To reveal the energy transfer mechanism of water injection and the dynamic response characteristics of pore pressure in tight sandstone reservoirs, and to clarify the influence of lithology, injection pressure, and injection method on the energy enhancement effect of water injection, a high-pressure energy injection and response testing system and nuclear magnetic resonance (NMR) testing technology were used to conduct systematic water injection energy enhancement experiments on three rock types: mudstone, sandstone, and naturally fractured sandstone. Combined with pressure dynamic monitoring and pore structure evolution analysis, the pressure response characteristics and energy enhancement mechanism of rock samples under different experimental conditions were explored. The experimental results showed that the NMR T2 distribution of the three rock samples exhibited bimodal characteristics, corresponding to small pores (pore size < 1000 nm) and large pores/microcracks (pore size > 1000 nm), respectively. There were significant lithological differences in the evolution of pore structure during water injection, with a cumulative decrease of 7.2% in the proportion of large pores in mudstone and an increase of 9.3% in the proportion of large pores in sandstone with natural fracture development. There is a positive correlation between injection pressure and the energy enhancement effect. Under an injection pressure of 40 MPa, the pressure increment at the outlet end of sandstone with natural fracture development reaches 8.06 MPa, and the energy enhancement effect is 24% higher than that under the 30 MPa working condition, while the mudstone only increases by 15%. The energy enhancement effect of intermittent water injection is significantly better than that of depleted water injection, and the energy enhancement effects of the three rock samples are increased by 18.6%, 12.0%, and 6.9%, respectively. Overall, sandstone with natural fractures has the best energy enhancement effect, followed by sandstone, and mudstone has the worst. The connectivity of pores and the degree of fracture development are the core factors that dominate the water injection energy enhancement effect and pressure transmission efficiency. The research results can provide reliable experimental basis and theoretical support for optimizing water injection development plans, improving energy efficiency, and dynamically regulating stress fields in tight sandstone reservoirs.

During the energy storage fracturing process of tight sandstone reservoirs, the pre-injection of fracturing fluid is used to supplement the formation energy, and the physical properties of rocks change under hydration. To reveal the damage mechanism of hydration on tight sandstone, the tight sandstone surrounding the Daqing Changyuan in the northern part of the Songliao Basin was taken as the research object. Through indoor static hydration experiments, combined with scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), Nano-indentation experiments, and other methods, the evolution laws of rock micro-pore morphology, microfracture parameters, Young's modulus, hardness, and other mechanical indicators under different hydration durations and soaking pressures were systematically explored. The research results show that the water-rock interaction of acidic slick water fracturing fluid significantly changes the mineral composition and microstructure of mudstone and sandstone, controls the development of induced fractures, and degrades the micro-mechanical properties of rocks, with significant lithological differences. In terms of mineral evolution, the soaking time causes the clay minerals in mudstone to increase by up to 12.0%, while pressure causes the carbonate minerals in sandstone to decrease by up to 23.3%. In terms of induced fracture development, the induced fracture widths of sandstone and mudstone under 30 MPa of pressure increase by 122.4% and 85.7%, respectively. The fracture width of mudstone shows a trend of "increasing first and then decreasing" with time, while that of sandstone decreases monotonically. In terms of micro-mechanical properties, after soaking for 168 h, the Young's modulus of mudstone decreases by up to 66.9%, much higher than that of sandstone (29.5%), while the decrease in hardness of both is similar (58.3% and 59.8%); the mechanical parameters at the induced fractures are only 53.0% to 73.6% of those in the matrix area, confirming the influence of microstructural heterogeneity. This research provides a theoretical basis and data support for optimizing hydraulic fracturing parameters, evaluating wellbore stability, and predicting the long-term development performance in tight sandstone reservoirs.

