Search Results (331)

This study investigates the mechanical behavior of Nylon 12 Carbon Fiber specimens manufactured through fused filament fabrication (FFF) for potential integration into light water well drilling rigs. Fifteen tensile test samples were 3D-printed on a MakerBot Method X printer in three orientations: horizontal, vertical, and lateral. Each specimen was printed with a soluble SR-30 support material, which was subsequently dissolved in an SCA 1200-HT wash station using heated alkaline solution. Following support removal, all samples underwent thermal annealing at 80 °C for 5 h in the printer’s controlled chamber to eliminate residual moisture and improve structural integrity. The annealed specimens were subjected to uniaxial tensile testing using an Instron 8875 electrohydraulic machine, with strain measured by digital image correlation (DIC) on a speckle-patterned gauge section. Key mechanical properties, including Young’s modulus, Poisson’s ratio, yield strength, and ultimate tensile strength, were determined. Finally, a finite element analysis (FEA) was performed using MSC Visual Nastran for Windows to simulate the tensile loading conditions and assess internal stress distributions for each print orientation. The combined experimental and numerical results confirm the feasibility of using additively manufactured parts in demanding engineering applications. Full article

In offshore drilling and geological exploration, the stability of jack-up rigs is predominantly determined by the bearing capacities of spudcan foundations during seabed penetration. The penetration depth of spudcans is relatively shallow in hard clay. The formation of a cavity on the top surface of a spudcan often complicates accurate estimation of its capacity. This study employs the finite element method, in conjunction with the Swipe and Probe loading techniques, to examine the failure surfaces of soils of varying strengths. Numerical simulations that consider different gradients of undrained shear strength and cavity depths demonstrate that cavity depth significantly influences the failure envelope. The findings indicate that higher soil strength increases the bearing capacity and reduces the area of soil displacement at failure. Moreover, an enhanced theoretical equation for predicting the vertical-horizontal-moment (V-H-M) failure envelope in hard clay strata is proposed. The equation’s accuracy has been verified against numerical simulation results, revealing an error margin of 3–10% under high vertical loads. This model serves as a practical and valuable tool for assessing the stability of jack-up rigs in hard clay, providing critical insights for engineering design safety and risk assessment. Full article

Objectives: Anterior petrosectomy is a challenging neurosurgical procedure requiring precise identification and preservation of multiple critical structures. This technical note explores the feasibility of using real-time near-infrared indocyanine green (NIR-ICG) fluorescence with white light overlay to enhance visualization of the petrous internal carotid artery (ICA) during transpetrosal drilling. We aimed to assess its utility for planning and performing modified Dolenc–Kawase drilling. Methods: We integrated NIR-ICG and white light overlay using a robotic microscope with simultaneous visualization capabilities. This technique was applied to improve neurovascular preservation and skull base landmark identification. Intraoperative video frames and images were captured during an anterior transpetrosal approach for a petroclival meningioma, with technical details, surgical time, and feedback documented. Results: Real-time NIR-ICG with white light overlay successfully identified the posterior genu, horizontal petrosal segment, anterior genu, and superior petrosal sinus. It facilitated precise localization of cochlear landmarks, enabling tailored drilling of the Dolenc–Kawase rhomboid according to patient anatomy and accommodating potential anatomical variants. Conclusions: This approach could enhance intraoperative safety and improve exposure, possibly reducing neurovascular risks without extending operative time. It may serve as a valuable adjunct for complex skull base surgeries. Full article

Horizontal wells in shale formations, such as those in the South Pars gas field (Iran) and the Bakken shale (Canada/USA), are essential for production from ultralow-permeability reservoirs but remain limited by poor hole cleaning, high torque, and unstable fluid transport. This study integrates real-time field data from South Pars with Drillbench simulations in the Bakken to develop practical strategies for improving drilling efficiency. A water-based mud system (9–10.2 ppg, 29–35 cP) supplemented with 2 wt.% sulphonated asphalt was applied to mitigate shale hydration, enhance cuttings transport, and preserve near-wellbore injectivity. Field implementation in South Pars demonstrated that adjusting drillstring rotation to 90 RPM and circulation rates to 1100 GPM reduced torque by ~70% (24 to 7 klbf·ft) and increased the rate of penetration (ROP) by ~25% (8 to 10 m/h) across a 230 m interval. Simulations in the Bakken confirmed these improvements, showing consistent torque and pressure trends, with cuttings transport efficiency above 95%. Inducing controlled synchronous whirl further improved sweep efficiency by ~15% and stabilized annular velocities at 0.7 m/s. Overall, these optimizations enhanced drilling efficiency by up to 25%, reduced operational risks, and created better well conditions for field development and EOR applications. The results provide clear, transferable guidelines for designing and drilling shale wells that balance immediate operational gains with long-term reservoir recovery. Full article

