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Aflaj refers to a traditional irrigation system found in Oman, which has been used for centuries to sustainably manage groundwater resources. These resources play a vital role in meeting various consumption needs, including agriculture, domestic, and industrial. The article, for the first time, introduces the concept of "hydraulics of aflaj", emphasizing the importance of accurate information about interaction of falaj and aquifer and also flow within their tunnels. The study utilizes the mechanisms of horizontal wells to simulate the interaction between the aquifer and the falaj tunnel, employing the meshless local Petrov–Galerkin numerical model to compute groundwater head of aquifer. The model is applied to a real test case in the Loba aquifer of Malaysia, demonstrating improved accuracy compared to previous models based on evaluation indices such as MAE, RMSE, MAPE, NSE and p-bias. The findings of the proposed model show good agreement. [ABSTRACT FROM AUTHOR]

The development of deep coalbed methane has become an important way to obtain natural gas in China. The development of deep CBM mainly depends on horizontal well technology. The different orientations of horizontal wells will have an important impact on the productivity of coalbed methane wells. The angle grid geological model of coalbed methane reservoirs with different inclination angles is established, and the deployment orientation of horizontal wells is changed to study the optimal deployment orientation of deep-saturated coalbed methane reservoirs. When CBM horizontal wells in deep saturated CBM reservoirs are deployed upward along the dip, well-controlled reserves, peak daily gas production, and cumulative gas production increase as the dip decreases. When deploying down the dip, with the increase in dip angle, the well-controlled reserves increase, and the peak daily gas production and cumulative gas production first increase and then decrease. In the low-dip reservoir, the development effect of horizontal wells deployed in different directions is better than that in the up-dip direction. In the high-dip reservoir, the development effect of horizontal wells deployed along the strike is better than that in the up-dip and down-dip directions. The development effect of horizontal wells is controlled by both well-controlled reserves and reservoir pressure drop. Because this method is targeted at different geological conditions, it can be used to guide the horizontal well optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs. [ABSTRACT FROM AUTHOR]

Horizontal wells have gained popularity as a technology for exploring water resources and remediating aquifers over the last decades, due to costs and numerous technical benefits compared to traditional vertical wells. This study presents a set of analytical solutions for drawdown distribution and various components of water budget contributing to flow toward a horizontal well in an aquifer-aquitard system interacting with a fully penetrating stream. It is assumed that the water level in the upper unconfined aquifer remains fixed at a specific elevation during the course of the pumping in the lower leaky aquifer. The water budget components account for inflows from aquifer storage, stream depletion, and leakage across the aquifer-aquitard interface. Analytical solutions to this three-dimensional, transient, non-axisymmetric Darcian flow model are given for both transient and steady-state flow conditions, relying on a four-fold integral transform technique that includes a Robin-type boundary condition at the aquifer-aquitard interface. It is shown how various components of water budget collectively counterbalance the effect of pumping discharge, confirming that the mass is conserved under both continuous and non-continuous pumping scenarios. Response maps are prepared to assess how different components of water budget react to changes in the well position. Furthermore, it is found that the components of water budget are most sensitive to the well-to-stream distance and anisotropy ratio of the leaky aquifer. [ABSTRACT FROM AUTHOR]

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Conventional thermal recovery methods for heavy oil suffer from significant issues such as high water consumption, excessive greenhouse gas emissions, and substantial heat losses. In contrast, electromagnetic heating, as a waterless method for heavy oil recovery, offers numerous advantages, including high thermal energy utilization, reduced carbon emissions, and volumetric heating of the reservoir, making it a focus of recent research in heavy oil thermal recovery technologies. This paper presents a numerical simulation study of electromagnetic heating for heavy oil recovery, using a heavy oil block in the Bohai Bay oilfield in China as a case study. Firstly, a multiphysics field coupled to a mathematical model was established, considering the impact of the temperature on the heavy oil viscosity, the threshold pressure gradient of non-Darcy flow, and the dielectric properties of the reservoir, along with heat dissipation from overlying and undercover sandstone and gravitational effects on fluid flow. Secondly, a numerical simulation method for the coupled multiphysics fields was developed, and the convergence and stability of the numerical simulation method were tested. Finally, a sensitivity analysis based on the numerical simulation results identified the factors affecting heavy oil production. It was found that electromagnetic heating significantly enhances heavy oil production, and the threshold pressure gradient greatly influences the prediction of heavy oil production. Moreover, heat dissipation from the overlying and undercover sandstone severely reduces cumulative oil production. When the production well is located below the electromagnetic heating antenna, larger well spacing results in higher cumulative heavy oil production. Higher heavy oil production is achieved when the antenna is positioned at the center of the reservoir for the studied cases. Power has a big effect on increasing heavy oil production, but its influence diminishes as power increases. There exists an optimal range of electromagnetic frequencies for maximum cumulative production, and higher water saturation leads to poorer electromagnetic heating efficiency. This study provides a theoretical foundation and technical support for the numerical simulation technology and development plan optimization of heavy oil reservoirs subjected to electromagnetic heating. [ABSTRACT FROM AUTHOR]

