Search Results (43)

Gas–water two-phase flow in horizontal and inclined wells is significantly influenced by gravitational forces and spatial asymmetry around the wellbore, resulting in complex and variable flow patterns. Accurate measurement of water holdup is essential for analyzing phase distribution and understanding multiphase flow behavior. Water holdup imaging provides a valuable means for visualizing the spatial distribution and proportion of gas and water phases within the wellbore. In this study, air and tap water were used to simulate downhole gas and formation water, respectively. An array capacitance arraay tool (CAT) was employed to measure water holdup under varying total flow rates and water cuts in a horizontal well experimental setup. A total of 228 datasets were collected, and the measurements were processed in MATLAB (2020 version) using three interpolation algorithms: simple linear interpolation, inverse distance interpolation, and Lagrangian nonlinear interpolation. Water holdup across the wellbore cross-section was also calculated using arithmetic averaging and integration methods. The results obtained from the three imaging algorithms were compared with these reference values to evaluate accuracy and visualize imaging performance. The CAT demonstrated reliable measurement capabilities under low- to medium-flow conditions, accurately capturing fluid distribution. For stratified flow regimes, the linear interpolation algorithm provided the clearest depiction of the gas–water interface. Under low- to medium-flow rates with high water content, both inverse distance and Lagrangian methods produced more refined images of phase distribution. In dispersed flow conditions, the Lagrangian nonlinear interpolation algorithm delivered the highest accuracy, effectively capturing subtle variations within the complex flow field. Full article

The continuous deposition of coal fine in the well can lead to complex problems, such as pump blockage and reduced capacity. The traditional critical velocity model applicable to rigid spherical particles, such as sand grains and glass beads, finds it difficult to accurately predict the migration behavior of coal fine in the wellbore. Therefore, this study aims to reveal the sedimentation law of coal fine particles, establish a critical velocity prediction model applicable to pulverized coal, and provide a theoretical basis for effectively preventing pump blockage and capacity decline problems. This paper analyzes the particle characteristics of coal fine in different mining areas and conducts experiments on the static settling of coal fine particles and the critical transport velocity. The experimental results showed that the larger the mesh size of coal fine, the lower the static settling velocity of coal fine particles. The critical velocity of coal fine increased with the particle size and concentration of the coal fine particles, as well as with the increase of the pipe column inclination. A new empirical formula for calculating the critical velocity of coal fine particles was derived by considering the effects of the coal fine concentration and pipe inclination. Full article

Deep coalbed methane wells often encounter challenges such as inefficient sand transport and sand accumulation in the horizontal sections during drainage, which significantly impact the stability of gas production and the efficiency of the gas lift system. To investigate the sand-carrying mechanisms in the horizontal sections of deep coalbed methane wells, this study develops a theoretical model for critical sand-carrying velocity based on gravitational, buoyant, drag, and pressure gradient forces. Additionally, a visualized experimental system was constructed using a multiphase pipe flow platform. By varying parameters such as liquid flow rate, gas–liquid ratio, gravel particle size, and pipe inclination, the critical conditions for sand transport were examined, and the dominant factors influencing sand transport in horizontal wellbore sections were identified. The experimental results indicate that water flow rate and particle size are inversely correlated with the gas volume required for sand transport, whereas inclination angle is positively correlated. The proposed model was validated against experimental data, showing a prediction error within 15%, thereby confirming its accuracy and engineering applicability. These findings offer theoretical guidance and technical references for efficient drainage and stable gas production in horizontal wellbore sections of deep coalbed methane wells. Full article