Addressing the severe risk of artificial fractures causing vertical pressure channeling and subsequent water flooding during shale oil development in the Ordos Basin, this study investigates the overlapping development zone in Block Shun 269. Through laboratory rock mechanics experiments, the mechanical anisotropy of the overlapping layers was characterized. Utilizing actual production data, a 4D dynamic geomechanical model incorporating 21 years of injection-production history was established to reconstruct the pre-fracturing 3D in situ stress field. Based on this stress field model, a quantitative analysis was conducted on the evolution of injection-production stresses, the vertical superposition distance, the distribution of natural fractures, and the propagation patterns of hydraulic fractures across layers under various fracturing engineering parameters (including pumping rate, fluid viscosity, and perforation cluster, etc.). Research indicates that long-term injection-production disturbances caused the average minimum horizontal principal stress in the Chang 6 layer to decrease by 1.6 MPa, with partial "stress deficit zones" experiencing reductions as high as 3.5 MPa. This significantly weakened the stress shading capability between layers, resulting in the probability of fracturing cracks through the Chang 7 layer in the lower section increasing from 12% to 49%. The propagation of fracture height is jointly governed by geological and engineering factors, the weighting order is as follows: superposition distance > pumping rate > interlayer stress difference. A fracturing cross-layer risk assessment chart based on the coupling of geological and engineering factors has been established, proposing different anti-leakage and fracture control technical models for fracturing sections with different risk levels. Using this model to simulate fracturing in B horizontal wells, the simulation results were consistent with microseismic measurement data.

The complex interaction behavior between hydraulic fractures (HFs) and gravels in heterogeneous glutenite reservoirs makes the near-wellbore HF propagation geometries still unclear. In this study, fracturing experiments combined with CT scanning and rate step-down tests were conducted to analyze the effects of horizontal stress difference (Δσ), fluid viscosity (μ), gravel size (dg), and stiffness ratio of gravel to matrix (Eg/Em) on the pressure response and near-wellbore HF geometries. Importantly, a novel method was developed to quantitatively characterize the near-wellbore fracture tortuosity by introducing fitting coefficients Knw and m. Results indicate that there are four types of injection pressure responses, with type-3 and type-4 responses accounting for the highest proportion of 37.5% and 42.9% in slick-water and gel fracturing, respectively. With the increase of Δσ and μ or with the decrease of Eg/Em, the HF geometry shifts from the complex gravel-bypassing fracture network to a bi-wing main fracture penetrating gravels, and Eg/Em has the most significant impact on fracture complexity in glutenite. It is found that the interpreted values of Knw and m are 0.016∼2.772 and 0.384∼1.1, respectively, with them following a logarithmic correlation; as dg rises and μ decreases, Knw increases while m and equivalent fracture width reduce. Besides, a Knw-m plate is established to predict fracture tortuosity by incorporating the effects of gravel cementation, gravel size, and fluid viscosity. This investigation aims to give theoretical insights into HF-gravel interaction behavior and near-wellbore fracture geometry, providing guidance for fracturing optimization in glutenite reservoirs.

Aiming to investigate the unclear lower limit of microscopic pore mobilization during CO2 pre-fracturing in the shale oil reservoirs of the Ma51X well block, this study integrates high-temperature and high-pressure (110 degrees C 70 MPa) CO2 huff-n-puff with nuclear magnetic resonance (NMR) experiments. The results demonstrate the following: (1) under high-temperature (110 degrees C) and ultra-high-pressure (70 MPa) conditions, the lower limit of mobilizable pores for CO2 to displace reservoir crude oil reaches 1.7 similar to 2.2 nm; (2) the dominant mobilized pore range for CO2 is 5.1 similar to 38.5 nm, and macropore abundance directly dictates the macroscopic sweep coverage of CO2; (3) the modification effect of CO2 on pore structure is primarily concentrated within the mesopore-to-macropore systems, and with an increase in huff-n-puff cycles, crude oil in mesopores progressively migrates toward macropores; and (4) multi-cycle CO2 huff-n-puff exhibits a cyclic performance pattern characterized by dominance in the initial cycle and subsequent attenuation. This study precisely delineates the lower limit of mobilizable pores for crude oil in the shale oil reservoirs of the Ma51X well block, providing a robust theoretical foundation for the efficient development of this formation and analogous ultra-low permeability reservoirs.

