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25 pages, 11464 KB

Open AccessArticle

Study on Multi-Dimensional Coupled Numerical Simulation Method for Deep Coalbed Methane

by Zhongwen Sun, Yongsheng An, Yiran Kang, Yiming Sun and Guangning Yang

Processes 2026, 14(14), 2307; https://doi.org/10.3390/pr14142307 - 15 Jul 2026

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The exploitation of deep coalbed methane is of great significance for easing China’s energy supply pressure and realizing the “Dual Carbon” goals. However, local grid refinement simulation methods for coalbed methane cannot well capture the characteristics of deep coalbed methane reservoirs, including strong [...] Read more.

The exploitation of deep coalbed methane is of great significance for easing China’s energy supply pressure and realizing the “Dual Carbon” goals. However, local grid refinement simulation methods for coalbed methane cannot well capture the characteristics of deep coalbed methane reservoirs, including strong stress sensitivity and high brittleness. To tackle this issue, this paper develops a novel numerical simulation approach dedicated to deep coalbed methane development. Integrated with the fluid–solid coupling effect in rock mechanics, this approach considers the interporosity flow between matrix pores and cleat fractures as well as that between cleat fractures and hydraulic fractures, and establishes a multi-dimensional coupled simulation framework on the basis of the dual-porosity single-permeability model and embedded discrete fracture model. Simulation results show that compared with the local grid refinement model, the daily gas production curve simulated by the proposed method is more consistent with the actual field curve. The local grid refinement method fails to accurately characterize the specific morphology of hydraulic fractures. The average relative error of the local grid refinement model reaches 25.61%, while that of the model in this paper is only 7.54%, representing an accuracy improvement of 18.07%. Sensitivity analysis draws the following conclusions: reservoir gas content is the dominant geological factor governing deep coalbed methane output, and raising reservoir gas content can boost cumulative gas production by 45.77%; hydraulic fracture length mainly affects gas production performance in the middle and late production stages, while fracture conductivity dominates early-stage productivity. This method can fully characterize the coupled flow behaviors of three types of media (matrix pores, cleat fractures and hydraulic fractures), and offers solid technical support for productivity forecasting and development scheme optimization of deep coalbed methane reservoirs. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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23 pages, 2975 KB

Open AccessArticle

Data Assimilation-Based Method for Wellbore Flow State Inversion and Safety Intervention Timing Prediction in Managed Pressure Drilling

by Xiuping Chen, Wei Gao, Yongzhi Yang, Jun Li, Hongwei Yang and Zhenyu Long

Processes 2026, 14(13), 2125; https://doi.org/10.3390/pr14132125 - 30 Jun 2026

Viewed by 254

Abstract

In managed pressure drilling (MPD), wellbore flow states cannot be obtained in real time, so kick intervention decisions rely on the empirical judgment of engineers, which introduces a significant lag. The central hypothesis of this study is that fusing a physics-constrained transient two-phase [...] Read more.

In managed pressure drilling (MPD), wellbore flow states cannot be obtained in real time, so kick intervention decisions rely on the empirical judgment of engineers, which introduces a significant lag. The central hypothesis of this study is that fusing a physics-constrained transient two-phase flow model with real-time surface measurements through data assimilation can reconstruct the unobservable downhole flow state and, on this basis, enable quantitative and earlier prediction of the safe intervention timing than empirical judgment alone. To this end, this paper proposes a method for real-time inversion of wellbore flow states and safety intervention timing prediction based on the Ensemble Kalman Filter (EnKF). Using a transient wellbore gas–liquid two-phase flow model as the EnKF model operator, the method continuously assimilates real-time casing pressure, standpipe pressure (SPP), and pit gain data. This process dynamically corrects model prediction bias while maintaining multiphase flow physical constraints. Thus, the method achieves high-precision dynamic inversion of wellbore pressure profiles and gas holdup distributions. On this basis, the authors use the inverted states as initial conditions to calculate safety casing pressure with the multiphase flow model. The method then predicts intervention timing by combining three trigger conditions: safety casing pressure, pit gain, and the density difference between the inlet and outlet. The authors validated the method using kick scenarios from Well L and Well Z in the Shunbei block. The results showed that the mean absolute errors (MAEs) for casing pressure inversion were 0.113 MPa and 0.135 MPa, respectively. The MAEs for SPP were 1.324 MPa and 0.954 MPa. The MAEs for pit gain were 0.174 m³ and 0.114 m³. The inverted spatiotemporal distribution of gas holdup reflected the entire process of gas migration and expansion in the wellbore. Prediction results for intervention timing showed that the method issued early warning signals approximately 53 min and 29 min earlier than actual field operations. This method provides a quantitative decision-making basis with safety redundancy for MPD field operations. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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20 pages, 6739 KB

