The Permian Lucaogou formation in the Jimsar sag, Junggar Basin, represents one of the most significant continental shale oil plays in China. However, uncertainties remain regarding the primary geological controls of “sweet spots”, incomplete evaluation frameworks, and discontinuous distribution of productive intervals. Clarifying the formation mechanisms and identification criteria of the sweet spots is critical for advancing shale oil exploration theory and guiding efficient development. Based on core, well logging, and experimental data, this study systematically investigates the controlling factors of shale oil sweet spots in the Lucaogou formation from four dimensions (reservoir capacity, oil-bearing capacity, mobility, and fracability). The results indicate that the Lucaogou formation can be divided into upper, middle, and lower sweet-spot intervals, among which the middle interval remains largely undeveloped yet holds substantial potential. Siltstone and calcareous-felsic shale which are characterized by abundant macropores, high free hydrocarbon content, and strong mobility constitute the most favorable lithofacies. Intervals with moderate total organic carbon (TOC) content, moderate maturity, and high brittle-mineral content are more conducive to forming fracable sweet spots. A four-property coupling evaluation highlights the middle interval as a prime development target which is further validated by the high-yield performance of Well JHW85-71. This study provides a scientific foundation for sweet spot identification and development planning of shale oil in the Lucaogou formation in the Jimsar sag.

The shale oil sweet spot reservoirs of the Permian Lucaogou formation in the Jimsar sag of Junggar Basin are characterized by complex lithology and greatly varying physical properties, and diagenesis has played an important role in the pore evolution of these reservoirs. Using rock slice, cast thin section, scanning electron microscopy (SEM) and X-ray diffraction (XRD), this paper studies the microscopic characteristics of the pores in the reservoirs to reveal pore genesis, and variations and controlling factors of reservoir physical properties. The results indicate two types of reservoirs, i.e. sandstone reservoir and dolomite reservoir are developed in the sweet spots of Lucaogou formation in the Jimsar sag. Both reservoirs are dominated by secondary pores such as intergranular dissolution pores, intragranular dissolution pores, moldic pores and dissolution fractures, and contain the macropores with diameter >50 μm accounting for more than 50%. The sandstone reservoir and dolomite reservoir have similar physical properties, belonging to medium porosity and low-ultra-low permeability reservoirs. The average porosity and permeability of the sandstone reservoir are 13.51% and 0.81mD, respectively. The dolomite reservoir exhibits an average porosity of 12.86% and an average permeability of 2.38 mD. Both reservoirs have undergone compaction, weathering/leaching dissolution, cementation, and organic acid dissolution, and are in phase A of the middle diagenetic stage. The weathering/leaching dissolution in the epidiagenetic stage accelerated the formation of large pores like capillary pores and supercapillary pores, which are the main contributors to reservoir space. The dissolution of organic acid in the middle diagenetic stage promoted the formation of nanoscale microcapillary pores, which exerted a limited improvement on reservoir physical properties.

Significant breakthroughs have been made in the exploration of continental shale oil in China. However, the strong heterogeneity and complex source-reservoir coupling in these shales have hindered the understanding of sweet spot formation mechanism. In this paper, taking the Permian Fengcheng formation in the Junggar Basin as an example, the characteristics of shale laminae and their controls on shale oil sweet spots were systematically investigated using multiple techniques such as large-area thin-section scanning, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), confocal laser scanning microscopy (CLSM), and organic geochemical analysis. The results indicate that the lacustrine shales of the Fengcheng formation are well-laminated. The laminae can be classified into six types: silt-grade felsic lamina (SFL), argillaceous-grade felsic lamina (AFL), sparry dolomitic lamina (SDL), sparry calcite lamina (SCL), spherulitic siliceous lamina (SSL), and alkaline mineral lamina (AML). Two predominant laminated shale combinations are identified, i.e., SFL + AFL, and SCL/SDL + AFL. These lamina types exhibit significant variations in source-reservoir characteristics. AFL and SSL, characterized by high organic matter (OM) contents and the presence of high-quality hydrocarbon precursors such as laminated algae and rhodophyta spores, serve as the primary hydrocarbon-generating laminae. In contrast, SFL exhibits well-developed micropores and nanopores, including quartz/feldspar intercrystallline pores and feldspar intragranular dissolved pores, with a high proportion of free oil, rendering it favorable reservoir lamina. The superimposition of multiple lamina types governs organic-inorganic interactions, reservoir space characteristics, and hydrocarbon micro-migration processes, ultimately leading to differential enrichment of shale oil across various intervals. It is noted that the SFL + AFL combination represents the optimal source-reservoir configuration, demonstrating excellent overall oil content and forming an enrichment model characterized by oil generation in argillaceous lamina and accumulation in silty lamina. This combination is identified as a favorable target for shale oil exploration and development.