Featured Application: The findings of this study can be utilized to enhance the operational parameters of the clean drilling process in shale gas horizontal wells. Additionally, the research offers technical solutions to prevent the accumulation of cuttings beds and mitigate drilling obstructions, while also providing theoretical backing for the development of specialized borehole purification tools for shale gas. The extraction of shale gas via horizontal drilling presents considerable challenges, primarily due to the accumulation of cuttings within the annular space, resulting in increased friction, torque, and potential drilling complications. To address this issue, the study proposes an experimental setup aimed at simulating cuttings transport under various operational conditions, with a particular emphasis on gas wells. The methodology encompasses the modulation of the drilling fluid flow rate and the drill's rotational speed to examine the transport velocity of cuttings. Furthermore, the study analyzes the impact of annular eccentricity on return volume, transport time, and cuttings bed height. Critical initiation velocities for cuttings across different motion modes were also determined, and theoretical calculations were compared with empirical data. The findings indicate that an increased flow rate of drilling fluid and higher rotation speed substantially improve the transport of cuttings, thereby minimizing bed formation, whereas increased eccentricity hinders this process. The results revealed that the theoretical model showed a greater overestimation of the start-up velocity for spherical particles, with average errors ranging from 15.50% to 17.56%. In contrast, the model exhibited better accuracy for non-spherical (flaky) particles, with errors between 8.63% and 9.61%. Under non-rotating conditions, the average error of the model was approximately 8.32%, while the introduction of drill tool rotation increased the average error to 11.94%. These results have the potential to optimize operational parameters in shale gas well drilling and may contribute to the development of specialized borehole purification tools. [ABSTRACT FROM AUTHOR]

Many research findings have proven that the system of porous medium reservoirs exhibits different heterogeneous structures at various scales, demonstrating some form of self-similarity with fractal characteristics. In this paper, fractal theory is incorporated into the reservoir to investigate coupled flow between reservoir and horizontal well. By examining the pore structure of highly heterogeneous reservoirs, the fractal dimension can be determined. Analytical methods are utilized to solve the Green function of a point source in a reservoir with fractal characteristics. Employing Green's function and the principle of spatial superposition, a finite flow model for a horizontal well coupled with a fractal reservoir is developed to calculate the flow rate and flow profile of the horizontal well. The model also accounts for the impact of wellbore friction and is solved numerically. A specific example is used for calculation to analyze the influence of fractal parameters on the production and flow rate of the horizontal well. When considering the fractal characteristics of oil reservoirs, the flow rate of the horizontal well is lower than that in Euclidean space. As the fractal dimension increases, the connectivity of pores in the reservoir improves, making it easier to drive the fluid into the wellbore, and the flow distribution along the wellbore becomes more uniform. Conversely, as the anomalous diffusion index increases, the connectivity between pores deteriorates, thus the distribution of flow rate along the wellbore becomes more uneven. [ABSTRACT FROM AUTHOR]

Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing. [ABSTRACT FROM AUTHOR]

The segmented water control technology for bottom water reservoirs can effectively delay the entry of bottom water and adjust the production profile. To clarify the impact of different methods on horizontal well production with different reservoir conditions and to provide theoretical support for the scientific selection of methods for bottom water reservoirs, a numerical simulation method is presented in this study, which is able to deal with wellbore reservoir coupling under screen tube, perforation, and ICD (Inflow Control Device) completion. Assuming the geological characteristics of the bottom-water conglomerate reservoir in the Triassic Formation of the Tahe Block 9 as a test case, the three aforementioned completion methods are tested to predict the transient production characteristics. The impact of completion parameters, reservoir permeability, bottom-water energy, and individual well control on the time to encounter water in horizontal wells (during a water-free production period) is discussed. A boundary chart for the selection of completion methods is introduced accordingly. The results show that the optimized ICD completion development effect for heterogeneous reservoirs is the best, followed by optimized perforation completion. Permeability is the main factor affecting the performances of completion methods, while bottom water energy and single well controlled reserves have a scarce impact. The average permeability of the reservoir is less than 500 mD, and ICD has the best water control effect. If the permeability is greater than 500 mD, the water control effect of perforation completion becomes a better option. [ABSTRACT FROM AUTHOR]