Open AccessArticle

Experimental Investigation of Acid-Etched Creep Behavior and Mechanical Constitutive Modeling of Carbonate Rocks

by Zehui Zhang, Ning Qi, Yuyang Shen, Yixin Lu, Shunming Zhou, Yuxin Wang, Ping Jiang and Aihua Li

Processes 2026, 14(13), 2038; https://doi.org/10.3390/pr14132038 - 23 Jun 2026

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Abstract

Deep and ultra-deep carbonate reservoirs commonly experience fracture closure and conductivity reduction under high-temperature and high-stress conditions. In this study, triaxial creep tests were conducted on unacid-etched and acid-etched carbonate cores under different stress levels to investigate their time-dependent deformation behavior and the [...] Read more.

Deep and ultra-deep carbonate reservoirs commonly experience fracture closure and conductivity reduction under high-temperature and high-stress conditions. In this study, triaxial creep tests were conducted on unacid-etched and acid-etched carbonate cores under different stress levels to investigate their time-dependent deformation behavior and the influence of acid etching on rock rheology. The results indicate that carbonate rocks exhibit pronounced creep behavior, including instantaneous elastic deformation, primary creep, and steady-state creep. Acid etching significantly altered the creep characteristics and rheological parameters of carbonate rocks, leading to distinct time-dependent deformation responses compared with the unacid-etched core. The Burgers constitutive model was employed to characterize the creep behavior, and all fitting correlation coefficients exceeded 0.9. Finite element simulations based on the fitted parameters successfully reproduced the experimental creep curves, verifying the reliability of the constitutive model. This study provides a theoretical and numerical basis for evaluating the long-term deformation behavior of acid-etched carbonate rocks and its implications for fracture closure and conductivity evolution. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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25 pages, 1920 KB

Open AccessArticle

A Dual-Layer Cooperative Feedback Control Method with Improved DBO-PID for Managed Pressure Drilling: Two-Phase Flow Experimental Verification

by Wang Chen, Jun Li, Hongwei Yang, Zhenyu Long and Xing Shi

Processes 2026, 14(9), 1394; https://doi.org/10.3390/pr14091394 - 27 Apr 2026

Viewed by 433

Abstract

During managed pressure drilling (MPD), gas influx intensifies the nonlinear relationship between choke valve opening degree and wellhead back pressure, causing conventional PID controllers to suffer from prolonged settling time and excessive overshoot. This paper proposes an automatic wellhead back pressure control method [...] Read more.