Complex microscopic occurrence and unclear production dynamics of shale oil in continental saline lacustrine basins challenge the study of shale oil enrichment theory and development law. Taking the Lucaogou formation in the Jimsar sag of Junggar Basin as an example, this paper characterizes the fluid occurrence state and mobility in the shale reservoirs using the techniques such as nuclear magnetic resonance, confocal laser scanning microscopy, argon ion polishing, and scanning electron microscopy, and validates against the monitoring results of produced fluid from individual wells in the pilot test area. The results show that the microscopic occurrence of the shale oil is characterized by oil fully saturating nanopores and both oil and water coexisting in sub-micron to micron-sized pores, with light and heavy components in hydrocarbons arranged in an onionskin pattern. The natural depletion of shale oil prefers the light hydrocarbon components stored in sub-micron to micron-sized pores, where free water is involved in the fluid flow. Changes in crude oil properties and produced water during well production represent effective responses to the microscopic fluid occurrence state. Shale oil well production is featured with by long-term water production and sequential producing of light and heavy components.

The main factors controlling the enrichment and high production of alkaline lacustrine shale oil in the Permian Fengcheng formation in the Mahu sag of Junggar Basin remain unclear, which limits theoretical understanding and efficient development. Based on the petrological, organic geochemical and physical characteristics of the Fengcheng shale oil reservoirs, the effects of source rock and reservoir lithology on shale oil enrichment in the Fengcheng formation were analyzed. Combined with the production profiles obtained from the key wells, the influences of shale oil enrichment, fractures and formation overpressure on the production of shale oil were identified. The findings are obtained in five aspects. First, in the Fengcheng shale oil reservoirs, the free hydrocarbon content increases with the increase of total organic carbon content (TOC), and the oil saturation index increases with the burial depth, indicating that the abundance, type and maturity of organic matter are the key factors determining the enrichment of shale oil. Second, siltstone exhibits the best storage space, followed by mudstone and endogenous rock, suggesting that the reservoir lithology controls the storage space and thus affects the enrichment of shale oil. Third, the enrichment is fundamental to the high production of shale oil. The shale oil production per meter from the Fengcheng reservoirs increases with the increase of TOC and feldspar mineral content. Fourth, the relationship between fracture orientation and present-day maximum horizontal principal stress direction affects the flow and production of the shale oil. Fifth, formation overpressure plays a role in retaining porosity, increasing permeability, reducing viscosity, and enhancing production/recovery of shale oil. The study clarifies the main factors controlling the enrichment and high production of shale oil in the Fengcheng formation, providing a scientific basis for further exploration and development.

The Junggar Basin holds abundant mixed shale oil, with total resources of 34.9×10⁸ t booked, which is the main strategic target for Xinjiang oilfield to achieve additional reserves and production. However, the strong heterogeneity of mixed shale oil reservoirs makes sweet spot identification and evaluation challenging, limits the promotion of available technology system, and threatens the large-scale and cost-effective development. The enrichment patterns and reservoir characteristics of shale oil in the Junggar Basin, and the corresponding engineering processes/technologies are systematically analyzed in this paper. The technologies formed during the exploration and development of mixed shale oil are summarized, mainly with respect to sweet spot identification, supporting engineering, and development deployment. The differential enrichment theory of mixed shale oil is constructed, and a cost-effective shale oil productivity model integrating sweet spot identification, three-dimensional deployment, excellent fast drilling and completion, efficient fracturing, and environmental protection is established. These achievements support the construction of the first national demonstration zone for continental shale oil in China, and guide the efficient exploration and development of continental shale oil in the country.

