Interbedded shale oil reservoirs are characterized by tight formations and strong heterogeneity, which present significant challenges for efficient development. To investigate effective enhanced oil recovery (EOR) technologies suitable for such reservoirs, a typical interbedded shale core was used as the research object, we innovatively propose a systematic study from physical property analysis to parallel comparison of recovery rate changes under two different enhanced recovery technologies. First, a suite of characterization techniques, including casting thin sections, scanning electron microscopy (SEM), and rock mechanics testing, was employed to systematically evaluate the microscopic pore structure, physical properties, and mechanical characteristics of the cores, providing fundamental parameters for subsequent experiments. Thereafter, parallel core experiments were conducted to systematically assess and compare the EOR performance of CO2-water alternating huff-n-puff and pressure-driven imbibition water flooding. The experimental results indicate that interbedded shale reservoirs exhibit a dense structure, poor fluid mobility, and relatively strong pore connectivity. In the CO2-water alternating huff-n-puff experiments, both recovery factor and injection pressure increased with soaking time, achieving a recovery factor of 23.49%. In contrast, pressure-driven imbibition water flooding experiments conducted on another set of cores with similar properties resulted in a markedly higher recovery factor of 31.7%. Comparative analysis suggests that pressure-driven imbibition water flooding has greater potential to enhance oil recovery in interbedded shale oil reservoirs. This study provides a theoretical foundation and technical support for the efficient, sustainable, and low-carbon development of interbedded shale oil reservoirs.

Summary In the research on hydraulic fracturing network evolution in fractured shale reservoirs, there are several key issues. For instance, it is generally assumed simplistically that the interfacial frictional properties of natural fractures (NFs) govern the propagation direction of fractures, overlooking that real rocks are typically aggregates of different minerals and may exhibit a certain degree of cementation. To address the comparative analysis of two types of fractures within the same parameter framework in this study, we established a 2D hydraulic fracturing model based on the extended finite element method, developed a new intersection criterion for cemented fractures, elucidated the mechanism of the fracture deflection phenomenon, and addressed the inherent limitations of this method in handling fracture intersections. Subsequently, the numerical model was used to analyze how different types of NF clusters influence the fracture network morphology. The results show that a small horizontal stress difference, high approaching angle, and small fracture interface friction coefficient are more conducive to the formation of fracturing networks in frictional NF groups. Cemented NF groups require small cementation strength, high approach angles, and higher injection rates to form complex fracture networks, which balance differences in energy release rates between the upper and lower halves of NFs. Additionally, the more concentrated the distribution of NFs, the more likely they are to intersect with hydraulic fracture (HF) branches and form complex fracture networks. When the geometric characteristics and spatial distribution of NFs are consistent, the fracturing networks formed in formations with frictional NFs exhibit significantly higher complexity than those in cemented formations. Stress interference between branched fractures not only alters their mutual propagation trajectories but also affects fracture opening conditions, and the distribution position of NFs exerts a critical impact on fracture network formation. This study provides theoretical support for optimizing fracture network stimulation in hydraulic fracturing operations for fractured shale reservoirs.