To address the challenges of accurately predicting and controlling the annular equivalent circulating density (ECD) in ultra-deepwater gas hydrate-bearing formations of the Qiongdongnan Basin, where joint production of hydrates and shallow gas through dual horizontal wells faces a narrow safe pressure window and hydrate decomposition effects, this study develops an ECD prediction model that incorporates riser drilling operations. The model couples four sub-models, including the static equivalent density of drilling fluid, annular pressure loss, wellbore temperature–pressure field, and hydrate decomposition rate, and is solved iteratively using MatlabR2024a. The results show that hydrate cuttings begin to decompose in the upper section of the riser (at a depth of approximately 600 m), causing a reduction of about 2 °C in wellhead temperature, a decrease of 0.15 MPa in bottomhole pressure, and an 8 kg/m³ reduction in ECD at the toe of the horizontal section. Furthermore, sensitivity analysis indicates that increasing the rate of penetration (ROP), drilling fluid density, and flow rate significantly elevates annular ECD. When ROP exceeds 28 m/h, the initial drilling fluid density is greater than 1064 kg/m³, or the drilling fluid flow rate is higher than 21 L/s, the risk of formation loss becomes considerable. The model was validated against field data from China’s first hydrate trial production, achieving a prediction accuracy of 93%. This study provides theoretical support and engineering guidance for safe drilling and hydraulic parameter optimization in ultra-deepwater hydrate-bearing formations. Full article

Shale oil and gas reservoirs are characterized by low porosity and low permeability. The development of ultra-long horizontal wells can significantly increase reservoir contact area and enhance single-well production. Shale formations exhibit distinct bedding structures, high formation pressure, high rock hardness, and strong anisotropy. These characteristics result in poor drillability, slow drilling rates, and high costs when drilling horizontally, severely restricting efficient development. Therefore, accurately predicting the drillability of shale gas wells has become a major challenge. Currently, most scholars rely on a single parameter to predict drillability, which overlooks the coupled effects of multiple factors and reduces prediction accuracy. To address this issue, this study employs drillability experiments, mineral composition analysis, positional analysis, and acoustic transit-time tests to evaluate the effects of mineral composition, acoustic transit time, bottom-hole confining pressure, and formation drilling angle on the drillability of horizontal well reservoirs, innovatively integrating multiple parameters to construct a nonlinear model and introducing three intelligent optimization algorithms (PSO, AOA-GA, and EBPSO) for the first time to improve prediction accuracy, thus breaking through the limitations of traditional single-parameter prediction. Based on these findings, a nonlinear regression prediction model integrating multiple parameters is developed and validated using field data. To further enhance prediction accuracy, the model is optimized using three intelligent optimization algorithms: PSO, AOA-GA, and EBPSO. The results indicate that the EBPSO algorithm performs the best, followed by AOA-GA, while the PSO algorithm shows the lowest performance. Furthermore, the model is applied to predict the drillability of Well D4, and the results exhibit a high degree of agreement with actual measurements, confirming the model’s effectiveness. The findings support optimization of drilling parameters and bit selection in shale oil and gas reservoirs, thereby improving drilling efficiency and mechanical penetration rates. Full article

Significant risk of water and sand inrushes is commonly encountered during coal seam mining when thin bedrock is directly overlain by thick, water-bearing, unconsolidated layers. Achieving effective strata control and establishing reliable water-isolating mechanisms under these conditions represent critical scientific and technological challenges for safe mining operations. Furthermore, this is a vital research direction for advancing the extraction limit (or recovery height) in coal seams. Initially, drawing on key stratum theory, ground pressure behavior patterns, and mining operation characteristics, the weathered zone was identified as the critical grouting horizon. During the initial mining stage, the first two periodic weighting intervals (approximately 60 m) were identified as the key area. Subsequently, a strategy of high-pressure grouting was proposed to modify the weathered stratum. Numerical simulation methods were employed to optimize the grouting parameters, with the core specifications determined as follows: grouting pressure ≥30 MPa, water–cement ratio of 0.7:1, and grouting hole spacing ≤30 m. Ultimately, a grouting system was designed that used directional drilling from the surface to access the weathered zone, followed by branched horizontal boreholes for staged high-pressure grouting. The borehole trajectory was predominantly L-shaped. Field implementation demonstrated that the grouting intervention increased the first weighting span by an average of 17.3%. Critically, no water inflow was observed throughout the initial caving period, and significant roof falls or rib spalling were effectively mitigated. This confirmed a substantial improvement in key stratum stability, ensuring the safe and efficient advancement of the mining face. This study provides essential technical support and a practical model for safely and efficiently extracting coal seams under thin bedrock under similar complex hydrogeological conditions. Full article