Drilling long horizontal wells in naturally cracked/fractured unconventional shale gas/oil formations presents a huge challenge to the energy industry because of wellbore clogging complications that cause pipe sticking problems. This work proposes to use smooth catenary well trajectories to reduce drilling friction to mitigate these problems. A mathematical model was developed in this study for designing well trajectory profiles with a smooth transition from the kick-out point (KOP) to the catenary section. This model consists of closed-form equations for the radius of curvature and inclination angle in the catenary section. Using the radius of curvature at the top point of the catenary section to design the arc section below the KOP eliminates the trial-and-error procedure required for achieving the smooth transition between the two sections. The result of a field case study with Tuscaloosa Marine Shale (TMS) data shows that the drilling drag (hook load) can be reduced by 15% to 30% with the use of smooth catenary well trajectories to replace the conventional arc-type well trajectories. Model-calculated reduction in the hook load drops linearly with the horizontal borehole friction coefficient (clog indicator). The reduction increases non-linearly from 15% to 30% with drill collar weight increasing from 20 lb/ft to 92 lb/ft. Full article

During the drainage process of coalbed methane (CBM) horizontal wells, wellbore fluctuations exert a significant influence on gas–liquid–solid three-phase flow behavior and coal particle migration. This study investigates the effects of wellbore inclination, gas–liquid flow rates, and coal particle sizes on migration characteristics through laboratory-scale experiments, based on an initial analysis of coal particle physical properties. A critical velocity model accounting for wellbore fluctuations is developed and refined. The migration states of coal particles under various operational conditions are examined, and the corresponding critical velocities and movement patterns are analyzed. The results show that coal particle migration is predominantly governed by the liquid phase, while the presence of particles has limited impact on the overall gas–liquid flow regime. Under different wellbore inclinations, the critical velocity increases with particle size; however, the influence of inclination is more pronounced than that of particle size. Coal particle entrainment follows three distinct stages: hopping, rolling, and suspension. The velocity during the rolling stage is identified as the critical velocity. At steeper inclination angles, particles are more easily entrained by the flow, and the associated critical velocity is higher. Based on the fitted experimental data, the model is revised to improve its predictive capability for coal particle transport in CBM wells. Finally, the model is validated using field data from a CBM well in the Ordos Basin. The results confirm the model’s ability to predict coal particle accumulation trends within the wellbore. This study provides new insights into coal particle migration mechanisms under fluctuating wellbore conditions, offering both experimental and theoretical support for understanding gas–liquid–solid flow behavior. It also presents technical guidance for optimizing drainage performance, controlling particle deposition, and formulating wellbore cleaning strategies. Full article

The development of deep coalbed methane (CBM) wells faces challenges such as significant reservoir depth, low permeability, and severe liquid loading in the wellbore. Traditional drainage and gas recovery techniques struggle to meet the dynamic production demands. This study, using the deep CBM wells at the Jishen 15A platform as an example, proposes a “cyclic gas lift–wellhead compression-vent gas recovery” composite synergy technology. By selecting a critical liquid-carrying model, innovating equipment design, and dynamically regulating pressure, this approach enables efficient production from low-pressure, low-permeability gas wells. This research conducts a comparative analysis of different critical liquid-carrying velocity models and selects the Belfroid model, modified for well inclination angle effects, as the primary model to guide the matching of tubing production and annular gas injection parameters. A mobile vent gas rapid recovery unit was developed, utilizing a three-stage/two stage pressurization dual-process switching technology to achieve sealed vent gas recovery while optimizing pipeline frictional losses. By combining cyclic gas lift with wellhead compression, a dynamic wellbore pressure equilibrium system was established. Field tests show that after 140 days of implementation, the platform’s daily gas production increased to 11.32 × 10⁴ m³, representing a 35.8% rise. The average bottom-hole flow pressure decreased by 38%, liquid accumulation was reduced by 72%, and cumulative gas production increased by 370 × 10⁴ m³. This technology effectively addresses gas–liquid imbalance and liquid loading issues in the middle and late stages of deep CBM well production, providing a technical solution for the efficient development of low-permeability CBM reservoirs. Full article