The Mugan Syncline in northeastern Yunnan represents a significant relay area for shale gas exploration in China. However, due to the combined effects of tectonic superimposition and sedimentary heterogeneity, systematic investigations into the intervals hosting high-quality shales and the coupling relationships among microfacies, reservoir quality, and gas-bearing properties remain insufficient. The core objective of this study is to establish a high-resolution microfacies framework and to quantitatively elucidate the multi-parameter coupling mechanisms by which microfacies control organic matter enrichment, pore development, and gas storage capacity in this structurally complex, basin-margin setting. By integrating core observations, thin-section petrography, scanning electron microscopy (SEM), whole-rock X-ray diffraction (XRD), total organic carbon (TOC) analysis, trace-element geochemistry, and well-logging data, we establish a stratigraphic subdivision and cross-well correlation framework for the Wufeng (WF) Formation and the Long11 submember. Furthermore, a lithofacies (microfacies) identification scheme based on a "TOC + siliceous (quartz + feldspar)-carbonate-clay" ternary classification is applied. The results reveal the following: (1) Based on the locally developed erosional contact at the boundary between the Longmaxi (LMX) Formation and the underlying Guanyinqiao Formation, the WF Formation in the study area can be subdivided into two submembers, whereas the Long11 submember comprises four sublayers. The thicknesses of the Long11-1 through Long11-3 sublayers range from 21.42 to 25.47 m, exhibiting a subtle northward-thickening trend. In contrast, the Long11-4 sublayer displays a relatively uniform thickness and high stratigraphic continuity of shale deposition. (2) Based on TOC content and ternary mineral composition, the shales are classified into four lithofacies associations and sixteen lithofacies subtypes. The main favorable microfacies assemblages are identified as high-carbon siliceous/calcareous shale (C-1), high-carbon calcareous/siliceous mixed shale (M-1), carbon-rich argillaceous siliceous shale (S-3), and high-carbon siliceous/argillaceous mixed shale (M-2). (3) High-quality shales (TOC > 2%) are predominantly developed in the upper member of the WF Formation and in the Long11-1 through Long11-4 sublayers. Their lateral distribution is markedly controlled by variations in paleotopography and terrigenous sediment supply. (4) The microfacies exert a synergistic control on shale gas enrichment. Carbon-rich argillaceous siliceous and siliceous-rich microfacies generally correspond to higher TOC contents and better-developed organic-matter pores. Siliceous-rich and mixed microfacies exert a positive influence on pore preservation and rock brittleness. The gas-bearing properties are influenced not only by TOC content but also by pore structure, mineral composition, and tectonic preservation conditions. The findings of this study provide a scientific basis for the prediction of shale gas sweet spots and the optimization of target intervals in the Mugan Syncline and other structurally and sedimentologically complex regions of northeastern Yunnan.

For further understanding of water spontaneous imbibition in continental shales, the pore structure and pore-size distribution of Chang 7 shale samples were investigated by scanning electron microscope, high-pressure mercury injection, and nuclear magnetic resonance. The results showed that micropores and small pores were the main types. Next, the vertical spontaneous imbibition experiments were conducted to reveal the imbibition process and investigate the temporal variation law on core-scale and pore-scale levels. The results indicated that the process could be divided into three stages. The first stage was the main period for the imbibition amount rising and accounted for more than 86%. The imbibition water saturation with a shorter core was higher, and was the largest in micropores. Additionally, the imbibition ripple rate at the core-scale and pore-scale levels implied that the imbibition front broke through the obstruction point to flow into the smaller pores or other paths conducive to imbibition. It fluctuated greatly in the first stage to show that there were massively stronger imbibition capacity flow paths, and the shale samples were strongly heterogeneous to a certain extent.

The development of natural fractures can easily lead to horizontal wellbore instability caused by stress concentration after drilling in shale reservoirs, which is not conducive to the safe development of shale gas, but how different natural fractures impact the horizontal wellbore stability in shale reservoirs is still unclear. Therefore, the effect of single straight, intersecting, and T-shaped natural fractures on horizontal wellbore stability in shale reservoirs is studied. Then a stress distribution model around the horizontal wellbore in shale reservoirs considering natural fractures is established based on linear elasticity theory, the stress distribution around horizontal wellbores in shale reservoirs with single straight, intersecting, and T-shaped natural fractures is acquired through the finite element method (FEM), and the effect of different natural fractures on horizontal wellbore stability is analyzed finally. Results show that among three types of natural fractures, intersecting natural fractures relieve the maximum stress of 1.676 × 106Pa, and the horizontal wellbore is the most stable; T-shaped natural fractures have the largest effect on total stress around the horizontal wellbore, which is the largest and can reach 68.105 × 106Pa, which makes the wellbore the most unstable; single straight natural fractures and intersecting natural fractures can cause the maximum circumferential stress on the wellbore wall respectively in the two directions of the maximum horizontal principal stress and the vertical principal stress, and wellbore wall is prone to compression and tensile failure respectively; circumferential stress and total stress around horizontal wellbore are the largest in the direction of the maximum horizontal principal stress, the wellbore is the most unstable. This work will be helpful for a more reliable assessment of borehole instability and benefit the drilling design in shale reservoirs with single straight, intersecting, and T-shaped natural fractures.