In the development of tight gas reservoirs in Chuanzhong BJC Gas Field of the Sichuan Basin, running horizontal casing in ultra-long open-hole section faces challenges. These include large friction prediction errors and high casing buckling risks. These challenges significantly impede both the efficiency and safety of field development. Traditional static segmented friction models fail to accurately predict friction coefficients. The reason is that they cannot track dynamic changes in wellbore inclination, azimuth, and dogleg severity in real time. To address this bottleneck, this study develops a technical system termed AI-based dynamic friction inversion-segmented process optimization. Clustering algorithms are used to divide regions. These regions have low, medium, and high friction characteristics. The simulated annealing algorithm dynamically corrects friction coefficients. Meanwhile, the segmented processes of float collars and drilling fluid density are optimized. Verification was conducted on well J108-2H, which features an open-hole section of 4060.9 m and a horizontal-to-vertical ratio (HD/TVD) of 1.88. Results show that this system significantly reduces the mean absolute percentage error of friction coefficient prediction. It also greatly improves the accuracy of casing running feasibility assessment. As a result, the casing in well J108-2H was run smoothly and efficiently. The research results provide an innovative solution for the safe and efficient development of ultra-long open-hole sections in unconventional gas reservoirs. Full article

Driven by “Dual Carbon” goals, advancing the green development of oil and gas resources is imperative. The Shaximiao Formation tight gas reservoirs in the Sichuan Basin suffer from wellbore instability, impairing drilling efficiency and elevating energy use and emissions. This study integrates mineralogy, mechanics, drilling fluid optimization, and geostress modeling to address instability mechanisms and support low-carbon drilling. XRD shows that clay content decreases with depth (11–48%), while quartz and plagioclase dominate (45–80%). Synthetic-based drilling fluids fully inhibit clay swelling (0% expansion), outperforming calcium-based (2.4–3.1%) and water-based systems (5.4%). Synthetic and calcium-based fluids also reduce waste treatment difficulty and carbon intensity. Rolling recovery reaches 98.12% for synthetic-based vs. 78.18% for water-based. Strength tests reveal a 36.9% reduction after 14-day immersion in synthetic-based fluid, whereas water-based systems with nano-plugging agents show self-recovery, cutting energy use per foot by ~15%. Geostress modeling indicates a maximum horizontal stress of 90.08 MPa (NE114° ± 13°) and minimum of 67.2 MPa (NE24° ± 13°). Collapse pressure (48–60 MPa) varies azimuthally, requiring higher density (58–60 MPa) along the min. horizontal stress direction. A low-carbon mitigation strategy is proposed: prioritize synthetic or calcium-based drilling fluids, and optimize well trajectory using geostress models. This reduces fluid loss risk by >20%, limits methane emissions, shortens drilling cycles, and enhances efficiency while lowering carbon footprint. These insights support green and efficient natural gas development through intelligent drilling and eco-material applications. Full article

Based on molecular simulation methods, this paper constructs a molecular model of the CH₄-drilling fluid system to conduct an in-depth analysis of the microscopic dissolution behavior of CH₄ in drilling fluids. By utilizing key parameters such as molecular motion trajectories, interaction energies and solubility free energies, the mechanisms of CH₄ dissolution and diffusion are revealed. The factors influencing CH₄ solubility and their variation mechanisms are elucidated at the molecular level. Through gas solubility experiments, the variation patterns of CH₄ solubility in drilling fluids under different temperature and pressure conditions are investigated, and optimized solubility models for CH₄-drilling fluid systems are selected. The results indicate that the dissolution and diffusion behavior of CH₄ in drilling fluids can be described using free volume, interaction energy and solubility free energy, with the degree of influence ranked as follows: interaction energy > free volume > solubility free energy. The interaction and free volume of CH₄ in oil-based drilling fluids are both greater than those in water-based drilling fluids, suggesting a higher solubility of CH₄ in oil-based drilling fluids. Solubility models of CH₄ in drilling fluids under conditions of 30~120 °C and 10~60 MPa are obtained by regression. The research findings not only deepen the understanding of the dissolution and diffusion behavior of CH₄ in drilling fluids for shale gas horizontal wells, but also provide crucial parameters for establishing wellbore pressure models in managed pressure drilling. Full article