During managed pressure drilling (MPD), gas influx intensifies the nonlinear relationship between choke valve opening degree and wellhead back pressure, causing conventional PID controllers to suffer from prolonged settling time and excessive overshoot. This paper proposes an automatic wellhead back pressure control method based on pressure–opening degree dual-layer cooperative feedback. The outer layer rapidly positions the choke valve near the target opening degree through a pressure drop–opening degree mapping model. The inner layer employs a PID controller tuned by an improved Dung Beetle Optimizer (DBO) for fine pressure regulation. The improved DBO introduces Logistic chaotic map initialization and an adaptive inertia weight to enhance global search capability, and adopts a comprehensive fitness function integrating the ITAE criterion with engineering safety constraints. Simulation results show that, compared with the Ziegler–Nichols (Z-N) method, the improved DBO-tuned PID reduces overshoot by 83.9% and settling time by 78.0%. Gas–liquid two-phase flow laboratory experiments were conducted with gas void fractions of 0–46.6%. Using manual control (average settling time of 50 s) as the benchmark, the dual-layer system equipped with the improved DBO-PID reduces settling time to 25 s (a 50% reduction), maximum overshoot absolute error to 0.009 MPa (a 74% reduction compared with Z-N-tuned PID), and achieves a mean absolute error of 0.004 MPa during continuous pressure tracking with zero overshoot. Both simulation and experimental results confirm that the synergy between the dual-layer control architecture and the improved DBO-PID enables rapid regulation and stable tracking of wellhead back pressure under gas–liquid two-phase flow conditions. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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17 pages, 4278 KB

Open AccessArticle

Permeability Characterization of Drilling Fluid Invasion Zone in Ultra-High-Temperature and High-Pressure Gas Wells

by Zhujun Li, Xianjin Zeng, Qing Huang, Kaiyu Yang, Tao Zhang, Pengfei Li, Xiangke Shi, Ting Li, Huaqiao Yang and Zhiyuan Wang

Processes 2026, 14(6), 960; https://doi.org/10.3390/pr14060960 - 17 Mar 2026

Viewed by 474

Abstract

In ultra-high-temperature and high-pressure gas well drilling, the use of high-density drilling fluid inevitably invades the reservoir, and perforation operations require penetrating this invasion zone to further connect the reservoir. This paper first conducts core drilling fluid invasion experiments, introducing two parameters—filter cake [...] Read more.

In ultra-high-temperature and high-pressure gas well drilling, the use of high-density drilling fluid inevitably invades the reservoir, and perforation operations require penetrating this invasion zone to further connect the reservoir. This paper first conducts core drilling fluid invasion experiments, introducing two parameters—filter cake loss and core slice permeability—to derive the long-term invasion depth pattern of drilling fluid. Then, through three types of perforation target experiments (steel target, cement ring target, and sandstone target), the penetration performance of this type of perforating charge is evaluated. The results indicate that the total volume of drilling fluid invasion depends on the pore permeability characteristics of the core, with a fitted final invasion depth of 7.24 cm after 30 days of actual operation. The edge effect of the perforating gun causes significant differences in penetration depth and hole diameter at different phases, where the near-edge penetration depth and hole diameter are 1.86 times and 1.75 times larger than the far-edge, respectively. When the temperature resistance exceeds 200 °C/100 h, penetration depth and hole diameter decrease significantly with increasing temperature and time, and under 250 °C/170 h conditions, the firing rate markedly decreases. Using sandstone targets with identical strength and pore permeability conditions as a South China Sea ultra-high-temperature and high-pressure well block, the average penetration depth is 197 mm, far exceeding the thickness of the drilling fluid invasion zone. These experimental results provide theoretical support for perforation operations in a South China Sea ultra-high-temperature and high-pressure well block. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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19 pages, 4182 KB

Open AccessArticle

Experimental Evaluation of Sealing Performance at the First and Second Interfaces of Cement Sheath Under Cyclic Loading

by Qiqi Ying, Lei Wang, Zhenhui Bi, Yintong Guo, Yuxiang Jing and Chuanfu Sun

Processes 2026, 14(5), 805; https://doi.org/10.3390/pr14050805 - 28 Feb 2026

Viewed by 502

Abstract

With the development of unconventional oil and gas resources (such as shale gas and tight oil/gas), the widespread application of multistage fracturing technology has significantly increased the difficulty of wellbore integrity maintaining. The cement sheath serves as the core barrier for preserving wellbore [...] Read more.