Abstract Huff-and-puff enhanced oil recovery (HnP-EOR) has become an important means of developing unconventional oil reservoirs (UORs) in China. However, oil recovery performance varies across different injectants and production blocks, posing challenges for the large-scale promotion and process optimization of this technology. To further advance the application of HnP-EOR technology in UORs, this paper systematically reviews the major injectants currently in use along with their research status in oil-displacement mechanisms, influencing factors, and engineering applications. The results show that the technically recoverable UOR resources in China are on the order of several billion tons, yet their matrix pore sizes are at the micro- to nanoscale. The main HnP-EOR injectants include single-phase liquids and gases, and multiphase fluid synergy, with water and CO2 the most prevalent. A unified understanding has been achieved regarding the microscopic interaction mechanism of each single-phase injectant; however, in terms of pore-scale utilization, the utilization laws of gas have been basically clarified while those of water still need to be explored. The influence laws of some parameters on HnP-EOR have been basically clarified, such as fracture density, injection pressure, well shut-in time, and cycle number. However, the dominant microscopic interaction mechanism and the weight ranking of influencing factors under different injectants, reservoir properties, and operational conditions remain unclear. Multiphase fluid synergy and pressure-driven injection are novel HnP-EOR technologies that have been developed rapidly in recent years. Their excellent performance has been preliminarily verified in laboratory experiments, and further in-depth research is urgently needed. The incomplete evaluation system for HnP-EOR has become an important obstacle for its engineering applications; therefore, a ″five-element method″ evaluation system is proposed in this work. Lastly, the challenges and future development directions of the HnP-EOR technology in UORs in China are comprehensively summarized from seven perspectives.

In intermittent - producing gas wells, there exists an interaction between the wellbore and the formation during the opening and closing periods. Nevertheless, the current multiphase flow models for wellbore - formation coupling are not yet perfect. In this paper, a mathematical model of unsteady wellbore flow is established based on the principles of mass conservation and momentum conservation. This model is capable of simultaneously describing the flow, holdup, and gas - liquid transfer in both the tubing and the casing annulus. The numerical method is employed to solve the partial differential equation. Specifically, the finite - difference method is utilized to discretize the mathematical model on the grid system, thereby forming the corresponding fully implicit difference equations, which are ensured to meet the requirements of compatibility, convergence, and stability. To verify the accuracy of the model, a simulation calculation is carried out on Well Su 38 - X using the new model. The simulation results demonstrate that the calculation results of the new model can accurately reflect the variations in bottom - hole pressure and wellhead pressure during the well opening and closing periods. It is revealed that the removal of fluid decreases the water saturation in the formation near the well bottom, which is beneficial for enhancing the gas - phase permeability and thus increasing the gas - well production.