Studies at hydraulic fracturing test sites (HFTSs) in North America and the Changqing oilfield, China, show that hydraulic fractures (HFs) commonly occur as closely spaced groups, or fracture swarms, with fracture numbers greatly exceeding perforation clusters. To investigate the formation mechanism and evolution of fracture swarms, continuous scratch testing and nanoindentation were used to characterize the mechanical heterogeneity associated with different lithologies, lithologic interfaces (LIs), and bedding planes (BPs). Hydraulic fracturing experiments were conducted on representative specimens from the Changqing HFTS using an improved small-scale true-triaxial system integrated with high-resolution CT scanning, high-frequency pressure monitoring, and acoustic emission (AE) monitoring. The results show that mechanical heterogeneity associated with LIs and BPs destabilizes cross-layer propagation of the main fracture and promotes fracture deflection, arrest, stepwise propagation, and secondary fracture re-initiation near weak planes, thereby favoring swarm development, whereas the homogeneous sandstone control specimen failed to generate such fracture patterns. When the interface contrast index Hi of a BP exceeds 0.1, the HF is more likely to be captured by the weak plane, which suppresses swarm development; when the Hi of an LI exceeds 0.1, local fracture deflection and secondary fracture re-initiation are more likely, whereas lower Hi favors direct crossing. Mechanistically, when weak planes satisfy the activation condition (Iact,i ≥ 1) but not the re-initiation condition (Ire,i < 1), fracture propagation is limited to local slip or minor deflection; when both conditions are satisfied (Iact,i ≥ 1 and Ire,i ≥ 1), secondary fractures are more likely to form and evolve into swarms. Main fractures exhibit larger apertures than secondary fractures, accompanied by alternating pressure peaks and troughs and AE signatures marked by increased event numbers, shear-event enrichment near weak planes, and sustained multipeak energy release. These findings provide new experimental insights into fracture swarm formation in shale reservoirs.

The complex propagation behavior of hydraulic fractures (HFs) in strongly heterogeneous conglomerate reservoirs poses significant challenges for effective reservoir stimulation. In particular, the interaction between fractures and gravel-induced heterogeneity often leads to highly tortuous fracture networks and uneven stimulation efficiency. To address this issue, a series of laboratory true triaxial hydraulic fracturing experiments were conducted on artificially prepared conglomerate specimens with controlled gravel size and distribution. A quantitative evaluation index, termed the Fracture Complexity Index (FCI), was proposed to characterize the tortuosity and complexity of fracture networks by integrating multiple geological and engineering factors. The effects of cluster spacing and fracturing fluid viscosity on multi-fracture propagation behavior were systematically investigated. The results show that increasing cluster spacing enhances inter-fracture interaction and promotes fracture tortuosity, while lower fluid viscosity facilitates fracture branching but may limit effective propagation distance due to energy dissipation. To further quantify the trade-off between fracture complexity and propagation extent, a dimensionless fracture length was introduced and combined with FCI to establish a fracture morphology evaluation framework. This framework enables the classification of fracture patterns and reveals the coupling relationship between engineering parameters and fracture geometry. The findings provide new insights into the mechanisms of fracture propagation in conglomerate reservoirs and offer a quantitative basis for optimizing fracturing design, particularly in balancing fracture complexity and effective stimulation range in strongly heterogeneous formations.

A critical strategy for shale reservoir development is the comprehensive reservoir evaluation and the fine division of fracturing grades. However, the diversity of evaluation parameters limits hydraulic fracturing optimization. Therefore, we propose an adaptive-category-gaussian-mixture-model (AC-GMM) based on a geology engineering framework, combining reservoir quality (RQ) and completion quality (CQ) to classify the composite quality index (CQI). The classification serves as the basis for an intelligent algorithm developed for fracturing design. Taking three typical wells from the Lucaogou Formation in the Junggar Basin in China as examples the following research results are summarized. First, the AC-GMM model can finely identify the fracturing grades, achieving a conformity rate of over 90 % with the field production data. Second, the paper obtains three types of fracturing grades (I, II, III) and further refines them into four grades (I, II1, II2, III), the grade I considers both high RQ and CQ, while grade II only regards the better of the double quality, and prioritizes the better CQ. Third, the intelligent algorithm groups similar qualities into the same stage, achieving up to 96 % intra-stage homogeneity, significantly enhancing hydraulic fracturing efficiency for long horizontal wells. Our work provides a data-driven framework for optimizing multi-stage fracturing designs in shale reservoirs.

