To disclose the pore distribution characteristics of different lithofacies lacustrine shales, ten samples collected from the Shahejie Formation, Dongying Sag, Bohai Bay Basin, China, were examined using argon ion beam milling–scanning electron microscopy (SEM). A quantitative method was adopted to characterize shale pore distributions based on the SEM images. Mercury intrusion capillary pressure was employed to determine the pore throat size distributions of the shales. The SEM images indicated that in shale reservoirs, interparticle pores at the edges of brittle particles and intraparticle pores in clay mineral aggregates primarily contribute to the reservoir spaces and that in calcite-rich shales, dissolution pores provide secondary reservoir space. Among the morphologies of dissolution, intraparticle, and interparticle pores, the morphology of the dissolution pores is the simplest, followed by those of intraparticle and interparticle pores in that order. Clay and felsic minerals primarily control the shale pore sizes and the larger the clay mineral content in the shales, the smaller their pore size; the felsic minerals demonstrate the opposite behavior. The image-based point counting data indicate that shale pore sizes are mostly between 20 nm and 2 μm. In contrast, most pore throats are less than 20 nm in diameter, implying that the pores in the nanometer to micrometer scales are connected by tiny throats. Among the four lithofacies shales, felsic-rich shales are favorable for shale oil accumulation and seepage because of their large pore sizes and throats their ability to form intercalated shale oil adjacent to organic-rich shales. Calcareous shales with a large number of dissolution pores and a large content of organic matter could produce self-generation and self-storage matrix shale oil and would typically develop fractures, thereby creating a seepage channel for shale oil. This study presents the micro-distributions of different lithofacies of shale pores, which would help in understanding the occurrence and seepage of oil in shale reservoirs.

To investigate the brittleness of shale and its influencing factors, triaxial rock mechanics experiments, combined with X-ray diffraction, total organic carbon (TOC) measurement, rock pyrolysis, and scanning electron microscopy, were conducted on shales from the Jurassic Lianggaoshan Formation in the Sichuan Basin. BI₁, based on the elastic modulus and hardness, BI₂, based on mineral composition, BI₃, based on strength parameters, and BI₄, based on the post-peak energy of shale, were calculated. Additionally, the effects of mineral composition, density, hardness, and organic matter on the brittleness of shales were analyzed. The results show that the shale mineral compositions were dominated by quartz (mean of 45.21%) and clay minerals (mean of 45.04%), with low carbonate mineral contents and high TOC contents. The stress–strain curve showed strong brittleness characteristics. When comparing different evaluation methods, the brittleness evaluation method based on the stress–strain curve (damage energy) was found to be more effective than the mineral fraction and strength parameter methods. The higher the density and hardness, the more brittle the shale. The higher the organic matter and quartz content, the less brittle the shale. The brittleness of sub-member I of the Lianggaosan Formation in Well XQ1 was higher than that of sub-members II and III. This study investigated the brittleness of lacustrine shale and its influencing factors, which is beneficial for the development of shale oil in the Sichuan Basin.

To accurately evaluate the shale oil resources in the Funing Formation of the Gaoyou Sag, Subei Basin, light and heavy hydrocarbon correction models of S₁ were developed based on the rock pyrolysis of liquefrozen, conventional, and oil-washed shales. The improved ΔlogR technique was applied to establish the TOC, S₁, and S₂ logging evaluation methods. The results showed that the S₂ values after oil washing were significantly lower than before. The difference between these two S₂ (ΔS₂) values is the heavy hydrocarbon correction amount of S₁, which is about 0.69 S₂. There was almost no loss of light hydrocarbons during liquefrozen shales’ pyrolysis tests; the ratio of liquefrozen to conventional S₁ values is the light hydrocarbon correction factor, which is about 1.67. The corrected S₁ is about 3.2 times greater than the conventional shale-tested value. The S₁ and TOC are obviously “trichotomous”; a TOC greater than 1.5% and corrected S₁ larger than 4.0 mg/g corresponds to the enriched resource. The logging estimated results show that the total shale oil resources in the E₁f₂ of the Gaoyou Sag are about 572 million tons, of which the enriched resource is about 170 million tons.

Thermodynamic method is a practical solution to determine the turbine efficiency of heads in excess of 100m without need for discharge measurement directly. Efficiency measurement is performed on a horizontal Pelton turbine with 650m rated head and two jets by thermodynamic method in this paper. Determination of specific hydraulic energy, specific mechanical energy, discharge and efficiency of Pelton turbine are discussed accordingly. To avoid the uncertain impact from unstable flow and velocity profile at low pressure section, an improved method to determine the turbine discharge is introduced, in which discharge may be worked out without need for flow velocity measurement at low pressure section.

Insight into the microscale distribution and abundance of pore-contained oil and water are essential for shale oil resource evaluation. This study investigates continental shales from various oil layers of the Qingshankou Formation in the Gulong Sag, Songliao Basin. Nuclear magnetic resonance (NMR) T1–T2 and T2 measurements were employed to characterize fluid occurrence and quantify oil and water contents. Integrated analyses using scanning electron microscopy, x-ray diffraction, total organic carbon (TOC), and Rock-Eval pyrolysis (conventional and multi-stage) were conducted to evaluate the controls of mineral and organic components on fluid distribution. The shales are mainly composed of clay minerals, quartz, and feldspar. Reservoir space is primarily associated with intergranular pores in quartz and intragranular pores in clay minerals. The NMR T1–T2 spectrum enables the identification of adsorbed, capillary-bound, and movable oil in pores corresponding to T2 peaks p1, p2, and p3, respectively. Capillary-bound water in p1 pores restricts adsorbed oil. Adsorbed oil increases with TOC below 2% but decreases at higher TOC levels. Capillary-bound water correlates with clay content. Vertically, Q7–Q9 layers show high TOC, abundant meso–macropores, and elevated capillary-bound oil. These findings improve understanding of pore fluid behavior and support sweet-spot targeting in K2qn shale oil reservoirs.