To clarify how shale-reservoir heterogeneity constrains hydraulic-fracturing effectiveness in complex structural areas, this study analyzes exploration well X in the Mugan–Shoushan area, Yunnan Province, using organic geochemistry, petrology and mineralogy, reservoir-property, and rock-mechanical data from the Wufeng–Longmaxi formations. The results show pronounced vertical engineering-geological differentiation. Average clay content decreases from 42% to 8%, Average carbonate minerals increase from 16% to 50%, and quartz is anomalously enriched in the Longyi 1-1 layer of the Longmaxi Formation (Longyi 1-1; 76%). The Longyi 1-3 layer of the Longmaxi Formation has the highest porosity (9.37%) but low matrix permeability (0.013–0.019 mD); the Longyi 1-2 layer of the Longmaxi Formation is highly brittle and tight; and the Longyi 1-4 layer of the Longmaxi Formation is highly ductile and water-rich. Accordingly, four engineering geological facies are defined: Type I, organic-rich, moderately brittle, and moderately ductile composite facies; Type II, organic-rich, highly brittle, tight, and strongly stress-sensitive facies; Type III, organic-poor, highly ductile, water-rich, and strongly water-sensitive facies; and Type IV, highly brittle, fracture-developed, and high-adsorption facies. Implications for fracturing are proposed for each facies, including mixed-fluid network stimulation, acid pretreatment with controlled flowback, interval avoidance, and coordinated stimulation with adjacent main reservoirs.

Huff-n-puff (HnP) is currently an important means to enhance the oil recovery of tight oil reservoirs. In this study, taking tight sedimentary tuff oil reservoirs in Santanghu Basin, China as an example, the oil production law, pore utilization characteristics, and influencing factors of water, N-2, CO2, N-2-water alternating, and CO2-water alternating HnP (WHP, NHP, CHP, NWAHP, CWAHP) are comprehensively studied. The results show that middle pores (MPs) are the main pore utilization interval for various HnP mediums. The recovery rates (RRs) of five rounds of WHP, NHP, and CHP are 39.32%, 44.45%, and 61.24%, with contribution rates (CRs) of MPs being 68.60%, 47.87%, and 56.00%. The RRs and CRs of various pores are closely related to their pore distribution and the oil recovery mechanism of the medium. Under the experimental conditions of this study, the RR of CHP does not have an obvious rock sample size effect, with sweep depth exceeding 1.25 cm in each round. The RR of CHP is positively correlated with injection pressure and shut-in time, and the injection exceeding the rock fracture fracturing and 300 min shut-in time are recommended. The RRs of six rounds of NWAHP and CWAHP are 51.98% and 62.75%, with CRs of MPs being 60.39% and 58.32%. The oil recovery effect (ORE) of NWAHP is better than that of their individual, while the ORE of CWAHP is better than that of WHP but close to that of CHP. The alternating sequence affects the stage RR of NWAHP and CWAHP. The NWAHP and CWAHP have great advantages in improving RR, reducing injection cost, and stabilizing production, and are expected to achieve rapid development.

The oil recovery of Lianchi tight oil reservoir Da’an Zhai section was lowly and development was difficult, then carried out the numerical simulation study of CO2 injection in Lianchi tight oil reservoir. Established the CO2 development numerical model of Lianchi oilfield (double pore model and compositional model) through combined the reservoir characteristics of Lianchi oilfield and fluid properties. Respectively predicted the increasing oil effect of three injection-production methods with displacement mode, CO2 huff and puff, cyclic huff and puff mode. Evaluated the development effect on the basis of CO2 oil draining rate and the increment of oil recovery. The results showed that, the development effect of cyclic huff and puff mode was best in three kinds of gas injection modes, the best time of well shut in was 3 months, the injection-production cycle of CO2 cyclic huff and puff was 4 years. At the same time, the optimal scheme of the gas injection was determined through comparative research, which provided the technical reference for the development of Lianchi oilfield for injection CO2.

Continental shale oil fracturing dynamics are governed by interactions between hydraulic fractures and pre-existing natural fractures. This study establishes a fluid–solid coupling model using globally embedded cohesive elements to simulate fracture propagation in naturally fractured reservoirs. Key factors affecting fracture network complexity were quantified: (1) Weakly cemented natural fractures (bond strength coefficient <0.5) promote 23% higher fracture tortuosity compared to strongly cemented formations. (2) Optimal horizontal stress differentials (Δσ = 8–10 MPa) balance fracture length (increased by 35–40%) and branching complexity. (3) Injection rate elevation from 0.06 to 0.132 m3/min enhances the stimulated volume by 90% through improved fracture dimensions. The findings provide mechanistic insights for optimizing fracture network complexity in shale reservoirs.

