Search Results (1,333)

With the frequent occurrence of stuck pipe incidents during the ultra-deep well drilling operation, the hydraulic-while-drilling (HWD) jar has become a critical component of the bottom hole assembly (BHA). However, during jarring operations for stuck pipe release, the drill string experiences severe vibrations induced by the impact loads from the jar, which significantly alter the stress state and dynamic response of the threaded connections—the structurally weakest elements—under cyclic dynamic loading, often leading to fracture failures. here, a thread failure incident of a hydraulic jar in an ultra-deep well in the Tarim Basin, Xinjiang, is investigated. A drill string dynamic impact model incorporating the actual three-dimensional wellbore trajectory is established to capture the time-history characteristics of multi-axial loads at the threaded connection during up and down jarring. Meanwhile, a three-dimensional finite element model of a double-shouldered threaded connection with helix angle is developed, and the stress distribution of the joint thread is analyzed on the boundary condition acquired from the time-history characteristics of multi-axial loads. Numerical results indicate that the axial compression induces local bending of the drill string during down jarring, resulting in significantly greater bending moment fluctuations than in up jarring and a correspondingly higher amplitude of circumferential acceleration at the thread location. Among all thread positions, the first thread root at the pin end consistently experiences the highest average stress and stress variation, rendering it most susceptible to fatigue failure. This study provides theoretical and practical insights for optimizing drill string design and enhancing the reliability of threaded connections in deep and ultra-deep well drilling. Full article

Hydraulic fracturing is a core stimulation technology for enhancing hydrocarbon production. However, it faces significant technical bottlenecks in unconventional reservoirs. These bottlenecks include poor adaptability to high-temperature and high-salinity environments, water-sensitive formation damage, and insufficient long-term fracture conductivity. Nanotechnology leverages unique properties of nanomaterials, such as surface effects, quantum size effects, and designability. Nanotechnology offers systematic solutions for optimizing fracturing fluids, enhancing proppant performance, and innovating waterless fracturing techniques. This review outlines the current status of fracturing technology, exploring the role of nanoparticles in improving fluid rheology, proppant strength, and interface regulation, and discusses future challenges. Studies show that nanomodified fracturing fluids can increase high-temperature viscosity retention by over 300%. Meanwhile, waterless fracturing reduces water consumption by 80%. Despite challenges in particle agglomeration and cost, nanotechnology demonstrates significant potential in boosting recovery and reducing environmental impact. Nanotechnology is positioned as a transformative technology for future unconventional resource development. Full article

During deep coalbed methane (CBM) drilling, wellbore stability is significantly influenced by the interaction between drilling fluid and coal rock. However, quantitative data on mechanical degradation under long-term high-temperature and high-pressure conditions are lacking. This study subjected coal cores to immersion in field-formula drilling fluid at 60 °C and 10.5 MPa for 0–30 days, followed by uniaxial and triaxial compression tests under confining pressures of 0/5/10/20 MPa. The fracture evolution was tracked using micro-indentation (µ-indentation), nuclear magnetic resonance (NMR), and scanning electron microscopy (SEM), establishing a relationship between water absorption and strength. The results indicate a sharp decline in mechanical parameters within the first 5 days, after which they stabilized. Uniaxial compressive strength decreased from 36.85 MPa to 22.0 MPa (−40%), elastic modulus from 1.93 GPa to 1.07 GPa (−44%), cohesion from 14.5 MPa to 5.9 MPa (−59%), and internal friction angle from 24.9° to 19.8° (−20%). Even under 20 MPa confining pressure after 30 days, the strength loss reached 43%. Water absorption increased from 6.1% to 7.9%, showing a linear negative correlation with strength, with the slope increasing from −171 MPa/% (no confining pressure) to −808 MPa/% (20 MPa confining pressure). The matrix elastic modulus remained stable at 3.5–3.9 GPa, and mineral composition remained unchanged, confirming that the degradation was due to hydraulic wedging and lubrication of fractures rather than matrix damage. These quantitative thresholds provide direct evidence for predicting wellbore stability in deep CBM drilling. Full article

