Search Results (497)

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

Wellbore stability is a crucial factor affecting the safe exploitation of offshore natural gas hydrates. As a sustainable energy source, natural gas hydrate has significant reserves, high energy density, and low environmental impact, making it an important candidate for alternative energy. Although research on the stability of screen pipes during horizontal-well hydrate production is currently limited, its importance in sustainable energy extraction is growing. This study therefore considers the effects of hydrate phase change, gas–water seepage, energy and mass exchange, reservoir deformation, and screen pipe influence and develops a coupled thermal–fluid–solid–chemical field model for horizontal-well natural gas hydrate production. The model results were validated using experimental data and standard test cases from the literature. The results obtained by applying this model in COMSOL Multiphysics 6.1 showed that the errors in all simulations were less than 2%, with errors of 12% and 6% observed at effective stresses of 0.5 MPa and 3 MPa, respectively. The simulation results indicate that the presence of the screen pipe in the hydrate reservoir exerts little effect on the decomposition of gas hydrates, but it effectively mitigates stress concentration in the near-wellbore region, redistributing the effective stress and significantly reducing the instability risk of the hydrate reservoir. Furthermore, the distribution of mechanical parameters around the screen pipe is uneven, with maximum values of equivalent Mises stress, volumetric strain, and displacement generally occurring on the inner side of the screen pipe in the horizontal crustal stress direction, making plastic instability most likely to occur in this area. With other basic parameters held constant, the maximum equivalent Mises stress and the instability area within the screen increase with the rise in the production pressure drop and wellbore size, and the decrease in screen pipe thickness. The results of this study lay the foundation for wellbore instability control in the production of offshore natural gas hydrates via depressurization. The study provides new insights into sustainable energy extraction, as improving wellbore stability during the extraction process can enhance resource utilization, reduce environmental impact, and promote sustainable development in energy exploitation. Full article

Drilling fluid loss is a common and complex downhole problem that occurs during drilling in deep fractured formations, which has a significant negative impact on the exploration and development of oil and gas resources. Establishing a drilling fluid loss model for the quantitative analysis of drilling fluid loss is the most effective method for the diagnosis of drilling fluid loss, which provides a favorable basis for the formulation of drilling fluid loss control measures, including the information on thief zone location, loss type, and the size of loss channels. The previous loss model assumes that the drilling fluid is driven by constant flow or pressure at the fracture inlet. However, drilling fluid loss is a complex physical process in the coupled wellbore circulation system. The lost drilling fluid is driven by dynamic bottomhole pressure (BHP) during the drilling process. The use of a single-phase model to describe drilling fluids ignores the influence of solid-phase particles in the drilling fluid system on its rheological properties. This paper aims to model drilling fluid loss in the coupled wellbore–-fracture system based on the two-phase flow model. It focuses on the effects of well depth, drilling pumping rate, drilling fluid density, viscosity, fracture geometric parameters, and their morphology on loss during the drilling fluid circulation process. Numerical discrete equations are derived using the finite volume method and the “upwind” scheme. The correctness of the model is verified by published literature data and experimental data. The results show that the loss model without considering the circulation of drilling fluid underestimates the extent of drilling fluid loss. The presence of annular pressure loss in the circulation of drilling fluid will lead to an increase in BHP, resulting in more serious loss. Full article

To investigate the mechanism by which the rheological properties of drilling fluids affect the stability of the wellbore in brittle mud shale, this study systematically examines the influence of drilling fluids with different rheological properties on the hydration dispersion and rock strength of brittle mud shale through a series of laboratory experiments, including thermal rolling tests and uniaxial compressive strength tests on core samples. The results reveal that for weakly dispersible brittle mud shale, the rheological properties of drilling fluids have a minor effect on hydration dispersion, with rolling recovery rates consistently above 90%. However, the rheological properties of drilling fluids significantly influence the strength of brittle mud shale, and this effect is coupled with multiple factors, including rock fracture intensity index, soaking time, and confining pressure. Specifically, as the viscosity of the drilling fluid increases, the reduction in rock strength decreases; for instance, at 5 MPa confining pressure with an FII of 0.46, the strength reduction after 144 h was 69.8% in distilled water (from an initial 133.2 MPa to 40.2 MPa) compared to 36.3% with 3# drilling fluid (from 133.2 MPa to 88.7 MPa, with 100 mPa·s apparent viscosity). Both increased soaking time and confining pressure exacerbate the reduction in rock strength; a 5 MPa confining pressure, for example, caused an additional 60.9% strength reduction compared to 0 MPa for highly fractured samples (FII = 0.46) in distilled water after 144 h. Rocks with higher fracture intensity indices are more significantly affected by the rheological properties of drilling fluids. Based on the experimental results, this study proposes a strength attenuation model for brittle mud shale that considers the coupled effects of fracture intensity index, soaking time, and drilling fluid rheological properties. Additionally, the mechanism by which drilling fluid rheological properties influence the strength of brittle mud shale is analyzed, providing a theoretical basis for optimizing drilling fluid rheological parameters and enhancing the stability of wellbores in brittle mud shale formations. 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