With the development of unconventional oil and gas resources (such as shale gas and tight oil/gas), the widespread application of multistage fracturing technology has significantly increased the difficulty of wellbore integrity maintaining. The cement sheath serves as the core barrier for preserving wellbore integrity, particularly at the first interface (cement–casing) and the second interface (cement–formation). The high temperature, high pressure, and cyclic dynamic loading imposed by multistage fracturing represent severe challenges to the integrity of cement sheath. To simulate underground conditions realistically, a high-temperature, complex stress path loading system coupled with real-time gas flow monitoring was developed. Using this system, gas leakage monitoring and displacement-controlled cyclic loading tests were conducted on cement–steel (simulating the first interface) and cement–shale (simulating the second interface) composite specimens. It focused on investigating the effects of different temperatures, cyclic stress levels, and cycle counts on the sealing performance of the cement–steel and cement–shale composites. The findings reveal that elevated temperatures significantly degrade cement properties and accelerate damage accumulation. Cyclic stress levels and cycle counts are core drivers of interface fatigue failure, exhibiting synergistic destructive effects with temperature. The first interface is more prone to seal failure due to material property differences and a relatively high stress level. This research elucidates the cumulative damage mechanism underlying interfacial seal failure. It is of significant engineering implications for enhancing well safety and development efficiency. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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21 pages, 4050 KB

Open AccessArticle

Mechanical Stability Evaluation Method and Application for Subsea Christmas Tree-Wellhead Systems Considering Seismic and Corrosion Effects

by Xuezhan Zhao, Guangjin Chen, Yi Hong, Shuzhan Li, Zhiqiang Hu, Yongqi Ma, Xingpeng Zhang, Qian Xiang, Xingshang Chen and Bingzhen Gao

Processes 2026, 14(3), 431; https://doi.org/10.3390/pr14030431 - 26 Jan 2026

Viewed by 606

Abstract

To address the failure risks associated with long-term service of subsea Christmas tree-wellhead systems under the complex marine environment of the South China Sea, a multi-factor coupled mechanical analysis method is proposed to evaluate the system’s mechanical characteristics and ensure the safety of [...] Read more.

To address the failure risks associated with long-term service of subsea Christmas tree-wellhead systems under the complex marine environment of the South China Sea, a multi-factor coupled mechanical analysis method is proposed to evaluate the system’s mechanical characteristics and ensure the safety of deepwater oil and gas production. A dynamic model of lateral vibration under seismic loading is established, considering the combined effects of earthquakes, ocean currents, and seabed soil resistance. Based on the actual operating parameters of a well in the Lingshui area of the South China Sea, a three-dimensional finite element model of the subsea Christmas tree-wellhead assembly was developed in ABAQUS 2023. The combined effects of ocean currents, seismic loading, and corrosion over long-term service were simulated to compute and analyze the distributions of stress, bending moment, and associated failure risk. The results indicate that, under a once-in-a-century current combined with seismic waves of intensity V–VI, the system risk remains controllable. However, when the seismic intensity exceeds level VII, the maximum stress and bending moment reach 324.9 MPa and 6.02 MN·m, respectively, surpassing the allowable limits for an X56-grade surface conductor. Considering corrosion effects over a 25-year service life, the extreme stress values increase by 1–5% while the bending moment increases slightly; corrosion significantly amplifies the system’s failure risk. An analysis of the mudline burial height of the subsea wellhead during long-term service shows that, within a range of 1–7 m, variations in system loading are minimal. Based on the mechanical characteristics analysis, it is recommended that the design of subsea Christmas trees and wellheads incorporate regional seismic history, specify X56-grade surface conductors to mitigate corrosion effects, and install leakage-monitoring devices at critical locations to ensure the long-term service safety of the subsea Christmas tree-wellhead system. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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24 pages, 9651 KB

Open AccessArticle

H₂/CH₄ Competitive Adsorption of LTA Zeolite: Effects of Cations, Si/Al Ratio, Adsorption Temperature, and Pressure

by Xue Zhang, Jianfeng Tang and Hui Liu

Processes 2026, 14(2), 387; https://doi.org/10.3390/pr14020387 - 22 Jan 2026

Viewed by 847

Abstract

The efficient separation of H₂ from CH₄ is crucial for hydrogen purification from industrial off-gases using pressure swing adsorption (PSA). In this study, the competitive adsorption behavior of H₂/CH₄ on LTA zeolites was systematically investigated via grand canonical [...] Read more.