Wellbore instability is a major constraint in large-scale shale oil extraction. This study focuses on the shale–sandstone interbedded shale oil reservoirs in the Chang 7 area, delving into the evolutionary principles governing wellbore stability in horizontal drilling operations within these formations. A geological feature analysis of shale–sandstone reservoir characteristics coupled with rigorous mechanical experimentation was undertaken to investigate the micro-mechanisms underpinning wellbore instability. The Mohr–Coulomb failure criterion applicable to sandstone and the multi-weakness planes failure criterion of shale were integrated to analyze the stress distribution of surrounding rocks within horizontal wells, facilitating the computation of collapse pressure and fracture pressure. A finite element model of wellbore stability in shale–sandstone horizontal drilling was established, and then we conducted a comprehensive analysis of the impacts of varying elastic moduli, Poisson’s ratio, and in-situ stress on wellbore stability. The findings reveal that under varying confining pressures, the predominant failure mode observed in most sandstone samples is characterized by inclined shear failure, coupled with a reduced incidence of crack formation. The strength of shale escalates proportionally with increasing confining pressure, resulting in a reduced susceptibility to failure along its inherent weak planes. This transition is characterized by a gradual shift from the prevalent mode of longitudinal splitting towards inclined shear failure. As the elastic modulus of shale rises, the discrepancy between circumferential and radial stresses decreases. In contrast, with the increasing elastic modulus of sandstone, the gap between circumferential and radial stresses widens, potentially inducing potential instabilities in the wellbore. An increase in sandstone’s Poisson’s ratio corresponds to a proportional increase in the difference between circumferential and radial stresses. Under reverse fault stress regimes, wellbore collapse and instability are predisposed to occur. Calculations of collapse pressure and fracture pressure reveal that the safety density window is minimized at the interface between shale and sandstone, rendering it susceptible to wellbore instability. These research findings offer significant insights for the investigation of wellbore stability in interbedded shale–sandstone reservoirs contributing to the academic discourse in this field. Full article

Deep drilling can lead to the encounter of complex geological conditions, with significant overburden pressure leading to a narrow safety window for mud density. In this study, we deviated wellbore instability conditions using the Mohr–Coulomb and tensile failure criteria, solving for collapse, shear, and fracture pressure using Newton’s method. The safe mud density window is defined between the maximum value of pore and collapse pressures and the minimum value of shear and fracture pressures. The analysis of the Anderson fault stress model, utilizing this method, enables a comprehensive investigation of how the safety mud density window varies with wellbore inclination and azimuth angles under various stress conditions. Additionally, applications in Chinese oilfields illustrate that this methodology can accurately calculate and analyze extremely narrow safety mud density windows at depths ranging from 2000 to 3000 m. In conclusion, this method enables rapid and accurate prediction of mud density limits, improving wellbore stability and reducing drilling risks. Full article

The widespread application of horizontal drilling technology has significantly enhanced the development efficiency of unconventional resources, particularly shale gas, by overcoming key technical challenges in reservoir exploitation. However, wellbore instability remains a critical challenge during shale gas horizontal drilling, as borehole wall collapse often results in the accumulation of large-sized cuttings (or blocky cuttings), increasing the risk of stuck pipe incidents. In this study, a large-scale circulating loop experimental system was developed to investigate the hydrodynamic behavior of blocky cuttings transport under the influence of multiple factors, including rate of penetration (ROP), well inclination, flow rate, drilling fluid rheology, and block size. The experimental results reveal that when ROP exceeds 15 m/h, the annular solid-phase concentration increases non-linearly. At a well inclination of 60°, the axial and radial components of gravitational force reach a dynamic equilibrium, resulting in the maximum cuttings bed height. To enhance cuttings transport efficiency and mitigate deposition, a minimum flow rate of 35 L/s and a drill pipe rotation speed of 90 rpm are required to maintain sufficient turbulence in the annulus. Drilling fluid plastic viscosity (PV) in the range of 65–75 mPa·s optimizes suspension efficiency while minimizing circulating pressure loss. Additionally, increasing fluid density enhances the transport efficiency of large blocky cuttings. A drill pipe rotation speed of 80 rpm is recommended to prevent the formation of sand-wave-like cuttings beds. These findings provide valuable hydrodynamic insights and practical guidelines for optimizing hole-cleaning strategies, ensuring safer and more efficient drilling operations in shale gas horizontal wells. Full article