Accurate prediction of fracture volume and morphology in horizontal wells is essential for optimizing reservoir development. Traditional methods struggle to capture the intricate relationships between fracturing effects, geological variables, and operational factors, leading to reduced prediction accuracy. To address these limitations, this paper introduces a multi-task prediction model designed to forecast fracturing outcomes. The model is based on a comprehensive dataset derived from fracturing simulations within the Long 4 + 5 and Long 6 reservoirs, incorporating both operational and geological factors. Pearson correlation analysis was conducted to assess the relationships between these factors, ranking them according to their influence on fracturing performance. The results reveal that operational variables predominantly affect Stimulated Reservoir Volume (SRV), while geological variables exert a stronger influence on fracture morphology. Key operational parameters impacting fracturing performance include fracturing fluid volume, total fluid volume, pre-fluid volume, construction displacement, fracturing fluid viscosity, and sand ratio. Geological factors affecting fracture morphology include vertical stress, minimum horizontal principal stress, maximum horizontal principal stress, and layer thickness. A multi-task prediction model was developed using random forest (RF) and particle swarm optimization (PSO) methodologies. The model independently predicts SRV and fracture morphology, achieving an R2 value of 0.981 for fracture volume predictions, with an average error reduced to 1.644%. Additionally, the model's fracture morphology classification accuracy reaches 93.36%, outperforming alternative models and demonstrating strong predictive capabilities. This model offers a valuable tool for improving the precision of fracturing effect predictions, making it a critical asset for reservoir development optimization. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Lightweight and ultra-lightweight solid materials are being used in gravel packing for horizontal wells instead of traditional quartz and ceramsite to decrease the risk of premature plugging and improve packing efficiency. Physical and numerical simulation experiments of gravel packing were conducted to assess the effectiveness of reducing solid material density and investigate its impact on packing and sand control. Packed gravel destabilization experiments highlighted the importance of high-compaction degree packing for effective sand control. Further gravel packing experiments examined the packing performance of different solid materials, revealing that lightweight solids have minimal gravitational deposition effect because their density is similar to the gravel slurry, relying primarily on fluid flow for compaction. The numerical simulation indicated that lightweight ceramsite is unsuitable for horizontal and highly-deviated wells because of its poor compaction degree and sand control, especially with high-viscosity slurry. High-density particles enhance gravitational deposition, improving packing compaction and sand control. Lightweight materials are recommended only when advanced plugging of α wave packing cannot be avoided. In highly-deviated wells, high-density materials significantly improve packing stability and sand control. This study provides clear technical guidelines for selecting solid materials for gravel packing in horizontal and highly-deviated wells. [ABSTRACT FROM AUTHOR]

Abstract Rock-breaking specific energy model of bit is the key foundation of evaluation and optimization of downhole drilling condition, while some necessary parameters for the existing models is difficult to measure directly while drilling. Aiming to improve the accessibility and accuracy of the model, this study proposes and illustrates an improved method by combining field tests and logging while drilling. The improved model was used to distinguish the inefficient drilling conditions and then to optimize drilling parameters. The results of application cases show that, the necessary parameters for the improved model could be obtained in time and the improved model helps to distinguish the reasons of stick–slip, whirling, load transfer difficulties in different horizontal wells. Based on the proposed model, the drilling parameters were evaluated and optimized, and then the rate of penetration get improved by 90.5% with higher energy efficiency. The proposed model and method could facilitate to realize automated and intelligent drilling.