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

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

Hydraulic fracturing technology is crucial for promoting oil and gas resource development. In recent years, water hammer fracture diagnostic techniques, derived from the water hammer effect in hydraulic fracturing, have garnered significant attention due to their low cost and ease of operation. The characteristic parameters of water hammer pressure are closely related to fracture geometry parameters. Monitoring the characteristics of water hammer pressure at the wellhead allows for rapid assessment of fracturing effectiveness. This study comprehensively considers wellbore friction, perforation friction, and the fluid loss effect within hydraulic fractures, establishing a mathematical model for the evolution of water hammer pressure during multi-cluster staged fracturing in horizontal wells. Based on field-monitored water hammer data from multiple stages, this study employed water hammer fracture diagnostics to inversely determine the geometric parameters of fractures in different fracturing stages. Characteristic parameters of the water hammer pressure, including the initial amplitude, number of oscillations, oscillation duration, and attenuation rate, were calculated for different well sections. Furthermore, the correlations between these water hammer characteristics and the fracture geometric parameters were analyzed. The correlation analysis between characteristic parameters of water hammer pressure and geometric parameters of hydraulic fractures indicates that under conditions of longer fracture half-length and smaller fracture height, the generated water hammer pressure exhibits a higher initial amplitude, fewer oscillations, a shorter oscillation duration, and a larger attenuation rate. The research findings can facilitate rapid estimation of fracture geometry using water hammer pressure, thereby optimizing fracturing design and enhancing fracturing effectiveness. Full article

To address wellbore integrity issues (especially casing strength concerns) of oil and gas wells threatened by overburden movement in coal mine goafs, this study takes a gas well in the goaf of Yanchang Gas Field as the research object. Using FLAC^3D 7.0 software, a 3D coupling model of “casing-cement sheath-formation-goaf” is established to systematically analyze the effects of goaf presence, convergence criteria, casing wall thickness/layer count, and cement slurry density on casing stress while conducting wellbore structure optimization. Key research results are as follows: (1) Overburden movement concentrates the maximum casing stress near the goaf, with the surface casing stress being 7–8 times higher than that in the absence of a goaf, serving as the core object of stress control; (2) A convergence criterion of 10⁻⁴ balances calculation accuracy and efficiency, where the maximum Von Mises equivalent stress of the surface casing differs by only 0.98% compared with that under a convergence criterion of 10⁻⁶; (3) Increasing casing layers is more effective than thickening walls or upgrading steel grade: three-layer casing reduces surface casing stress by 23.4% compared with two-layer casing, and all casing safety factors meet the standards; (4) The casing stress is minimized when the cement slurry density is 1800–1900 kg/m³ (with a minimum of 325.79 MPa), while excessively low or high density will lead to increased stress. The optimized wellbore structure provides key references for the design of gas wells in goaf areas. Full article

This paper demonstrates the comprehensive research of the target Middle Eastern carbonate oilfield on waterflooding technologies, including geological characteristics, integrated research, and principal development techniques. Geological research reveals that the Mishrif Formation in the B Oilfield is a gentle-sloping carbonate platform, with granular limestone serving as the primary reservoir rock and micrite limestone serving as the secondary reservoir rock. In addition, based on understandings drawn from geological characteristics and numerical simulation, the water flooding mode of IBPT, which can take full use of the gravity effect, has been proven to yield better sweep efficiency in the context of a thick and heterogeneous reservoir. Furthermore, a large-scale physical model experiment is designed to investigate the fluid migration between the producer and injector and indicates that the injected water migration is mainly divided into four phases, including a two-peak advance phase, a gravitational differentiation phase, a secondary bottom water phase, and a wellbore water coning phase. Subsequently, the principal techniques and corresponding optimized production responses of water flooding development are systematically illustrated, which consist of well type optimization, differentiated water injection strategies, injection pattern conversion, unstable water injection, selective well perforation, as well as tracer surveillance methodology. The outcomes of this study are directly derived from field performances and could provide concrete practical experiences for water flooding technology in the Middle East. Full article