High-pressure, high-volume fracturing in unconventional reservoirs often induces perforation erosion damage, endangering operational safety. This paper employs fluid–solid coupling theory to analyze the flow characteristics of fracturing fluid inside the casing during fracturing. Combined with strength theory, the stress distribution and variation law are investigated, revealing the mechanical mechanism of casing perforation erosion damage. The results indicate that the structural discontinuity at the entrance of the perforation tunnel causes an increase in fracturing-fluid velocity, and this is where the most severe erosion happens. The stress around the perforation is symmetrically distributed along the perforation axis. The casing inner wall experiences a combined tensile–compressive stress state, while non-perforated regions are under pure tensile stress, with the maximum amplitudes occurring in the 90° and 270° directions. Although the tensile and compressive stress do not exceed the material’s allowable stress, the shear stress exceeds the allowable shear stress, indicating that shear stress failure is likely to initiate at the perforation, inducing erosion. Moreover, under the impact of fracturing fluid, the contact forces at the first and second interfaces of the casing are unevenly distributed, reducing cement bonding capability and compromising casing integrity. The findings provide a theoretical basis for optimizing casing selection. Full article

Deep coalbed methane reservoirs must utilize hydraulic fracturing technology to create high-conductivity sand-filled fractures for economical development. However, the mechanism by which proppant embedment affects fracture width in coal rock is not yet clear. In this article, using the discrete element particle flow method, we have developed a numerical simulation model that can replicate the dynamic process of proppant embedment into the fracture surface. By tracking particle positions, we have accurately characterized the dynamic changes in fracture width and proppant embedment depth. The consistency between experimental measurements of average fracture width and numerical results demonstrates the reliability of our numerical model. Using this model, we analyzed the mechanisms by which different proppant particle sizes, number of layers, and closure stresses affect fracture width. The force among particles under different proppant embedment conditions and the induced stress field around the fracture were also studied. Numerical simulation results show that stress concentration formed by proppant embedment in the fracture surface leads to the generation of numerous induced micro-fractures. As the proppant grain size and closure stress increase, the stress concentration formed by proppant embedment in the fracture surface intensifies, and the variability in fracture width along the fracture length direction also increases. With more layers of proppant placement, the particles counteract some of the closure stress, thereby reducing the degree of proppant embedment around the fracture surface. Full article

Hydraulic fracturing is currently the main technical means to form complex fracture systems in shale gas development. To explore the influence of fracture dip, fracture length and fracture filling degree on the propagation of hydraulic fractures under complex fracture conditions, this paper establishes a 20 cm × 20 cm two-dimensional numerical model by inserting global cohesive elements and conducting triaxial hydraulic fracturing experiments to verify the model. The results show that the fracture filling degree plays a major role in the fracture pressure and the propagation of hydraulic fractures, while the fracture dip plays a minor role. The experimental results are consistent with the model results in terms of the law, but due to the existence of other natural fractures in the test block, the fracture pressure is smaller than that of this model. This model can provide some theoretical basis and technical support for situations where there are complex natural fractures in hydraulic fracturing. Full article

To investigate hydraulic fracture propagation in multi-layered porous media such as sand–coal interbedded formations, we present a new phase-field-based model. In this formulation, a diffuse fracture is activated only when the local element strain exceeds the rock’s critical strain, and the fracture width is represented by orthogonal components in the x and y directions. Unlike common PFM approaches that map the permeability directly from the damage field, our scheme triggers fractures only beyond a critical strain. It then builds anisotropy via a width-to-element-size weighting with parallel mixing along and series mixing across the fracture. At the element scale, the permeability is constructed as a weighted sum of the initial rock permeability and the fracture permeability, with the weighting coefficients defined as functions of the local width and the element size. Using this model, we examined how the in situ stress contrast, interface strength, Young’s modulus, Poisson’s ratio, and injection rate influence the hydraulic fracture growth in sand–coal interbedded formations. The results indicate that a larger stress contrast, stronger interfaces, a greater stiffness, and higher injection rates increase the likelihood that a hydraulic fracture will cross the interface and penetrate the barrier layer. When propagation is constrained to the interface, the width within the interface segment is markedly smaller than that within the coal-seam segment, and interface-guided growth elevates the fluid pressure inside the fracture. Full article

To enhance the structural safety of casings in coalbed methane (CBM) wells, this study develops a finite element model of the casing-cement sheath-formation assembly using ABAQUS software (ABAQUS 6.14). The model systematically investigates the influence of cement sheath defect thickness, defect angle, and internal pressure on the casing stress distribution. The results reveal that the cement sheath defects significantly elevate the casing stress, particularly when the defect is located at the first cementing interface. Casing stress increases most sharply when the defect angle lies between 20° and 60°. Beyond 60°, the stress on the outer wall approaches the yield strength of the casing material. Furthermore, rising internal pressure intensifies stress concentration. When internal pressure exceeds 60 MPa, the outer wall becomes the most likely location for failure initiation. Optimizing the elastic modulus of the cement sheath and employing heavy-wall casing grades such as TP125V can effectively mitigate the casing stress and enhance wellbore integrity. These findings offer both theoretical insights and practical guidance for optimizing cementing design and hydraulic fracturing operations in CBM wells. Full article