In the Jimsar sag, the replacement areas for shale oil development in the Lucaogou formation contain abundant resources, but exhibit small reservoir thickness and heterogeneous sweet spot distribution. Through experimental tests involving organic geochemistry, petrology, pore structure, and hydrocarbon occurrence/mobility, a comprehensive evaluation was conducted on the source rock, crude oil property, reservoir lithology, pore type, and shale oil occurrence/mobility in the replacement areas. The results show that the replacement areas have favorable source rock conditions, and have generally experienced two oil-generating peaks, with significantly lower crude oil density and viscosity and a higher proportion of light components, as compared with the primary zones. The reservoirs in the replacement areas are characterized by small thickness and fine grain size, with underdeveloped intergranular pores but relatively developed dissolution pores and intercrystalline pores, demonstrating a similar pore size range to the primary zones but smaller pore-throat radii than the latter. Both the replacement areas and primary zones hold oil in multiple types of pores, with similar shale oil occurrence patterns. The lower limit of pore size for free hydrocarbon occurrence in the replacement areas is 40-60 nm, which is smaller than that in the primary zones. Crude oil viscosity has a significant control effect on shale oil mobility. Under low viscosity conditions, the crude oil in the replacement areas is highly mobile, with a smaller cutoff than the primary zones according to the nuclear magnetic resonance (NMR) mobility interpretation. The movable oil quantity, oil saturation, pore pressure, and brittleness are the key factors affecting the productivity of the replacement areas. Based on these research insights, a sweet spot evaluation technique combining the weights of these four factors was reconstructed, revealing an accuracy of sweet spot identification in the replacement areas exceeding 80%. The research results provide theoretical support for the stable production of shale oil in the Lucaogou formation.

In response to the challenges in enhancing volumetric stimulation effectiveness in the shale oil reservoirs of the Lucaogou formation in the Jimsar sag of the Junggar Basin, a systematic study was conducted. Based on the lithological assemblage characteristics and geomechanical parameters of the study area, numerical simulation was employed to analyze the propagation patterns of hydraulic fractures under different lithological assemblages. The research focused on the controlling effects of interlayer strength, in-situ stress, interface strength coefficient, displacement, and horizontal well placement on fracture propagation, and explored a differentiated optimization method for fracturing stages. The results indicate that an increase in the elastic modulus of the reservoir/barrier layers and a decrease in tensile strength both facilitate vertical fracture propagation, whereas a high horizontal stress difference significantly inhibits vertical fracture extension. A critical threshold exists for the interlayer interface strength coefficient, which directly governs fracture propagation behavior. Under this critical condition, high displacement promotes fracture penetration through barriers, while low displacement lead to fracture diversion along interfaces. Well placement exhibits a limited impact on fracture geometry, as effective vertical propagation can be achieved regardless of whether the horizontal well is placed within the reservoir or barrier layers. A nonuniform staging scheme based on geological-engineering sweet spot evaluation effectively enhances stimulation efficiency and reduces ineffective operations. This research results provide theoretical support and practical guidance for optimizing horizontal well trajectory, fracturing stage design, and treatment parameters in the shale oil development of the study area.

In light of the geological characteristics of continental shale oil reservoirs，a numerical model for unbalanced fracture propagation during horizontal well intensive fracturing was constructed using the cohesive zone method to study the effects of cluster spacing and lamina on unbalanced propagation of multiple fractures and then elucidate the mechanism of unbalanced fracture propagation during horizontal well intensive fracturing. True triaxial physical simulation experiment was conducted on samples taken from the field outcrop of shale oil reservoirs to investigate the mechanical behaviors of multi-fracture initiation and cross-interface propagation and thereby reveal the mechanism of mechanical interaction between fractures and lamina during intensive fracturing. Comprehensive analysis indicates that the development degree of lamina in shale oil reservoirs is the key determinant of the complexity of fracture network. Increasing cluster spacing effectively enhances the connectivity of the lamina and interfaces. The difference in propagation rate among fracture clusters decreases with the increase of cluster spacing，and the central fractures are more prominently affected by stress interference when cluster spacing is small. The multiple-clustered fractures exhibit a mutually complementary propagation pattern. Reasonably controlling cluster spacing can improve the vertical extension of fractures，thereby expanding the coverage of fracture system and enhancing the fracturing efficiency in shale oil reservoirs.