The efficient separation of H₂ from CH₄ is crucial for hydrogen purification from industrial off-gases using pressure swing adsorption (PSA). In this study, the competitive adsorption behavior of H₂/CH₄ on LTA zeolites was systematically investigated via grand canonical Monte Carlo (GCMC) simulations, with a focus on the effects of cation type (Na⁺, Li⁺, Ca²⁺, Mg²⁺), Si/Al ratio (1–1.5), temperature (298–318 K), and pressure (0.2–2 MPa). The results reveal that CH₄ favors β-cages as excellent adsorption sites with high population density, followed by the regions adjacent to the cations or framework oxygen atoms of the eight-membered rings. In contrast, H₂ is uniformly distributed throughout all the channels. Cations with higher valence and smaller ionic radii (e.g., Mg²⁺) enhance CH₄ adsorption capacity and diffusion more effectively than monovalent or larger cations. Increasing the Si/Al ratio reduces cation content and exposes more framework oxygen atoms, particularly those in Si–O–Si environments, which improve CH₄ adsorption. Elevated temperature weakens CH₄ adsorption while promoting H₂ diffusion and pore occupancy. Although higher pressure increases the uptake of both gases, H₂ adsorption rises more substantially and distributes more widely, leading to a decrease in CH₄/H₂ selectivity. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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23 pages, 4205 KB

Open AccessArticle

A Novel Predictive Model for Drilling Fluid Rheological Parameters Across Wide Temperature–Pressure Ranges Using Symbolic Regression Algorithm

by Wang Chen, Jun Li, Hongwei Yang, Geng Zhang, Biao Wang, Gonghui Liu, Zhaoyu Shen and Hui Ji

Processes 2026, 14(2), 386; https://doi.org/10.3390/pr14020386 - 22 Jan 2026

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Abstract

Accurate prediction of drilling fluid rheological parameters under high-temperature and high-pressure (HTHP) conditions is critical for reliable drilling hydraulics and wellbore pressure control in deep and ultra-deep wells. However, most existing empirical and semi-empirical rheological models are developed for limited temperature–pressure ranges and [...] Read more.

Accurate prediction of drilling fluid rheological parameters under high-temperature and high-pressure (HTHP) conditions is critical for reliable drilling hydraulics and wellbore pressure control in deep and ultra-deep wells. However, most existing empirical and semi-empirical rheological models are developed for limited temperature–pressure ranges and specific fluid formulations, which restrict their applicability and accuracy under HTHP conditions. In this study, systematic rheological experiments were conducted on multiple drilling fluid systems over wide temperature–pressure ranges (20–200 °C and 0.1–200 MPa). Based on the experimental data, a unified predictive model for key rheological parameters was developed using a symbolic regression (SR) algorithm. The model performance was evaluated using standard statistical metrics and compared with commonly used conventional models. Compared with conventional models, the proposed model shows stronger applicability for predicting the rheological parameters of the investigated oil-based and water-based drilling fluids over a wider temperature–pressure range. It effectively overcomes the limitations of existing models under HTHP conditions (150–200 °C and 80–200 MPa) and demonstrates improved prediction accuracy and robustness for both high- and low-density drilling fluids. The overall prediction errors are generally within approximately 10%. The results indicate that the proposed unified model provides a reliable and computationally efficient tool for predicting drilling fluid rheological parameters under HTHP conditions, facilitating its integration into wellbore hydraulics, wellbore pressure, and equivalent circulating density calculations in deep and ultra-deep well applications. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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19 pages, 1685 KB

Open AccessArticle

Study on Two-Phase Flow Behavior and Analysis of Influencing Factors Based on Unsteady Oil–Water Relative Permeability Experiment

by Liqiang Dong, Depeng Dong, Wenqiang Lou and Jie Cao

Processes 2026, 14(2), 346; https://doi.org/10.3390/pr14020346 - 19 Jan 2026

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Abstract

Late-stage sandstone reservoirs often exhibit flow behavior markedly different from early performance, reducing recovery. This study quantifies two-phase flow in Jilin Oilfield sandstone cores to support production optimization. An oil–water displacement apparatus was built and unsteady-state relative-permeability tests were performed on core plugs [...] Read more.