An integrated non-planar three-dimensional (3D) fracture propagation and proppant transport model is developed, capable of simulating key physical behaviors in heterogeneous in situ stress fields, including fracture propagation, deflection, intersection, coalescence, and proppant transport, settling, and bridging. After validating the model reliability with true triaxial hydraulic fracturing laboratory experiments and numerical simulations of non-planar fracture propagation, the proposed model is employed to analyze the impact of in situ stress field heterogeneity on fracture initiation and propagation pressures, non-planar propagation paths, fracture width, and proppant concentration distribution. The simulation results indicate that the principal stress orientation determines the final propagation direction of hydraulic fractures, while the horizontal stress difference affects the curving length required for non-planar fracture reorientation. Stress interactions induced by multi-fracture propagations not only lead to uneven growth but also non-planar geometries, as hydraulic fractures preferentially propagate along the paths of minimal energy dissipation. Proppant distribution is primarily governed by fracture geometry and width, with proppant concentrated near the wellbore where fracture width is greater. Deflected in situ stress fields promote non-planar fracture propagation, as well as intersection and merging, with larger stress deviation angles accelerating fracture deflection and coalescence. The sudden width variations and slurry convergence at fracture intersecting points significantly raise proppant concentration, potentially leading to premature proppant screen-out. Inter-cluster stress heterogeneity affects the simultaneous initiation and propagation of multiple fractures, while inter-well stress heterogeneity induces asymmetric fracture geometries and proppant concentration distribution. In multi-well pad fracturing, the evolution of 3D pressure and stress fields caused by production or injection from parent wells can strongly influence the preferential growth paths of fractures in new wells.

Discontinuities such as lithology interfaces (LIs) and bedding planes (BPs) significantly complicate the mechanisms of hydraulic fracture (HF) propagation in multi-lithology and multi-layered shale reservoirs (MLSR). To investigate how these discontinuities influence HF growth, an improved small-scale true triaxial fracturing simulation system and CT scanning technique were employed to conduct fracturing experiments. Subsequently, a 3D numerical model based on the continuum-discontinuum element method (CDEM) was developed to explore the influence mechanisms of LIs, BPs, minimum horizontal principal stress (σh), and Young’s modulus (E) differences between lithologies, and combined factors on the evolution of HF parameters. The physical experiment results indicate that HF propagates through LIs and BPs in a “step-like” pattern. The HF morphology takes the shape of a “╫” or “╪”, penetrating, offsetting, or terminating at LIs or BPs with a narrow aperture. The numerical simulation shows that when HFs intersect with LIs and BPs, shear failure is dominant. The shear sliding along interfaces causes stress release at the fracture tip, resulting in discontinuities at the fracture front. The effect of σh on HF growth is more significant than that of E. Lithologies with high σh form a pressure barrier, while E indirectly slows the rate of HF growth by influencing the rock stiffness and aperture. HF length extension is more favorable in lithologies with low σh. HFs are more prone to elastic deformation in soft formations, resulting in an uneven and slower extension rate. The tensile-induced stress increases in high E, leading to stress concentration at the LIs, which promotes HF to penetrate the LIs. Furthermore, the elastic deformation of low E contributes to less significant stress concentration, which restricts HF growth. BPs with low σh are less likely to capture HFs, merely delaying the propagation of stress. The findings are expected to provide theoretical support for controlling HF growth during hydraulic fracturing.

To understand the effects of laminar structure on fracture propagation and proppant transportation intuitively, an improved true triaxial fracturing device with a proppant pumping unit was used to carry out sand-laden fracturing on shale oil reservoir samples with multiple lithological-combination and different laminar structures. Based on high-precision CT scanning technology and acoustic emission (AE) monitoring technology, the propagation mechanism of hydraulic fractures (HFs) and proppant transportation characteristics were analyzed, and the critical condition for lamina slip was proposed. The results show that laminas with initial width tend to be activated by fracturing fluid, resulting in diversion or offset. Closed laminas tend to be penetrated by HFs and are hardly activated by fracturing fluid. Rock with dense initial width laminas tends to form “#” shaped fractures interwoven with activated laminas and vertical fractures. In contrast, rock with closed laminas tends to form simple fractures dominated by vertical HFs. The width of HFs varies greatly from the perforation layer to the neighboring layer. As the difference in tensile strength between the interlayer and the perforated layer increases, the degree of decline in HF width significantly increases. Intensive AE activity was monitored at the intersection of vertical HFs and activated laminas, indicating that decreased fracture width causes proppants to bridge and block at the diversion and offset. Therefore, most proppants are filled in wide fractures near perforation, blocking the diversion and offset; there is almost no proppant in activated laminas. Reducing proppant diameter is conducive to placing the proppant in the activated laminas and interlayer HFs. Compared with placing 200 mesh and 120/140 mesh with similar fracture morphology samples, the proppant placement volume ratio of 400 mesh proppant placing samples increased by 7

