structure were characterized and evaluated by means of field emission scanning electron microscopy, nuclear magnetic resonance, low temperature nitrogen adsorption and high pressure mercury injection. The difference in reservoir space characteristics between different rock phases was also compared. With a centrifugation time of 3 h and centrifugation speed of 11 000 r/min, quantitative evaluation of the mobility of shale oil with different lithofacies was carried out by NMR centrifugation and the influential factors are clearly defined. The evaluation model of movable oil quantity logging was established and. the favorable rock facies was selected. The results show that: (1) The TOC of Lianggaoshan Formation shale is mainly between 0.15%~2.95%, the R_o is between 1.06%~1.68%, and the shale is in the mature-high mature stage. After the recovery of light hydrocarbons, the change range of S₁ was 0.03 mg/g ~3.32 mg/g. The mineral types are mainly clay minerals and quartz. The developed lithofacies are lamellar clay shale facies, lamellar felsic shale facies, lamellar mixed shale facies and massive silty mudstone facies. (2) Shale reservoir space types are mainly clay mineral intergranular pores, organic matter pores, in addition to quartz dissolution pores, interparticle pores, pyrite intergranular pores and microfractures. The porosity is between 1.15% and 4.71%. The shale has a wide pore size distribution. The pore volume is mainly contributed by mesopores and macropores smaller than 200 nm. Laminated clay shale has the best physical properties (3) the movable oil content of the Lianggaoshan Formation shale ranges from 0.25 mg/g to 3.26 mg/g, and the movable oil rate ranges from 5.13% to 44.8%. Lamellar clay shale has the best mobility, and massive silty mudstone has the worst mobility. TOC, clay mineral content and porosity are the key factors controlling movable oil content in the Lianggaoshan Formation. Based on these three factors, a mobile oil quantity prediction model is established and verified. Laminated clayey shale is preferred as the key exploration object of the Lianggaoshan Formation, which is indicative of the exploration and development of shale oil in the Sichuan Basin.

Breakthroughs have been achieved in the exploration of lacustrine shale oil. However, the dominant geological factors controlling the enrichment and high yield of shale oil remain unclear, restricting its efficient exploitation. The fine characterization of various laminae can reveal the major factors controlling shale oil enrichment. This study focuses on the carbonate-rich shales of the Paleogene Shahejie Formation in the Jiyang Depression. Using thin section observations and field emission scanning electron microscopy (FE-SEM), we analyze the reservoir spaces and oil-bearing properties of typical laminae and reveal the controlling effects of the lamina assemblages of shales on oil enrichment. The results indicate that carbonate-rich shales in the upper sub-member of the 4th member of the Shahejie Formation (Es₄^U) within the Jiyang Depression contain five lamina types: fibrous calcite laminae, micritic calcite laminae, very fine crystalline calcite laminae, clay-mineral-rich laminae, and mixed laminae. Major lamina assemblages include the combination of micritic calcite laminae, clay-mineral-rich laminae, and mixed laminae, and the combination of fibrous calcite laminae, very fine crystalline calcite laminae, clay-mineral-rich laminae, and mixed laminae. The clay-mineral-rich and mixed laminae, among others, exhibit high organic matter content, serving as the material basis for shale oil enrichment. Meanwhile, the very fine crystalline calcite laminae, with well-developed reservoir spaces, act as preferential storage media for shale oil. Additionally, the superposition of clay-mineral-rich laminae with very fine crystalline or micritic calcite laminae forms the optimal lamina configuration for shale oil enrichment. Therefore, the carbonate-rich shales with the clay-mineral-rich laminae and very fine crystalline or micritic calcite laminae assemblage serve as an important target for shale oil exploration and exploitation.