Groundwater seepage plays a critical role in the long-term safety of high-level radioactive waste (HLW) disposal, yet its characterization remains challenging due to the complexity of fractured rock media. This study introduces the Double-Layered Seismo-Electric Method (DSEM) for imaging groundwater seepage fields with enhanced sensitivity and spatial resolution. By integrating elastic wave propagation with electrokinetic coupling in a stratified framework, DSEM improves the detection of hydraulic gradients and preferential flow pathways. Application at a representative disposal site demonstrates that the method effectively delineates seepage channels and estimates hydraulic conductivity, providing reliable input parameters for groundwater flow modeling. These results highlight the potential of DSEM as a non-invasive geophysical technique to support safety assessments and long-term monitoring in deep geological disposal of high-level radioactive waste. Full article

Limited-Entry Liner (LEL) technology has emerged as a transformative solution for enhancing hydrocarbon recovery in unconventional reservoirs while addressing challenges in carbon sequestration. This review examines the role of LEL in optimizing acid stimulation, hydraulic fracturing and production optimization, focusing on its ability to improve fluid distribution uniformity in horizontal wells through precision-engineered orifices. By integrating theoretical models, experimental studies, and field applications, we highlight LEL’s potential to mitigate the heel–toe effect and reservoir heterogeneity, thereby maximizing stimulation efficiency. Based on a comprehensive review of existing literature, this study identifies critical limitations in current LEL models—such as oversimplified annular flow dynamics, semi-empirical treatment of wormhole propagation, and a lack of quantitative design guidance—and aims to bridge these gaps through integrated multiphysics modeling and machine learning-driven optimization. Furthermore, we explore its adaptability for controlled CO₂ injection in geological storage, offering a sustainable approach to energy transition. This work provides a comprehensive yet accessible overview of LEL’s significance in both energy production and environmental sustainability. Full article

Conventional fracturing fluids, while essential for large-volume stimulation of unconventional reservoirs, often induce significant reservoir damage through water retention and capillary trapping. To address this problem, this study developed a novel superhydrophobic nano-viscous drag reducer (SN-DR), synthesized through a multi-monomer copolymerization and silane modification strategy, which enhances structural stability and minimizes reservoir damage. The structure and thermal stability of SN-DR were characterized by FT-IR, ¹H NMR, and TGA. Rheological evaluations demonstrated that the gel fracturing fluid exhibits a highly stable three-dimensional network structure, with a G′ maintained at approximately 3000 Pa and excellent shear recovery under cyclic stress. Performance tests showed that a 0.15% SN-DR achieved a drag reduction rate of 78.1% at 40 L/min, reduced oil–water interfacial tension to 0.91 mN·m⁻¹, and yielded a water contact angle of 152.07°, confirming strong hydrophobicity. Core flooding tests revealed a flowback rate exceeding 50% and an average permeability recovery of 86%. SEM and EDS indicated that the gel formed nanoscale, tightly packed papillary structures on core surfaces, enhancing roughness and reducing water intrusion. The study demonstrates that gel fracturing fluid enhances structural stability, alters wettability, and mitigates water-blocking damage. These findings offer a new strategy for designing high-performance fracturing fluids with integrated drag reduction and reservoir protection properties, providing significant theoretical insights for improving hydraulic fracturing efficiency. Full article

Hydraulic fracturing technology significantly enhances reservoir conductivity by creating artificial fractures, serving as a crucial means for the economically viable development of low-permeability reservoirs. Accurate prediction of post-fracturing productivity is essential for optimizing fracturing parameter design and establishing scientific production strategies. However, current limitations in understanding post-fracturing production dynamics and the lack of efficient prediction methods severely constrain the evaluation of fracturing effectiveness and the adjustment of development plans. This study proposes a machine learning-based method for predicting post-fracturing productivity in multi-layer commingled production wells and validates its effectiveness using a key block from the PetroChina North China Huabei Oilfield Company. During the data preprocessing stage, the three-sigma rule, median absolute deviation, and density-based spatial clustering of applications with noise were employed to detect outliers, while missing values were imputed using the K-nearest neighbors method. Feature selection was performed using Pearson correlation coefficient and variance inflation factor, resulting in the identification of twelve key parameters as input features. The coefficient of determination served as the evaluation metric, and model hyperparameters were optimized using grid search combined with cross-validation. To address the multi-layer commingled production challenge, seven distinct datasets incorporating production parameters were constructed based on four geological parameter partitioning methods: thickness ratio, porosity–thickness product ratio, permeability–thickness product ratio, and porosity–permeability–thickness product ratio. Twelve machine learning models were then applied for training. Through comparative analysis, the most suitable productivity prediction model for the block was selected, and the block’s productivity patterns were revealed. The results show that after training with block-partitioned data, the accuracy of all models has improved; further stratigraphic subdivision based on block partitioning has led the models to reach peak performance. However, data volume is a critical limiting factor—for blocks with insufficient data, stratigraphic subdivision instead results in a decline in prediction performance. Full article

