Shale oil reservoirs are characterized by having various types of vertical sublayers, a large contrast in rock mechanical properties, well-developed bedding, and high clay content, which are likely to cause rock elastic–plastic deformation. In numerical simulations of hydraulic fracture (HF) propagation in the shale oil reservoirs, the effects of rock elastic–plastic deformation and complex bedding structure on the layer-crossing behavior of HF are not considered. To understand the mechanism of HF height growth in shale oil reservoirs, we used the cohesive zone method to establish an elastic–plastic finite element model of HF propagation by considering the effects of shell limestone interlayers, the Mohr–Coulomb yield criterion for shear–plastic failure, the cross-mechanical interaction between bedding and shale oil reservoir, and the complex situations such as the HF height across high-electrical resistivity bedding and high-conductivity fractures. The effects of internal friction angle, cohesion, layer stress contrast, fracture toughness, bedding bond strength, injection rate, elastic modulus, and bedding shear strength on HF height growth in shale oil reservoirs are studied, and the characteristics of HF width profile, injection pressure, failure mode, and maximum HF width are compared. Compared with the layer stress contrast, cohesion, internal friction angle, and fracture toughness, the injection rate, elastic modulus, and bedding shear strength and bond strength have a larger effect on the vertical HF width. Increment of the injection rate, decrease of the elastic modulus, and increment of the bedding shear strength and bond strength are favorable for HF height growth in the shale oil reservoir. As rock cohesion and internal friction angle increase, the HF width decreases. At the initial stage of fracturing fluid injection, the maximum HF height and injection pressure fluctuate. Lower cohesion and internal friction angle promote rock shear failure in HF height growth. Our study provides guidance for the stimulation of fracture crossing layers in the shale oil reservoirs.

In the oil shale in situ conversion project, it is urgent to solve the problem that the reaction degree of organic matter cannot be determined. The yield and composition of organic products in each stage of the oil shale pyrolysis reaction change regularly, so it is very important to master the process of the pyrolysis reaction and reservoir change for oil shale in situ conversion project. In the in situ conversion project, it is difficult to directly obtain cores through drilling for kerogen maturity testing, and the research on judging the reaction process of subsurface pyrolysis based on the maturity of oil products has not been carried out in-depth. The simulation experiments and geochemical analysis carried out in this study are based on the oil shale of the Nenjiang Formation in the Songliao Basin and the pyrolysis oil samples produced by the in situ conversion project. Additionally, this study aims to clarify the evolution characteristics of maturity parameters such as effective biomarker compounds during the evolution of oil shale pyrolysis hydrocarbon products and fit it with the kerogen maturity in the Nenjiang formation. The response relationship with the pyrolysis process of oil shale is established, and it lays a theoretical foundation for the efficient, economical and stable operation of oil shale in situ conversion projects.

In this study, fluid viscosity effects on LSP performance in terms of boosting pressure were numerically investigated. A water–glycerin mixture with different concentrations corresponding to varying apparent viscosities was flowed through an in-house manufactured LSP under various flow conditions, e.g., changing flow rates, rotational speeds, and fluid viscosities. The pressure increment between the intake and discharge of the LSP was recorded using the differential pressure transducer. The same pump geometries, fluid properties and flow conditions were incorporated into the numerical configurations, where three-dimensional (3D), steady-state, Reynolds-averaged Navier–Stokes (RANS) equations with a standard SST (shear stress transport) turbulence model were solved by a commercial CFD code. With the high-quality poly-hexcore grids, the simulated pressure increment was compared with the corresponding experimental measurement. The internal flow structures and characteristics within the cavities contained by the LSP impeller and diffuser were also analyzed. The good agreement between the numerical results against the experimental data verified the methodology adopted in this study.

A downhole electric tubular resistive heater is proposed for the oil-shale in situ resorting. After flowing through a set of heating tubes, the outlet temperature and the flow rate of the injected gas can be conveniently adjusted to match the requirement of the pyrolysis temperature of the oil shale. The calculation demonstrates the effects of the inner diameter, the length of the heating tube, and the inlet flow rate on the heat transfer performance of the electric heater. It was found that, compared with the armored electric heaters, even with a small inject flow rate of 5 Nm³/min, the convective heat transfer coefficient of the inner flow exceeds 300 W/m² K, resulting in a much smaller thermal resistance. The outlet temperature of the heating gas can conveniently reach up to 900 °C with the absence of the complex structure of enhanced fins. Though the pressure loss is relatively larger under a high flow rate, the comprehensive index is still 40% higher, indicating that the present tubular electric heater is a promising candidate to deal with complex downhole conditions.

The feasibility of the autothermic pyrolysis in situ conversion (ATS) process for low-grade oil shale (OS) has not been determined. In this research, the pyrolysis and combustion properties of Tongchuan OS, with a 4.04% oil yield, were systematically analyzed. The findings revealed that temperatures between 350 and 425 °C favored oil production, while temperatures from 450 to 520 °C resulted in a higher rate of gaseous generation. At 300 °C, the volume expansion and ignition coking caused by the large amount of bitumen generated resulted in severe pore plugging, which significantly increased the combustion activation energy of the residue, while the presence of substantial flammable bitumen also significantly decreased the ignition and combustion temperatures. From 300 to 520 °C, the combustion performance of residue decreases continuously. In addition, pyrolysis residues of Tongchuan exhibited a slightly higher calorific value, between 425 and 520 °C, owing to its higher fixed carbon content (10.79%). Based on the ideal temperature screening method outlined for Tongchuan OS, the recommended preheating temperature for Tongchuan OS was 425 °C, while the optimum temperature for the retorting zone should be 510 °C, considering a heat utilization rate of 40%. These findings contribute valuable insights for the application of the ATS process to low-grade OS.

In order to weaken the influence of external groundwater on in situ pyrolysis exploitation, the flow characteristics of groundwater were studied according to the oil shale reservoir characteristics of Qingshankou Formation in Songliao Basin, China. In addition, the parameters of marginal gas flooding for water-stopping were optimized. Taking a one-to-one pattern and a five-spot pattern as examples, the characteristics of groundwater flow under the in situ process were studied. Under the one-to-one pattern, the external groundwater flows into the production well from the low-pressure side, and the water yield was basically stable at 1000 kg/d. In the five-spot pattern, the groundwater can flow into the production wells directly from the windward side, and the water yield of the production well on the leeward side mainly comes from the desaturated zone; the water yield of each production well remains at a high level. By setting water-stopping wells around the production well and keeping the gas flooding pressure slightly higher than the production well, the water yield of the production well can be reduced and stabilized within 100 kg/d under gas flooding pressures of 3 and 5 MPa. However, the gas yield of the production well slightly decreased when the gas flooding pressure reduced from 5 to 3 MPa. Therefore, the gas flooding pressure of water-stopping wells shall be determined in combination with the water yield and gas yield, so as to achieve the best process effect. It is expected that the results will provide technical support for large-scale oil shale in situ pyrolysis exploitation.