This study develops a coupled Smoothed Particle Hydrodynamics (SPH) and the Discrete Element Method (DEM) framework to explore the sedimentation behavior of densely arranged particles in vertical pipes. An unresolved SPH-DEM model is proposed, which integrates porosity-dependent fluid governing equations through local averaging techniques to connect pore-scale interactions with macroscopic flow characteristics. Validated against single-particle settling experiments, the model accurately captures transient acceleration, drag equilibrium, and rebound dynamics. Systematic simulations reveal that particle number, arrangement patterns, and fluid domain geometry play critical roles in regulating collective settling: Increasing particle count induces nonlinear terminal velocity reduction. Systems of 16 particles show 50% lower velocity than single-particle cases due to enhanced shielding and energy dissipation. Particle configuration (compact layouts 4 × 8 vs. elongated arrangements 8 × 4) dictates hydrodynamic resistance, compact layouts facilitate faster settling by reducing cross-sectional blockage, while elongated arrangements amplify lateral resistance. The width of the fluid domain exerts threshold effects: narrow boundaries (0.03 m) intensify wall-induced drag and suppress vortices, whereas wider domains promote symmetric vortices that enhance stability. Additionally, critical transitions in multi-row/column systems are identified, where stress-chain redistribution and fluid-permeation thresholds govern particle detachment and velocity stratification. These findings deepen the understanding of granular–fluid interactions in confined spaces and provide a predictive tool for optimizing particle management in industrial processes such as wellbore cleaning and hydraulic fracturing. Full article

Accurate wellbore pressure management is critical for safety and efficiency in deep drilling, where narrow pressure windows and extreme high-temperature, high-pressure (HTHP) conditions exist. Current methods, including direct measurement and model-based prediction, face limitations such as sensor reliability issues and inaccurate lab-derived parameters. Data-driven AI methods lack interpretability and generalize poorly. This study proposes a model-data fusion approach to address these issues. It integrates mechanistic models with real-time data using the Unscented Kalman Filter (UKF) for real-time parameter correction. Friction correction factors are introduced to continuously update and optimize the estimation of frictional pressure drop. Validated with field data, the model demonstrates high accuracy, with absolute percentage errors below 5% and mean absolute errors (MAPE) below 1%. It also shows strong robustness, maintaining low MAPE (1.10–2.15%) despite significant variations in frictional pressure drop distribution. This method significantly enhances prediction reliability for safer ultra-deep drilling operations. Full article

Efficient development of bottom-water reservoirs is seriously affected by low recovery due to the rapid rise in water content in horizontal wells. In order to cope with this problem, a number of water control devices (including ICD and AICD) have been installed in horizontal wellbores in recent years. These are used in conjunction with packers to achieve the effect of balancing the fluid production profile and controlling water in sections. As an alternative to packers, the method of horizontal-well gravel packing has been widely used. This technique utilizes the permeability of gravel to block axial flow in the annulus of the horizontal wellbore, and uses water control devices for the purpose of sectional flow restriction. In this paper, a coupled method of numerical simulation of the production dynamics of gravel-packed water-control completions in horizontal wells in bottom-water reservoirs is proposed, which can consider multi-phase flows in porous media, in layers packed with gravel particles, and in water control devices simultaneously. In order to obtain the blocking capacity of the layer packed with gravel, we built an experimental setup of the same size as the borehole and annulus of a horizontal well, tested the permeability of the layer using Darcy’s law, and applied it to a coupled numerical simulation model. After comparison with actual well examples, it was proved that the coupled numerical simulation model has good accuracy, and can be used to carry out production predictions for gravel-packed water-control completions in horizontal wells in bottom-water reservoirs. The study also provides field engineers with a design tool for parameter optimization using a different water control method. 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