For Measurement While Drilling (MWD), the redundant Micro-Electro-Mechanical Systems Inertial Measurement Unit (MEMS-IMU) navigation system significantly enhances the reliability and accuracy of drill string attitude measurements. Such an enhancement enables precise control of the wellbore trajectory and enhances the overall quality of drilling operations. But installation errors of the redundant MEMS-IMUs still degrade the accuracy of drill string attitude measurements. It is essential to calibrate these errors to ensure measurement precision. Currently, the commonly used calibration method involves mounting the carrier on a horizontal plane and performing calibration through rotation. However, when the carrier rotates on the horizontal plane, the gravity acceleration component sensed by the horizontal axis of the IMU accelerometer in the carrier is very small, which leads to a low signal-to-noise ratio, so that the measured matrix obtained by the solution is dominated by noise. As a result, the accuracy of the installation is insufficient, and, finally, the effectiveness of the installation error compensation is reduced. In order to solve this problem, this study proposes a 45°-inclined six-position calibration method based on the selected hexagonal prism redundant structure for redundant MEMS-IMUs in MWD. Firstly, the compensation matrices and accelerometer measurement errors were analyzed, and the new calibration method was proposed; the carrier of the IMUs should be installed at an inclined position of 45°. Then, six measuring points were identified for the proposed calibration approach. Finally, simulation and laboratory experiments were conducted to verify the effectiveness of the proposed method. The simulation results showed that the proposed method reduced installation errors by 40.4% compared with conventional methods. The experiments’ results demonstrated reductions of 83% and 68% in absolute measurement errors for the x and y axes, respectively. As a result, sensor accuracy after compensation improved by over 25% compared with traditional methods. The calibration method proposed by this study effectively improves the accuracy of redundant systems, providing a new approach for the precise measurement of downhole trajectories. Full article

The salt layer serves as an excellent caprock for oil and gas resources, with its underlying strata often containing abundant hydrocarbon reserves. However, the strong creep characteristics of the salt layer frequently lead to damage issues. Therefore, research on the wellbore integrity of salt layers holds significant practical value. This study focuses on the wellbore integrity of high-pressure salt layers. Based on the Heard time-hardening creep model, a numerical simulation model of composite salt-layered wellbores incorporating a saline water seepage field was established. This study analyzed the mechanical influence of factors such as well inclination angle, azimuth angle, brine density, and liquid column density on the wellbore. The results indicate that high formation pressure, salt creep, and saline water seepage in high-pressure salt layers are the main causes of wellbore stress and deformation. These conditions pose a high risk of damage to the casing and cement sheath. When designing directional well trajectories within high-pressure salt layers, the inclination angle should be controlled between 45° and 60°, and the azimuth angle should be kept below 30°. Full article

China’s offshore heavy oil resources are abundant but underutilized. Circulating steam stimulation enhances production while increasing casing failure risks in thermal recovery wells. Accurately assessing casing performance after repeated thermal cycles is crucial for ensuring wellbore integrity. This paper presents tensile and creep experiments on TP110H casing under cyclic temperatures. The temperature distribution within the “casing-cement sheath-stratum” system is derived using heat transfer theory. Stress and displacement equations are established based on thick-walled cylinder theory and thermo-elasticity. Thermal coupling analysis assesses casing stress in straight, inclined, and sidetrack well sections. Key factors, including steam injection pressure, in situ stress, cement modulus, and prestress, are analyzed for their effects on cumulative strain below the packer. Strain-based methods evaluate casing safety. Results show that under thermal cycling at 350 °C, after 16 cycles, the casing’s elastic modulus, yield strength, and tensile strength decrease by 15.3%, 13.1%, and 10.1%, respectively, while the creep rate increases by 16.0%. Above the packer, the casing remains safe, but the lower section may be at risk. Using low-elasticity cement, higher steam injection pressure, and prestressing can help improve casing performance. This study provides guidance on enhancing casing safety and optimizing steam stimulation parameters. Full article