Based on the Low Frequency Distributed Acoustic Sensing(LF-DAS)fiber optic monitoring and downhole hawk-eye imaging,the fluid and sand distribution and perforation erosion of all clusters during hydraulic fracturing were evaluated,and then a fully coupled wellbore-perforation-fracture numerical model was established to simulate the whole process of sand-carrying fluid migration and analyze key influencing factors.The proppant and fracturing fluid exhibit divergent flow pathways during multi-staged,multi-cluster fracturing in horizontal wells,resulting in significant heterogeneity in the fluid-proppant distribution among clusters.Perforation erosion is prevalent,and perforation erosion and sand inflow ratio have phase bias.The trajectory of proppant transport is controlled by the combined effects of inertia of particle migration and gravity settlement.The inertial effect is dominant at the wellbore heel,where the fluid flow rate is high,hindering particles turning into perforations and causing uneven sand distribution among clusters.The gravity settlement is more pronounced toward the wellbore toe,where the fluid flow rate is low,leading to enhanced phase-bias of slurry distribution and perforation erosion.Increasing the pumping rate reduces the influence of gravity settlement,mitigating the phase bias of sand inflow and perforation erosion.However,the large pumping rate limits the sand inflow efficiency near the heel clusters,and more proppants accumulate towards the toe clusters.High-viscosity fluids improve particle suspension,achieving more uniform proppant placement within wellbore and fractures.Larger particle sizes exacerbate sand inflow differences among clusters and perforations,limiting the proppant placement range within fractures.

The glutenite reservoir is strongly heterogeneous due to the random distribution of gravels, making it challenging to perform hydraulic fracturing effectively. To solve this issue, it is essential to study interaction behavior between hydraulic fractures (HFs) and gravels. A coupled hydro-mechanical model is proposed for HF propagation in glutenite using a grain-based discrete element method. This paper first investigates the dynamic evolution of HFs in glutenite, then analyzes the influences of various factors such as horizontal stress difference (Δσ), minimum horizontal stress (σh), gravel content (Vg), gravel size (dg), and stiffness ratio of gravel to matrix (Rs) on HF propagation geometries. Results show that penetrating the gravel is the primary HF-gravel interaction behavior, which follows sequential and staggered initiation modes. Bypassing the gravel is the secondary behavior, which obeys the sequential initiation mode and occurs when the orientation of the gravel boundary is inclined to the maximum horizontal stress (σH). An offset along the gravel boundary is usually formed while penetrating gravels, and the offsets may cause fracture widths to decrease by 37.8%–84.4%. Even if stress dominates the direction of HF propagation, HFs still tend to deflect within gravels. The deviation angle from σH decreases with rising Δσ and increases with the increase of dg and Rs. Additionally, intra-gravel shear HFs (IGS-HFs) are prone to be generated in coarse-grained glutenite under high Δσ, while more gravel-bypassing shear HFs (GBS-HFs) tend to be created in argillaceous glutenite with high Rs than in sandy glutenite with low Rs. The findings above prompt the emergence of a novel HF propagation pattern in glutenite, which helps to understand the real HF geometries and to provide theoretical guidance for treatments in the field.

The hydraulic fracturing experiments were conducted in the laboratory under true triaxial condition.Based on acoustic emission localization and acoustic emission characteristic parameters,the process of crack propagation in hydraulic fracturing was studied.The results showed that:(1)According to acoustic emission(AE)characteristics,shale hydraulic fracturing process can be divided into three stages:the initial stage,main fracture stage,and volumetric fracture stage.(2)In the initial stage,the pressure is in an upward phase,with a relatively small number of acoustic emissions and large b-values,mainly consisting of compressive and tensile cracks with low frequency,forming dispersed small cracks inside the rock.Before reaching the peak pressure,the cracks will gradually form a main fracture.(3)In the main fracture stage,as the pressure increases until the reservoir fracture pressure is reached,the acoustic emission rate sharply increases,resulting in a large number of high-energy acoustic emission events.The b-value decreases,and the acoustic emission frequency is higher,forming a tensile type main fracture closed to the wellbore hole.(4)In the stage of volumetric fracture,although the pressure significantly decreases,a large number of micro cracks still occur inside the samples.The fractures mainly propagate in a dispersed manner along the main fracture and form a complex network of volumetric fractures.During this stage,the acoustic emission b value is relatively high,with a large number of acoustic emissions of shear type fractures.(5)The AE characteristics of hydraulic fracturing in the laboratory are consistent with the microseismic monitoring results of on-site hydraulic fracturing.After on-site hydraulic fracturing,a large number of microseismic events will also occur during the well closed stage.The results of this study have important guiding significance for on-site hydraulic fracturing.