The Jimsar Shale Oil Demonstration Area in the Junggar Basin, one of the first national continental shale oil demonstration areas in China, has entered the stage of large-scale production. Due to geographical constraints, the well placement optimization and design are indefinite. A reliable geological model is established based on the geology-engineering integration and deviation of well azimuth and operation parameters are optimized through numerical simulation. The results indicate that the platform exhibits characteristics of normal-fault stress, with the minimum horizontal principal stress of 62-72 MPa. The simulated hydraulic fracture length is about 85% of the microseismic monitoring results, and the simulated hydraulic fracture height is similar to the wellbore temperature monitoring results. As the angle between the well azimuth and the maximum horizontal principal stress direction decreases, the hydraulic fracture length increases, while the stimulated reservoir volume (SRV) decreases. Some hydraulic fractures in adjacent sections merge at the part where natural fractures are present, and the proportion of repeated stimulation and degree of heterogeneity of such fractures increase. This suggests that for wells with small angle, the fracturing section length can be extended or the number of clusters in a single section be reduced properly. It is recommended that the optimal well spacing be 200-300 m when the deviation of well azimuth does not exceed 60°, and the optimal well spacing be decreased to maintain a high oil recovery when the well azimuth deviates greater than 60°.

The Jimsar Shale Oil Demonstration Area in Xinjiang, China’s first national-level lacustrine shale oil demonstration area, is in the middle to late stage of development. The concentrated placement of horizontal wells and large-scale fracturing have led to fracture activation, causing casing deformation and impeding the development progress. Considering that the conventional numerical simulation of casing deformation yields results with low accuracy of multiple types of faults in strike-slip fault zones, a strike-slip fault induced casing deformation model was established and then combined with engineering practices to reveal the factors controlling the casing deformation induced by strike-slip fault. The results show that the casing deformation is mainly controlled by fracture dip, applied fluid pressure, and angle between the fracture orientation and the maximum horizontal principal stress direction. For the section of casing deformation at the risk level 1, the injected liquid volume should be reduced to 65%-70% of the original level as designed, and the temporary plugging should be advanced to the time when the injected liquid volume reaches 300 m³, so that the risk of casing deformation can be effectively mitigated. The research breaks through the limitations of traditional fracturing design in the homogenization treatment of strike-slip fault zone, and provides a theoretical basis for the prevention of casing deformation and efficient development of shale oil in complex fault systems.

Nuclear magnetic resonance (NMR) logging is a critical method for obtaining the porosity of shale oil reservoirs, but the varying vertical resolutions of different logging tools severely affect the division of oil layer thickness and the characterization of sweet spots. The spectral characteristics of different NMR effective porosity curves were analyzed through the Fourier transform. With the spectral amplitudes of the logs including microspherically focused resistivity, acoustic, neutron porosity, and P-type NMR effective porosities selected using the ReliefF algorithm as the input features for the machine learning (ML) model, and the spectral amplitude of CMR-type NMR effective porosity log as the target value, a prediction model for the spectral amplitude of NMR effective porosity was constructed using decision tree (DT) and LSBoost ensemble tree. The prediction results of different ML models were compared, showing that the LSBoost ensemble tree model is the most accurate. For purpose of resolution matching among different NMR logs, the time-frequency analysis was innovatively integrated with the resolution matching to form a method for improving the resolution of NMR effective porosity log through spectral amplitude transplantation. This method has been validated to significantly enhance the resolution of low-resolution NMR effective porosity logs. The reconstructed NMR effective porosity logs are significantly superior in oil layer thickness division, fully proving that this resolution matching method is highly promising, laying a foundation for the precise characterization of sweet spot distribution and the efficient extraction of shale oil in the Permian Luocaogou formation in the Jimsar sag of the Junggar Basin. However, this method is limited when applied in strata with high pyrite content or small thickness.