Under the geological conditions of sandstone reservoirs in the long 7 sections of Tiezhuizi block, with the increase in the depth of burial and the complexity of geological structure, it leads to the status quo of generally low production capacity of horizontal wells. In the face of this challenge, the optimisation of fracturing engineering desserts is particularly difficult. To cope with this challenge, this study is dedicated to finding a high-precision method for quantitative evaluation of reservoir engineering sweet spots. In this study, principal component analysis was adopted to comprehensively and meticulously analyse nine key engineering sweet spot factors, including core density, elastic modulus, Poisson's ratio, and perimeter pressure. The screening criteria of eigenvalue > 1 accurately identified 2 factors that mainly affect the engineering sweet spot. The cumulative explained variance of these two principal components reaches 91.199 %, which almost covers most of the information. By analysing the positive and negative correlations between the factor loading coefficients of these 2 principal components affecting the engineering sweet spot, these two principal components were identified as the damage resistance factor and the external confining stress factor, respectively. By analysing the rock number composite scores of the principal components, the specific locations of the dominant reservoirs were precisely located, and the dominant reservoirs were located at 2085-2095m, 2035-2045m, 1955-1965m, 1975-1985m and 2005-2015m. This result is more conducive to the realisation of the project, with high accuracy.

Outcrop shale and core sample studies have shown that natural fracture (NF) is a key factor influencing the productivity of shale oil and gas reservoirs. When hydraulic fracture (HF) intersects with NF, the stimulated reservoir volume (SRV) after fracturing can expand significantly due to the opening of pre-existing NF. As a result, production of oil and gas often exceeds expectations based solely on the matrix properties of low-porosity and low-permeability shales. While previous studies have laid a theoretical and experimental foundation for understanding fracture intersection behavior, most of them have focused on how experimental parameters influence fracture propagation patterns, with limited attention paid to the role of NF slip characteristics in determining intersection outcomes. To address this gap, we conducted HF–NF interaction experiments using outcrop shale from the Chang 7 Member of the Ordos Basin. A single HF was induced to intersect a pre-existing through-going NF within the rock sample. By systematically varying the approach angle, the distance between the injection point and the NF, the NF cementation strength, the confining pressure, and the injection rate, we investigated how slip behavior affects HF propagation paths. We further proposed threshold ranges of slip distance and slip rate under laboratory conditions that are associated with different HF–NF interaction outcomes. This study provides critical experimental evidence and mechanistic insights for improving fracture interaction theory, optimizing field fracturing designs, and building more accurate numerical models of fracture networks. It holds significant theoretical and practical value.

The shale oil reservoir in Block Y of the Ordos Basin exhibits low porosity and low permeability, yet it features distinct stratification and developed micro-fractures. During the development process using “horizontal wells + volume fracturing”, the differential in geostress exerts a certain influence on the initiation and propagation of fractures. This paper employs the Cohesive element simulation method to investigate the formation patterns of fracture networks in fractured formations. By prefabricating natural fractures, the study explores the impact of natural fractures on the direction of hydraulic fractures during the hydraulic fracturing process. The study considers the fracture initiation and propagation patterns as well as the interaction between hydraulic fractures and natural fractures under differential geostress conditions of 0 MPa, 1 MPa, and 5 MPa. The numerical simulation results reveal that the presence of natural fractures significantly affects the direction of hydraulic fractures, with the tip of the hydraulic fracture deflecting towards the natural fracture. The smaller the geostress difference, the more complex the fractures become with more branching fractures. Conversely, a larger geostress difference leads to the formation of a single double-wing fracture perpendicular to the minimum principal stress, resulting in a simpler fracture morphology. The pore pressure variation at the injection point generally experiences a rapid increase followed by a slight decrease, subsequently undergoing wavy changes. The occurrence of wavy pressure variations indicates the continuous generation of micro-fractures. The fracture width at the injection point generally exhibits an increasing trend followed by a decreasing trend. When the stress difference is 0 MPa, 1 MPa, and 5 MPa, the peak rupture pressures are 12.63 MPa, 13.42 MPa, and 18.33 MPa, respectively; the maximum crack openings are 0.797 cm, 0.779 cm, and 0.771 cm, respectively. The study on fracture initiation and propagation in shale reservoirs provides guidance for the field application of multi-cluster fracturing in horizontal well sections.