Multilayered shale reservoirs typically contain numerous mechanically weak bedding planes (BPs), which strongly influence the vertical propagation of hydraulic fractures (HFs). However, the mechanisms governing HF vertical propagation and the dynamic growth behavior of BPs in multilayered shale reservoirs remain poorly understood. To address this issue, this study develops a three-dimensional (3D) fracture propagation model that integrates BP slip and fluid leakoff. HF propagation is simulated using a planar 3D model, while BP slip is characterized by a lumped pseudo-3D model. The accuracy of the 3D fracture model is validated with an extended finite element model. Subsequently, the effects of fluid viscosity and interlayer stress differences on HF vertical propagation and BP slip are systematically analyzed. Numerical results reveal that HF height and width increase with higher fluid viscosity, while HF widths become discontinuous when crossing BPs. A greater interlayer stress difference leads to a more pronounced variation in HF width on both sides of the BP. Low-viscosity fluids enhance BP slip, though the BP sliding zone length generally remains below 1 m. In contrast, fracturing with high-viscosity fluids overcomes stress constraints on HF height, effectively increasing vertical stimulation.

Outcrop coal samples from the Shizhuang South Block of the Qinshui Basin, Shanxi Province, China, were subjected to true triaxial hydraulic fracturing experiments to simulate frature propagation. Combined with CT scanning and three-dimensional fracture reconstruction, the study examined fracture propagation patterns and bedding activation behaviors under variable pumping-rate fracturing in coal reservoirs. Results indicate that the variable pumping-rate fracturing technique effectively overcomes the strong trapping effect of coal bedding. Micro-fractures are initiated at multiple weak points along bedding planes, leading to multi-point fracture initiation and competitive propagation of fractures toward the far field, thereby generating a more complex three-dimensional fracture network. The geometry and aperture of the induced fracture network are primarily controlled by the ramp-up rate of injection flowrate. A gradual ramp-up favors the development of a more complex fracture network, though at the expense of lower breakdown pressure, insufficient initiation, and narrower apertures. In contrast, a rapid ramp-up produces wider fractures and larger propped lengths, but results in more pronounced aperture fluctuations. For coal reservoirs with relatively high rock strength, a moderately higher ramp-up rate is recommended to avoid excessively narrow fractures and potential proppant bridging. Different coal lithotypes necessitate tailored ramp-up strategies to optimize fracture morphology and stimulation effectiveness.

This study investigates the effects of CO2–water–rock interactions on shale oil reservoirs, specifically focusing on the mineral dissolution and pore structure alterations in shale samples from the second section of the Permian Fengcheng Formation in the Mahu Depression, Junggar Basin. Core soaking experiments were conducted under high-temperature and high-pressure conditions to simulate reservoir environments. Mineral evolution, ion migration, and microstructural changes were qualitatively and quantitatively analyzed using X-ray Diffraction (XRD), Inductively Coupled Plasma (ICP) spectroscopy, and Scanning Electron Microscopy (SEM). The findings indicate that CO2-induced mineral dissolution follows a distinct sequence: calcite > dolomite > potassium feldspar > sodium feldspar, which is directly reflected in the concentration of ions (Ca2+ > Mg2+ > K+ > Na+) in the solution. The dissolution rate and pore structure enhancement are significantly influenced by lamina density, with dolomitic rocks with high lamina density showing greater dissolution and porosity increase, and the lamina area greater than the matrix area. This study demonstrates that the dynamic changes of rock minerals are the core mechanism for controlling the pore structure of reservoirs, showing how CO2–water–rock reaction enhances the porosity and connectivity of shale reservoirs, thereby improving oil recovery potential.