Late-stage sandstone reservoirs often exhibit flow behavior markedly different from early performance, reducing recovery. This study quantifies two-phase flow in Jilin Oilfield sandstone cores to support production optimization. An oil–water displacement apparatus was built and unsteady-state relative-permeability tests were performed on core plugs from multiple well blocks. Permeability, pressure gradient, water saturation, and displacement efficiency were tracked over a range of injection multiples. Water-phase relative-permeability curves classify three seepage types: concave-up (12 cores, 2.10–46.17 mD), linear (7 cores, 1.58–12.23 mD), and concave-down (3 cores, 8.74–30.73 mD). Permeability is strongly negatively correlated with irreducible water saturation (R² = 0.84) and positively correlated with residual oil saturation (R² = 0.58), two-phase flow interval (R² = 0.51), and movable oil saturation (R² = 0.89); other relationships are weak. An increasing pressure gradient markedly improves displacement efficiency in low-permeability cores. Higher injection multiples further raise displacement efficiency across all permeability classes, but gains diminish with increasing permeability. Displacement efficiency also increases with water cut when used as a flooding-stage indicator in these unsteady-state tests. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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22 pages, 9537 KB

Open AccessArticle

Study on Wellbore Stability of Shale–Sandstone Interbedded Shale Oil Reservoirs in the Chang 7 Member of the Ordos Basin

by Yu Suo, Xuanwen Kong, Heng Lyu, Cuilong Kong, Guiquan Wang, Xiaoguang Wang and Lingzhi Zhou

Processes 2025, 13(5), 1361; https://doi.org/10.3390/pr13051361 - 29 Apr 2025

Cited by 5 | Viewed by 1298

Abstract

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 [...] Read more.

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

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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22 pages, 8876 KB

Open AccessArticle

Efficient Design of Three-Dimensional Well Trajectories with Formation Constraints and Optimization

by Xueying Wang, Jie Zheng, Jianmin Wang, Yibing Yu, Xi Wang and Feifei Zhang

Processes 2025, 13(4), 1215; https://doi.org/10.3390/pr13041215 - 17 Apr 2025

Cited by 3 | Viewed by 1893

Abstract

Current methods for designing three-dimensional trajectories rarely account for complex formation constraints, focusing primarily on geometric relationships. However, trajectory adjustments are often necessary during drilling operations. These field adjustments typically lack systematic optimization, resulting in suboptimal trajectories. This study introduces a novel trajectory [...] Read more.

Current methods for designing three-dimensional trajectories rarely account for complex formation constraints, focusing primarily on geometric relationships. However, trajectory adjustments are often necessary during drilling operations. These field adjustments typically lack systematic optimization, resulting in suboptimal trajectories. This study introduces a novel trajectory optimization framework that integrates formation fitness for curve construction and proactive anti-collision trajectory adjustment (PACTA). The framework begins by incorporating PACTA and optimizing the initial trajectory to minimize total measured depth (TMD) using a genetic algorithm. Subsequently, a second optimization phase identifies curve sections passing through formations with low build-up fitness, automatically splitting them into combinations of curves and straight lines. Dynamic trajectory equations are then constructed based on these adjustments, and the final trajectory is optimized accordingly. Case studies demonstrate that the proposed method effectively adjusts curve positions in the presence of multiple formations with low build-up fitness while avoiding wellbore collisions. The approach achieves an average 10% reduction in total drilling time when minimizing TMD and an average 19.7% reduction in drillstring torque when torque minimization is prioritized. This new trajectory design method is expected to significantly reduce well construction costs. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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12 pages, 11071 KB