Investigating the adsorption behavior in organic matter and its associated pores holds critical significance for revealing the occurrence states and mechanisms of shale oil. Differing from the previous method of replacing the organic matter model with the graphene model, a realistic kerogen molecular model, the Type Ⅱ-C model, is employed to simulate the adsorption behavior of multi-component shale oil within organic pores based on the general Amber force field (GAFF). The results are as follows. (1) Unlike graphene, which can only be used to simulate surface adsorption, kerogen has the dual functions of both adsorption and absorption. Competitive shale oil adsorption transpires on kerogen walls, dominated by the adsorption of polarity and heavy components, while the kerogen skeleton is characterized by absorption of small molecules moving far away. The shale oil adsorption on the surface and absorption in the skeleton with migration are influenced by the interaction energy between shale oil and kerogen, as well as the molecular size. Specifically, heavy components of shale oil are subjected to strong adsorption but weak absorption, while its light components undergo weak adsorption but strong absorption; (2) The absorption of shale oil components leads to the deformation of the kerogen skeleton and pores, manifested as the formation of new pores and the expansion and partial collapse of original pores. The plasticity of kerogen plays a significant role in its shale oil absorption and further skeleton swelling. Highly plastic kerogen (with low maturity) is more prone to absorb shale oil and swell significantly in skeleton. In contrast, weakly plastic kerogen swells slightly with absorption; (3) An increase in temperature enhances the absorption of aromatic hydrocarbon molecules (like naphthalene) and non-polar molecules (e. g., formic acid, ethanol, and thiophene) in kerogen skeleton, which reduces the adsorption on kerogen surface, and is conducive to the desorption of saturated hydrocarbon molecules. Additionally, pressure produces insignificant effects on the shale oil adsorption and absorption in kerogen. In this study, the realistic kerogen molecular model is innovatively applied to simulate kerogen’s adsorption and absorption of shale oil components, which is of great help in objectively revealing the shale oil occurrence state and mechanism in kerogen.

Shale oil composition serves as both a basis for revealing the shale oil enrichment mechanism and an essential parameter used to explore the interactions among oil, water, and rocks in the pores. We investigate the shale oil reservoir of pure shale type in the 1^st member in the Qingshankou Formation in the Gulong Sag, Songliao Basin; the shale oil reservoir of transitional type in the Chunshang interval of the upper sub-member of the 4^th member of the Shahejie Formation in the Dongying Sag, Jiyang Depression, Bohai Bay Basin; and the shale oil reservoir of pure shale type in the 3^rd sub-member of the 7^th member of the Yanchang Formation, Ordos Basin. Shale samples taken bypressure-retained coring and conventional coring, as well as oil produced from the three shale intervals and the products of autoclave-based thermal simulation experiment, are subjected to composition analysis. The composition of shale oil of diverse types and with varying maturity is characterized through chromatography to determine the total petroleum hydrocarbons (TPH) and pyrolysis-gas chromatography (PY-GC). The methods for deriving shale oil compositions are comprehensively summarized and compared in terms of result, and the factors affecting the composition after evaporative loss are discussed. The assessment scheme is proposed at last. Consequently, we identify the compositional differences for the produced oil, thermally desorbed hydrocarbons, shale extracts, and products from thermal simulation experiment, as well as clarify the limitations of the above-mentioned evaluation methods. Additionally, the phenomenon that shale intervals with high total organic carbon (TOC) content tend to be of high oil content is illustrated, as revealed in previous studies. However, these intervals of high oil content do not necessarily reflect a high ratio of mobile to total oil volume. Shale maturity directly determines the composition of shale oil, while the abundance of organic matter and pore structures exert certain effects on the composition of residual hydrocarbons in shales. As indicated by the results of this study, it is necessary to consider hydrocarbon evaporativeloss in evaluating oil content in shales and exploring fluid occurrence state and shale oil enrichment mechanism, especially for shales of medium to high maturity. The composition evaluation of shale oil at varying maturity can provide new insights for revealing the fluid occurrence characteristics in shale nanopores.

Shale porosity measurements have crucial scientific and economical applications in unconventional petroleum systems. As a standard technique, liquid saturation methods, including water saturation (WS) and oil saturation (OS), have been widely used to measure the porosity of many rock types. For clay-rich shale reservoirs with high organic matter content, it is well known that the WS method may cause clay swelling and induce structural changes in the pore system. The OS method affects the accuracy of porosity measurements because of some of the oil being dissolved by kerogen within the shale; however, this has not received sufficient research attention. In this study, we compare the previously reported and newly tested OS porosities with helium (He) expansion porosity. Results show that OS porosity generally exceeds the He porosity. Furthermore, the higher the total organic carbon (TOC) content and lower the maturity of shale, the greater the difference between the OS and helium porosities. When using the OS method, the effect of kerogen-dissolved oil causes an overestimation of the shale porosity by ~30%. To the best of our knowledge, this is the first time to note the kerogen-dissolve oil effects on OS porosity. Herein, we propose a new, simple, and effective correction method for estimating OS porosity that involves subtracting the kerogen-dissolved oil content from raw OS porosity. In addition, the quantification model of kerogen-dissolved oil capacity is established, taking into account the abundance and maturity of organic matter. Taking the He porosity as the benchmark, the absolute error of the corrected OS porosity does not exceed 1% and the average relative error is only ~10%. The obtained results can help improve the accuracy of shale porosity evaluation methods.