Fracturability evaluation is an important task before hydraulic fracturing, and machine learning (ML) methods have been applied to petroleum-related studies but have not been applied to fracturability evaluation. In this study, we present a novel fracturability evaluation workflow based on ML that focuses on the Chang 7 continental shale oil reservoirs in the Ordos Basin, aiming to generate a comprehensive fracturability index (KC) to guide the selection of sections and clusters in hydraulic fracturing. Owing to the lithological differences between continental shale oil reservoirs and shale reservoirs, brittleness-based fracturability evaluation methods are poorly adapted to the research area. Hence, we integrate geological sweet spots, brittleness, and difficulty in forming a complex fracture network in a reservoir. The typical factors influencing fracturability include oil saturation (SOG), porosity (POR), permeability (PERM), Young's modulus (YM), Poisson's ratio (PR), Mode-I fracture toughness (KIC), Mode-II fracture toughness (KIIC), and the horizontal stress difference coefficient (HSDC). Furthermore, the powerful nonlinear dimension reduction capability of kernel principal component analysis (KPCA) is used to integrate the main characteristics of each effect. To verify the adaptability of the KPCA-based method, the KC is compared with logging interpretations and microseismic events. Considering the substantial spatial correlation of logging data, a hybrid neural network [convolutional neural network (CNN)-multihead attention (MHA)-bidirectional long short-term memory neural network (BiLSTM)] is presented to simplify the complex intermediate computation procedure and directly use the logging data to predict the KC. The CNN excels at extracting local features, the MHA enables the model to focus more on task-relevant data, and the BiLSTM captures bidirectional dependencies with logging data. The experimental results show that the CNN-MHA-BiLSTM outperforms other neural networks on the testing set and can better handle data with hidden patterns.

Shale oil is a strategically important global resource, and its commercial extraction requires fracking to increase production. However, the impact of different fracture distributions on shale oil production is unclear. The application of hydraulic fracturing technology to horizontal wells has been demonstrated to alter the seepage mechanism within the reservoir, thereby improving the overall development efficiency. To this end, a production prediction model for multi-cluster fracturing of horizontal wells was constructed in this study using the finite element method. Through the variation of the number and distribution of hydraulic fractures, it was determined that augmenting the number of fracture clusters and reducing fracture spacing could substantially enhance shale oil production. Additionally, a comprehensive analysis of the production data was conducted to ascertain the fracture distribution patterns in the transverse direction (uniformly laid, dense at both ends, and dense in the middle) and the longitudinal direction (uniformly laid, spindle-type, and dumbbell-type). The findings indicate that in the transverse direction, dense fractures at both ends have the most significant impact on enhancing yield, followed by uniformly laid fractures, and dense fractures in the middle have a weaker impact; and in the longitudinal direction, the dumbbell type has the greatest impact on improving yield, followed by uniformly laid fractures, and the spindle type has a weaker impact. The comprehensive analyses indicate that the fracture combination of dense and dumbbell type at both ends can significantly enhance the production of shale oil in fracture modification operations, thereby providing a robust theoretical foundation for the optimization of fracture network in shale reservoirs.