Open AccessArticle

Experimental Study on Combustion Characteristics of Methane Vertical Jet Flame

by Yudan Peng, Jing Yu, Weifeng Chen, Chen Hao, Jiawei Zhang, Guangming Fu and Baojiang Sun

Processes 2025, 13(4), 1207; https://doi.org/10.3390/pr13041207 - 16 Apr 2025

Cited by 3 | Viewed by 1463

Abstract

A jet flame is a common type of flame in fires in the oil and gas industries. At present, research on jet flames is still not comprehensive enough. To systematically investigate the combustion characteristics of vertical methane jet flames, experiments were conducted on [...] Read more.

A jet flame is a common type of flame in fires in the oil and gas industries. At present, research on jet flames is still not comprehensive enough. To systematically investigate the combustion characteristics of vertical methane jet flames, experiments were conducted on vertical methane jet flames, supplementing the existing experimental data on jet fires. The study reveals variations in the flame shape, center temperature, and thermal radiation with different flow rates and nozzle diameters, and the mechanisms of change in the flame center temperature and thermal radiation are discussed. The results show that increasing the gas flow rates and nozzle diameters led to a greater flame height and width. Along the flame axis, the temperature initially rose and then decreased with an increasing vertical distance from the nozzle. For smaller nozzle diameters, the flame temperature increased with the flow rate beyond the peak temperature point. Additionally, higher flow rates and larger nozzle diameters raised the height at which the maximum thermal radiation occurred. The thermal radiation near the flame’s top exceeded that in the middle, while minimal changes were observed near the base. The jet flame’s lift-off height and shape significantly influenced the distribution of the centerline temperature and thermal radiation. These findings provide valuable insights for the effective management and control of gas jet fires. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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26 pages, 8635 KB

Open AccessArticle

Quantitative Analysis and Modeling of Transient Cuttings Transport Impact on Drill String Mechanics in Extended Reach Drilling

by Jianbo Xiang, Xi Wang, Wenqiang Lou, Xueying Wang, Chi Zhao and Feifei Zhang

Processes 2025, 13(1), 35; https://doi.org/10.3390/pr13010035 - 27 Dec 2024

Cited by 4 | Viewed by 3065

Abstract

Cuttings beds in horizontal wells significantly affect the frictional torque and drag along the drill string; however, their quantification and modeling have been relatively underexplored. To gain deeper insights into the impact mechanisms of the cuttings bed distribution on drilling mechanics, this study [...] Read more.

Cuttings beds in horizontal wells significantly affect the frictional torque and drag along the drill string; however, their quantification and modeling have been relatively underexplored. To gain deeper insights into the impact mechanisms of the cuttings bed distribution on drilling mechanics, this study establishes a model linking the cuttings bed height with variations in axial and tangential forces on the drill string through experimental investigations. By integrating this model with previously developed transient cuttings transport and torque–drag models, a coupled transient hole cleaning and drill string mechanics model is constructed. This comprehensive model simulates the dynamic distribution of cuttings along the entire well trajectory and its influence on the drill string torque and drag. The results reveal that accumulated cuttings significantly reduce the weight on bit (WOB), increase the drill string torque, and cause problems related to a high equivalent circulation density (ECD). For long horizontal sections, the key to achieving effective hole cleaning lies in optimizing the design of the tripping circulation time to ensure that all cuttings are removed from the wellbore. Using the proposed coupled model, a methodology is developed to minimize the tripping circulation time by solving optimization problems within a constrained 2D domain, providing scientific guidance for drilling operations. The findings demonstrate that dynamically managing the cuttings distribution in the wellbore can significantly mitigate issues arising from insufficient hole cleaning, thereby ensuring drilling safety and efficiency. This study provides a scientific foundation for the optimized design of long horizontal well drilling operations and highlights the critical role of cuttings management in enhancing hole cleaning performance and mitigating drilling risks. Full article

(This article belongs to the Special Issue Advanced Research on Marine and Deep Oil & Gas Development)

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