Unconventional oil and gas reservoirs are frequently developed using inclined and horizontal wells, leading to intricate multiphase flow patterns due to spatial asymmetry surrounding the wellbore and gravitational differentiation effects. Through the examination of water holdup imaging, the spatial arrangement of oil and water phases within the wellbore may be clearly depicted, yielding critical information for precisely assessing the ratios of oil and gas. This study employed No. 10 industrial white oil and tap water as fluid media, with measurements obtained using a resistive ring array tool (RAT) to evaluate its response properties over the wellbore cross-section. The data gathered throughout the trials were analyzed by two-dimensional interpolation imaging utilizing 2020 version MATLAB software. To enhance the analysis of water holdup distribution in the wellbore, three interpolation algorithms were utilized: Simple Linear Interpolation (SLI), Inverse Distance Weighting Interpolation (IDWI), and Ordinary Kriging Interpolation (OKI). The results indicated that RAT operates effectively in medium and low flow circumstances, correctly representing the real distribution of oil and water phases while yielding more dependable water holdup data. The SLI algorithm effectively delineates the oil-water interface during stratified flow of oil and water phases, rendering it the optimal algorithm for determining water holdup in standard flow patterns. Under DW/O&W and DO/W&W flow patterns, SLI continues to perform well; however, the accuracy of IDWI and OKI markedly enhances, with IDWI more effectively delineating the attributes of intricate mixed flow and more precisely representing the dynamic fluid distribution. Under DW/O and DO/W flow patterns, the OKI algorithm exhibits optimal performance in these intricate dispersed flow patterns. OKI more precisely represents the dynamic distribution of dispersed oil and water due to its capacity to simulate the spatial correlation of both phases, surpassing both SLI and IDWI. Full article

Poor wellbore cleaning is a significant challenge in oil drilling, primarily due to the accumulation of cuttings at the bottom of the well, particularly in deviated and horizontal wells. This study addresses this issue by employing Computational Fluid Dynamics (CFD) with the commercial software ANSYS FLUENT (2023-R1) to simulate a solid–liquid multiphase flow in an annulus. The primary objective is to analyze the cuttings concentration, pressure loss, and solid velocity profiles across various drilling parameters, including drill pipe rotation, the flow rate, rate of penetration, inclination angle, and fluid rheology. Our results underscore the critical role of these parameters in enhancing cuttings transport efficiency. Specifically, the drill pipe rotation, flow rate, and rate of penetration emerge as the most influential factors affecting the wellbore cleaning performance. With a validated model exhibiting an average error of 4.24%, this study provides insights into optimizing drilling operations to improve wellbore cleaning and increase hydrocarbon recovery. Full article

During drilling operations, drilling fluids undergo heat exchange with hydrate-bearing formations. The intrusion of drilling fluids affects hydrate stability, leading to variations in stress fields around a wellbore and complex scenarios such as borehole collapse, significantly hindering the efficient development of natural gas hydrate resources. This study establishes a thermo-hydro-mech model for hydrate-bearing inclined wells based on linear thermoelastic porous media theory and an appropriately high inhibitive drilling fluid temperature. This research reveals that drilling should follow directions of minimum horizontal stress or perpendicular to maximum horizontal stress during drilling operations to control wellbore stability. Hydrate decomposition due to factors like drilling fluid pressure and temperature can rapidly reduce the strength of low-saturation formations, significantly increasing the risk of wellbore instability. Therefore, selecting appropriate highly inhibitive and low-temperature drilling fluids during drilling operations helps control hydrate decomposition and reduce fluid intrusion, thereby mitigating risks associated with wellbore instability. Full article