Horizontal well multi-stage fracturing is the primary technology for deep shale gas development, but dense multi-cluster fractures are prone to non-uniform initiation and propagation, requiring real-time monitoring and interpretation techniques to adjust fracturing parameters. Although high-frequency water hammer pressure-monitoring technology shows diagnostic potential, the correlation mechanism between pressure response characteristics and multi-cluster fracture morphology remains unclear. This study utilized outcrop rock samples from the Longmaxi Formation shale to construct a long-injection-tube pipeline system and a 1 kHz high-frequency pressure acquisition system. Through a true triaxial fracturing simulation test system, it systematically investigated the effects of flow rate (50–180 mL/min) and fracturing fluid viscosity (3–15 mPa·s) on water hammer signal characteristics and fracture morphology. The results reveal that when the flow rate rose from 50 mL/min to 180 mL/min, the initiation efficiency of transverse fractures significantly improved, artificial fractures more easily broke through bedding plane limitations, and fracture height propagation became more complete. When the fracturing fluid viscosity increased from 3–5 mPa·s to 12–15 mPa·s, fracture height propagation and initiation efficiency significantly improved, but fewer bedding plane fractures were activated. The geometric complexity of fractures positively correlated with the water hammer decay rate. This research demonstrates a link between water hammer signal features and downhole fracture morphology, giving a theoretical basis for field fracturing diagnostics.

Continental interbedded shale oil reservoirs generally exhibit obvious composite layer effect, which is characterized by multilayers of various lithologies, dense laminas, and lithologic interfaces. In such formations, the behavior of hydraulic fracture (HF) height growth is still unclear. In this study, we used a 3D discrete element method (DEM) based on fracturing model to explore the composite layer effect on HF height- growth behavior. The model considered innovatively the rock matrix as transversely isotropic material due to the presence of dense laminas. Model validation was achieved through laboratory- scale fracturing tests on shale specimens featuring dense laminas. Computed tomography (CT) scanning was used to observe fracture morphology before and after the experiment. The numerical results showed high consistency with experimental observations in terms of fracture initiation, propagation, and deflection at laminated interfaces, confirming the model's reliability. Moreover, influence factors of dense laminas, interlayer stress difference, barrier layer thickness, pumping rate, and fluid viscosity were investigated in detail. Finally, the results demonstrate that as the interlayer stress difference increases or the barrier layer becomes thicker, the composite layer effect becomes more pronounced, making it increasingly difficult for an HF to penetrate these interlayer boundaries. Additionally, dense laminas intensify the containment effect of the composite layer effect on HF height propagation. As lamina permeability increases or strength decreases, the containment on HF height propagation is further intensified. Ultimately, it was also observed that interbedded shale oil reservoirs influenced under the composite layer effect, adjusting key fracturing parameters, such as the combination of pumping rate and fracturing fluid viscosity, can alter the propagation of HF height- growth behavior. Moreover, recommendations are provided for the optimal pumping rate and viscosity under different reservoir conditions. This study enhances the understanding of the HF height- propagation mechanism in interbedded shale oil reservoir and also offers new insights for controlling HF height in practical fracturing operations.

Bedding planes (BPs) are widely presented in multilayered shale oil/gas reservoirs and significantly affect propagation of hydraulic fractures (HFs) during hydraulic fracturing treatment. BPs may undergo slip deformation and the created sliding zone on BP would impede HF propagation by leaking injected fluid and reducing fracture width. A lumped model characterizing size and slip extent of the BP sliding zone was developed in this study and incorporated into a planar 3D HF model for investigation of how HF propagates in the presence of BP sliding zone. The model accuracy on sliding zone size and slip magnitude is verified through comparison to extended finite element results, and the condition is provided in that the accuracy is not strongly affected by the mesh size of the HF. A parametric study was performed for the investigation of the influences of key geological and mechanical factors on HF propagation and BP slip. Numerical results revealed that the interlayer stress difference is a critical factor controlling HF vertical propagation and the size of the BP sliding zone depends on both the vertical stress difference and the coefficient of friction on BP. The maximum sliding distance, generally less than 4 m, slightly increases with the vertical stress difference, and it varies in between 0.7 and 1.0 m when the vertical stress difference exceeds 6 MPa. As the coefficient of BP friction increases from 0.4 to 0.8, the area of BP sliding zone decreases by 40 %, and the maximum sliding distance decreases by 65 %. BP permeability has minimal impact on BP slip and sliding zone shape. Low-viscosity fluids promote BP slip, while high-viscosity fluids help overcome stress confinement on HF height growth, thereby quenching the growth of BP sliding zone.