Drilling fluid losses into formation voids are among the major issues that lead to increases in the costs and nonproductive time of operations. Lost circulation materials have been widely used to stop or mitigate losses. In most cases, the size of the loss zone is not known, making conventional lost circulation materials unsuitable for plugging the loss zone. In this study, novel temperature-sensitive LCM (TS-LCM) particles composed of diglycidyl ether of bisphenol A (DGEBA) and 4,4′-diaminodiphenyl methane were prepared. It is a thermal-response shape-memory polymer. The molecular structure was analyzed by Fourier transform infrared spectroscopy. The glass transition temperature (T_g) was tested by Different scanning calorimetry (DSC). The shape-memory properties were evaluated by a bend-recovery test instrument. The expansion and mechanical properties of particles were investigated under high temperature and high pressure. Fracture sealing testing apparatus was used to evaluate sealing performance. The mechanism of sealing fracture was discussed. Research results indicated that the T_g of the TS-LCM was 70.24 °C. The shape fixation ratio was more than 99% at room temperature, and the shape recovery ratio was 100% above the T_g. The particle was flaky before activation. It expanded to a cube shape, and the thickness increased when activated. The rate of particle size increase for D90 was more than 60% under 120 °C and 20 MPa. The activated TS-LCM particles had high crush strength. The expansion of the TS-LCM particles could self-adaptively bridge and seal the fracture without knowing the width. The addition of TS-LCM particles could seal the tapered slot with entrance widths of 2 mm, 3 mm and 4 mm without changing the lost circulation material formulation. The developed TS-LCM has good compatibility with local saltwater-based drilling fluid. In field tests in the Yan’an area of the Ordos Basin, 15 shale oil horizontal wells were plugged with excellent results. The equivalent circulating density of drilling fluid leakage increased by an average of 0.35 g/cm³, and the success rate of plugging malignant leakage increased from 32% to 82.5%. The drilling cycle was shortened by an average of 14.3%, and the effect of enhancing the pressure-bearing capacity of the well wall was significant. The prepared TS-LCM could cure fluid loss in a fractured formation efficiently. It has good prospects for promotion. Full article

To address the technical challenge of real-time interpretation of sandstone reservoir porosity during drilling, a data-driven approach is employed by integrating logging data with machine learning algorithms to deeply mine existing logging data and predict the porosity range of encountered reservoirs. Initially, the acquired logging data is cleaned, and correlation analysis is conducted on the feature parameters. Porosity values were discretized into intervals according to field conditions. Subsequently, porosity-intelligent interpretation models are established using One-vs.-One Support Vector Machines (OVO SVMs), Random Forest (RF), XGBoost, and CatBoost algorithms. Model parameters are optimized using grid search and cross-validation methods. Finally, the test data is interpreted based on the four models with optimized parameters. Results indicate that all four models achieve training accuracies exceeding 95% and test accuracies exceeding 85%. Considering precision, recall, and F1 score comprehensively, the RF model is selected for the case study, with all three indicators exceeding 96%. These findings demonstrate that data-driven methods based on machine learning can accurately interpret sandstone reservoir porosity within specified intervals. For porosity interpretation of sandstone reservoirs in different blocks, interpretation models should be developed using multiple machine learning algorithms, and the best performing model should be selected for practical deployment. This method can be integrated with geological steering drilling technology during horizontal well drilling to ensure that the wellbore trajectory passes through higher-quality reservoir intervals, thereby providing certain guidance for maximizing the encounter rate of reservoir sweet spots. Full article