Deep seismic signals exhibit serious high-frequency energy attenuation, leading to lower resolution than required level in production. Conventional frequency-increasing methods primarily operate on the amplitude spectrum of seismic signals, but cannot restore original phase spectrum, resulting in signal distortion and poor lateral continuity of events. Based on the time-frequency analysis of S transform, this paper proposes a method that directly performs spectral whitening on point complex spectrum to ensure that the phase of seismic signals remains unchanged before and after point complex spectral operation, which can effectively improve seismic data resolution while preserving signal-to-noise ratio and lateral continuity of seismic events. The conventional deconvolution method, traditional spectral whitening frequency-increasing method and point complex spectrum-based frequency-increasing method were applied to the seismic data processing of the Permian Lucaogou formation in the Jimsar sag. It is found that the point complex spectrum-based frequency-increasing method is better performed than the other two methods, and it can provide high-fidelity, amplitude-preserving, high-resolution seismic data for seismic prediction of thin sweet spots.

Based on the high-precision petrophysical experiments and the data acquired by new logging techniques, a logging-based characterization was conducted on three key parameters (lithofacies, effective porosity, and movable oil porosity) of shale oil reservoirs in the Fengcheng formation of Mahu sag, Junggar Basin. The following results are obtained. First, according to the core characteristics, FMI images, pore types, and mineral contents, the Fengcheng shale oil reservoirs are divided into felsic, dolomitic/calcareous, and clayey mixed lithofacies. The diamictite index and micro-pore index are constructed to identify lithofacies. Second, a tight reservoir analysis (TRA) experiment is performed to measure porosity of rock samples, confirming that the felsic lithofacies presents the best physical properties. Using TRA experiment results to calibrate the NMR logging data, an effective porosity characterization model with variable T₂ cutoff of different lithofacies is established. Third, through comparison of multi-state T₁-T₂ NMR experiments, and considering the NMR logging responses, the positions of movable oil, bound oil, capillary bound water, asphalt and clay bound water of three lithofacies are revealed, and the shale oil occurrence identification chart is formed. According to the characterization results of lithofacies, effective porosity and movable oil porosity, together with the fluid production profiles of key wells, it is clarified that the interbedding of felsic lithofacies and clayey mixed lithofacies forms a favorable lithofacies combination in the Fengcheng formation. The research provides technical support for the experimental analysis of other continental shale oil reservoirs in China, and contributes a reference for shale oil reservoir evaluation.

Horizontal wells are widely used in the development of shale oil reservoirs. Due to the presence of thin interlayers in and significant anisotropy of the reservoir, there is an obvious difference between the acoustic slowness measured in horizontal wells and that measured in vertical wells, which seriously affects the interpretation accuracy of horizontal wells. In this paper, the four-component rotation technique is applied to process dipole array acoustic data for correcting shear-wave anisotropy. The slow shear-wave slowness obtained by this method is difficult to be accurately extracted due to serious dispersion effect. To solve this problem, a functional relationship between shear-wave anisotropy ratio and clay mineral content is established through analyzing horizontal well logging data of typical shale oil reservoirs in different basins, and a transformation relationship between the anisotropy ratios of compressional wave and shear wave is defined by using the core experimental data of these reservoirs. In practical processing, the anisotropy ratios of compressional- and shear-waves are obtained based on the clay mineral content. By combining the fast compressional-wave and shear-wave slowness values extracted from the acoustic logging data, the measured acoustic anisotropy of horizontal well is corrected. This correction method has been used to the actual horizontal well measurements in different basins, suggesting that the corrected acoustic slowness well agrees with the measured value of adjacent vertical well. The porosity calculated by the corrected acoustic slowness is basically consistent with the porosity calculated from the density logging. The results indicate that the proposed correction method is effective, and the corrected acoustic slowness can be used for calculating reservoir and engineering evaluation parameters for shale oil.