Natural fractures in shale reservoirs are diverse in type and complex in morphology, posing a challenge to understanding the effect of different types of natural fractures on the mechanical behavior of hydraulic fractures in parallel and vertical direction of horizontal well planes. To address this issue, physical simulation experiments on large sized shale samples with prefabricated I-shaped, X-shaped, and T-shaped natural fractures were conducted by a true triaxial hydraulic fracturing system. And the initiation and propagation laws of hydraulic fracture under the effect of different types of natural fractures were investigated. Results show that the hydraulic fractures in shale reservoirs with I-shaped natural fractures exhibit symmetrical initiation, while the shale reservoirs with X-shaped and T-shaped natural fractures exhibit asymmetric initiation. Among these natural fractures, X-shaped natural fractures displayed the strongest inducing ability, and the secondary natural fracture in X-shaped natural fractures is significantly contributing to this effect. The induction ability of T-shaped natural fractures is followed by the X-shaped natural fractures, particularly concerning the induction ability of the main natural fracture in T-shaped natural fractures. And I-shaped natural fractures have the weakest induction ability. Additionally, the bedding played a crucial role in inhibiting hydraulic fracture propagation along the direction of vertical principal stress. The bedding in shale reservoirs with straight natural fractures has the strongest inhibitory effect on the hydraulic fractures propagation, followed by shale reservoirs with T-shaped natural fractures, and shale reservoirs with X-shaped natural fractures have the weakest inhibitory effect. The research results provide guidance for analyzing the fracturing effect of shale reservoirs with different types of natural fractures.

During the refracturing process in aging wells, fractures often propagate towards the cement sheath, leading to communication between the casing and the cement sheath, or between the cement sheath and the wellbore wall. This phenomenon makes it challenging to ensure the efficacy of fracturing stimulation. To tackle this issue, the extended finite element method was employed to develop a fracture propagation model that considers the integrity of cementing quality. The impacts of cement sheath thickness and fracture spacing on the external channeling flow of the fracturing fluid were further investigated. Based on quantitative evaluation data of cementing quality and fracturing design and construction data from the horizontal well refracturing test area in the Changqing Oilfield, data analysis methods were utilized to identify the primary controlling factors of channeling outside the horizontal well refracturing pipe. Subsequently, a prevention and control chart was formulated aimed at mitigating channeling outside repeated fracturing pipes. The results indicate that cementing quality and fracture spacing are the main controlling factors for channeling outside refractory pipes. Specifically, fracture sections with spacing less than 30 m and sound amplitudes exceeding 5 mV represent sufficient conditions for pipe channeling during horizontal well refracturing in the target area. Following the application of the pipe channeling prevention control chart, the segment loss rate at the refracturing site decreased by 5.2

The determination of rock mechanics parameters and in-situ stress during the development process of “horizontal well + volume fracturing” for shale oil reservoirs in Block Y of the Ordos Basin can provide a basis for fracturing schemes and production pressure difference design. Rock mechanics experiments are the most direct method for determining rock mechanics parameters. This article tested the in-situ stress of the Chang 7 shale oil reservoir in Block Y of the Ordos Basin through Kaiser acoustic emission experiments, calculated the static rock mechanics parameters of the block, and found that the vertical principal stress distribution of the Chang 7 section of the block is between 49.72 ~ 61.13 MPa, the maximum horizontal principal stress distribution is between 59.04 ~ 75.4 MPa, the minimum horizontal principal stress distribution is between 46.75 ~ 56.38 MPa, the horizontal stress difference is between 10.16 ~ 21.67 MPa, and the horizontal stress difference coefficient is between 0.21 ~ 0.42. The average maximum horizontal stress gradient is 2.534 MPa/100m, the average minimum horizontal stress gradient is 1.891 MPa/100m, and the average vertical stress gradient is 2.051 MPa/100m. In addition, dynamic rock mechanics parameters can be calculated using well logging curves, and a relationship model between dynamic and static rock mechanics can be established. Through calculation, the error can be obtained within 16%, which meets practical engineering requirements and can be applied in mining practice. The core experimental data is limited, discrete, and unable to reflect the trend of rock strength changes throughout the entire well section. By using logging curve data to predict rock strength parameters, continuous formation strength profiles can be obtained, providing important basis for later layer selection, section selection, and prediction of fracture direction.