This study addresses the key technical challenges in monitoring hydraulic fracturing within unconventional reservoirs through an innovative wide-field electromagnetic (WEM) monitoring technique. The method employs a 5A AC-excited wellbore-fracturing fluid system to establish a conductor antenna effect, coupled with a surface electrode array (100–250 m offset) to detect millivolt-level time-lapse potential anomalies, enabling real-time dynamic monitoring of 142 fracturing stages. A line current source integral model was developed to achieve quantitative fracture network inversion with less than 12% error, attaining 10 m spatial resolution and dynamic updates every 10 min (80% faster than conventional methods). Optimal engineering parameters were identified, including fluid intensity ranges of 25–30 m³/m for tight sandstone and 30–35 m³/m for shale, with particulate diverters achieving 93.1% diversion efficiency (significantly outperforming chemical diverters at 35%). Application in deep reservoirs maintained signal attenuation rates below 5% per kilometer. Theoretically, a nonlinear relationship model between fluid intensity and stimulated area was established, while practical implementation through real-time adjustments in 142 stages enhanced single-well production by 15–20% and reduced diverter costs, advancing the paradigm shift from empirical to scientific fracturing in unconventional reservoir development. Full article

Multistage hydraulic fracturing significantly increased oil and gas production in the past two decades. After drilling, fracturing fluids are pumped into the formation to create fractures that provide pathways to the hydrocarbon. These fluids are usually viscous to provide the mechanical power to frack the formation and carry the proppants, which keep the fractures open. After fracking, the viscous gel should be broken to allow the flowback of the fluid to avoid formation damage. The key player in the fracturing fluid system is the polymer, which is responsible for the fluid viscosity of the system. All other additives are added to improve the polymer’s performance under different conditions and reduce formation damage. The formation damage appears as fine migration, residue precipitation, adsorption, and wettability alteration. All of these types are affected by the polymer types and behavior. This paper reviews the polymers used in fracturing treatments, their classifications, preparations, mechanisms, degradation behavior, and interactions with other fracturing fluid additives. It also covers their impact on the formation damage and environmental concerns raised with fracturing treatments, including spills and flaring activities. The paper discussed the cost of the main polymers used in fracturing fluids and suggested practical recommendations to select a robust, cost-effective polymer. By integrating these concepts, the review gives the researcher the necessary knowledge to design and prepare effective fracturing fluids tailored to a wide range of operational scenarios. Full article

The effect of molecule–surface interaction strength on water becomes pronounced when pore size shrinks to the nanoscale, leading to the spatially varying viscosity and water slip phenomena that break the theoretical basis of the classic Lucas–Washburn (L-W) equation for the spontaneous imbibition of water. With the purpose of fulfilling the knowledge gap, the viscosity of nanoconfined water is investigated in relation to surface contact angle, a critical parameter manifesting microscopic molecule–surface interaction strength. Then, the water slip length at the nanoscale is determined in accordance with the mechanical balance of the first-layer water molecules, which enlarges gradually with increasing contact angle, indicating a weaker surface–molecule interaction. After that, a novel model for the spontaneous imbibition of nanoconfined water incorporating spatially inhomogeneous water viscosity and water slip is developed for the first time, demonstrating that the conventional model yields overestimations of 16.7–103.2%. Hydrodynamics affected by pore geometry are considered as well. The results indicate the following: (a) Enhanced viscosity resulting from the nanopore surface action reduces the water imbibition distance, the absolute magnitude of which could be 3 times greater than the positive impact of water slip. (b) With increasing pore size, the impact of water slip declines much faster than the enhanced viscosity, leading to the ratio of the nanoconfined water imbibition distance to the result of the L-W equation dropping rapidly at first and then approaching unity. (c) Water imbibition performance in slit nanopores is superior to that in nanoscale capillaries, stemming from the fact that the effective water viscosity in nano-capillaries is greater than that in slit nanopores by 5.1–22.1%, suggesting stronger hydrodynamic resistance. This research is able to provide an accurate prediction of spontaneous imbibition of nanoconfined water with microscopic mechanisms well captured, sharing broad application potential in hydraulic fracturing water analysis and water-flooding-enhanced oil/gas recovery. Full article