The multi-branch horizontal well for coalbed methane (CBM) is a core technical means to achieve efficient CBM extraction, and its productivity is jointly restricted by geological and engineering factors. To accurately grasp the main controlling factors of the productivity of multi-branch horizontal wells and provide a scientific basis for the optimized design of CBM development, this study takes Well W1 in the Wenjiaba Coal Mine of the Zhina Coalfield in Guizhou, China, as an engineering example and comprehensively uses three-dimensional geological modeling and reservoir numerical simulation methods to systematically explore the key influencing factors of the productivity of multi-branch horizontal wells for CBM. This study shows that coal seam thickness, permeability, gas content, and branch borehole size are positively correlated with the productivity of multi-branch horizontal wells. With the simulation time set to 1500 days, when the coal seam thickness increases from 1.5 m to 4 m, the cumulative gas production increases by 166%; when the permeability increases from 0.2 mD to 0.8 mD, the cumulative gas production increases by 123%; when the coal seam gas content increases from 8 m³/t to 18 m³/t, the cumulative gas production increases by 543%; and when the wellbore size increases from 114.3 mm to 177.8 mm, the cumulative gas production increases by 8%. However, the impact of branch angle and spacing on productivity exhibits complex nonlinear trends: when the branch angle is in the range of 15–30°, the cumulative gas production shows an upward trend during the simulation period, while in the range of 30–75°, the cumulative gas production decreases during the simulation period; the cumulative gas production with branch spacing of 100 m and 150 m is significantly higher than that with spacing of 50 m and 200 m. Quantitative analysis through sensitivity coefficients reveals that the coal seam gas content is the most important geological influencing factor, with a sensitivity coefficient of 2.5952; a branch angle of 30° and a branch spacing of 100 m are the optimal engineering conditions for improving productivity, with sensitivity coefficients of 0.2875 and 0.273, respectively. The research results clarify the action mechanism of geological and engineering factors on the productivity of multi-branch horizontal wells for CBM, providing a theoretical basis for the optimized deployment of well locations, wellbore structure, and drilling trajectory design of multi-branch horizontal wells for CBM in areas with similar geological conditions. Full article

To address the critical challenges of severe fragmentation in cuttings, persistent cuttings bed accumulation, and abrupt friction torque increases during horizontal well drilling of Jurassic continental shale oil formations in J Block, Sichuan Basin—rooted in the unique high clay content that induces colloidal stability of fine cuttings and resistance to conventional cleaning—this study innovatively proposes a coupled prevention–removal hole-cleaning technology. The core methodology integrates three synergistic components: (1) orthogonal numerical simulations to optimize drilling parameters, reducing the cuttings input rate by 43.48% through “hydraulic carrying + mechanical agitation” synergy; (2) a modified Moore model with horizontal section correction factors to quantify slip velocity of cuttings, lowering the prediction error from ±20% to ±5%; and (3) a helical groove cutting removal sub with 60 m optimal spacing, enhancing local turbulence intensity by 42% to disrupt residual cuttings bed. Field validation in Well J110-8-1H demonstrated remarkable improvements: a 50% reduction in sliding friction, a 25% decrease in rotational torque, and 40% shortening of the drilling cycle. This integrated technology fills the gap in addressing the “fragmentation–colloidal stability” dilemma in shale with high clay contents, providing a quantifiable solution for safe and efficient drilling in similar continental formations. Full article

The primary contradiction in mature oilfields during the high water-cut stage is the uneven vertical water drive, which prevents the effective utilization of residual oil in the upper part of thick sand bodies at small scales. To address this issue, ultra-short-radius horizontal wells are employed to establish large-diameter oil flow channels within the reservoir, thereby achieving precise exploitation of this type of residual oil. Optimizing the length of the horizontal section is a critical issue in the development of small-scale residual oil, but conventional methods for optimizing the length of horizontal sections cannot be directly applied to ultra-short-radius horizontal wells (USRHWs). Therefore, utilizing reservoir seepage mechanics theory, the reservoir numerical simulation method was employed to investigate variations in daily and cumulative oil production for different horizontal section lengths. The theoretical upper limit of the optimal horizontal section length for actual injection and production well patterns was determined. Considering the coupled flow characteristics in the bottom water drive reservoir formation and wellbore, as well as the impact of friction losses caused by the relative roughness of the pipe wall under turbulent flow conditions on productivity, a mathematical model was established for the optimal length of the horizontal section of USRHWs, and the technological optimal value was determined. On this basis, fully accounting for the influence of drilling costs and oil prices on the optimization of the horizontal section length, an economic model for optimizing horizontal section length was established, and we comprehensively determine the optimal length of horizontal sections from multiple perspectives, including simulation, technology, and economics. The effectiveness of this method was validated by the processing results of actual reservoir parameters and the production performance after drilling. Full article