Objectives: Horizontal wells can effectively improve the economic benefits of shale oil and gas development. However, as the horizontal section extends, the rock debris transport efficiency of the PDC drill bit gradually decreases, which can lead to bit balling in severe cases. Consequently, it is costly to directly improve the hydraulic structure of PDC bits. This paper uses a multi-physics field coupling numerical simulation method to analyze the influence of the coupling of different drilling process parameters and drill bit structure parameters on the bottom hole flow field and improves the drill bit hydraulic structure to enhance the rock debris transport efficiency of the PDC drill bit. Methods: Using COMSOL multi-physics field coupling simulation software, a geometric model of the bottom hole flow field of the horizontal well was established. The low Reynolds number k-ԑ model was employed to simulate the coupling of fluid flow and particle motion in the fluid, and iterative calculations were performed. The low Reynolds number k-ԑ model could adapt to different Reynolds number regions, especially the influence of molecular viscosity in the viscous bottom layer in the low Reynolds number region on the mixed phase flow. Parameters close to the actual drilling conditions were used to set the boundary conditions of the coupling model, and the grid independence of the coupling model was verified to reduce simulation error. Changes in the bottom hole flow field and the movement of rock debris by the PDC bit in a horizontal well under different drilling fluid displacement, PDC bit rotation speeds, and rock debris particle sizes were analyzed. Results: In the numerical simulation results of the coupling model, the following findings were observed: (1) From the flow velocity distribution diagram on the bottom hole wall, it was observed that the hydraulic energy distribution on the bottom hole wall became more uniform with an increase in displacement. When the displacement is 35 L/s, the flow velocity distribution effect on the bottom hole wall is optimal. However, the low-speed flow area of drilling fluid at the bottom hole cannot be completely eliminated by increasing displacement. In the comparative analysis of the retention of bottom hole rock debris at different displacements, an increase in displacement can reduce the impact of gravity on the cleaning of bottom hole rock debris. However, once the displacement reaches a certain level, the degree of cleaning of bottom hole rock debris changes relatively little. (2) In the lateral drilling fluid flow line at different rotation speeds, the flow rate gradually increases with an increase in rotation speed, causing a significant deviation in the flow state of the drilling fluid. When comparing and analyzing the accumulation of rock debris particles and the average velocity of rock debris particles, it was found that as the drill bit rotation speed increases, the fluctuation of the average velocity of rock debris particles also gradually increases. Although increasing drill rotation speed raises the average velocity of rock debris particles, it does not improve the migration efficiency of rock debris beyond a certain rotation speed. When the rotation speed is 240 r/min, the rock debris migration efficiency is the lowest. (3) In the comparative analysis of the average speeds of different rock debris particles, the farther they are from the bottom of the well, the faster the speed of large-size rock debris decays due to gravity. The speed change of small-size particles is relatively stable, but the average speed of rock debris particles with mixed particle sizes falls in the middle. (4) With roughly the same displacement area, increasing the number of drill bit nozzles from six to eight significantly reduces the amount of rock debris retention. (5) Compared with the equal diameter nozzle combination, the combination of a large inside and small outside nozzle reduces the transport efficiency of large particle rock debris due to the weakening of the drilling fluid flow rate. However, the flow rate in the central area of the combination of a small inside and large outside nozzle is reduced, which fails to form a strong pressure difference, resulting in an overall reduction in rock debris migration efficiency. Conclusions: Increasing the drilling fluid displacement improves the hydraulic energy and the rock debris transport efficiency at the bottom hole wall, but after the displacement increases to a certain level, it has little effect on the change in the degree of rock debris cleanliness at the bottom of the well. The mismatch between the high speed of the drill bit and displacement increases the average speed of the rock debris, but does not improve rock debris transport efficiency. Within a certain range of rock debris particle sizes, gravity has a relatively small impact on larger-size rock debris due to the influence of rotational force and turbulent kinetic energy. The transport efficiency of larger-size rock debris is higher than that of smaller-size rock debris. However, the farther away from the bottom of the well, the greater the impact of gravity on larger-size rock debris, resulting in greater velocity attenuation than that of smaller-size rock debris. According to the bottom hole flow field state under different drilling process parameters, the number of drill bit nozzles increase from six to eight under roughly the same nozzle displacement area, the hydraulic energy distribution is more uniform and the transport efficiency of rock debris improves. Meanwhile, compared to non-equal diameter nozzle combinations, equal diameter nozzle combinations perform more balancedly.

Aiming at the problems of large load of rotation drive system, low efficiency of torque transmission and high cost for operation and maintenance of liner steering drilling system for the horizontal well, a new method of liner differential rotary drilling with double tubular strings in the horizontal well is proposed. The technical principle of this method is revealed, supporting tools such as the differential rotation transducer, composite rotary steering system and the hanger are designed, and technological process is optimized. A tool face control technique of steering drilling assembly is proposed and the calculation model of extension limit of liner differential rotary drilling with double tubular strings in horizontal well is established. These results show that the liner differential rotary drilling with double tubular strings is equipped with measurement while drilling (MWD) and positive displacement motor (PDM), and directional drilling of horizontal well is realized by adjusting rotary speed of drill pipe to control the tool face of PDM. Based on the engineering case of deep coalbed methane horizontal well in the eastern margin of Ordos Basin, the extension limit of horizontal drilling with double tubular strings is calculated. Compared with the conventional liner drilling method, the liner differential rotary drilling with double tubular strings increases the extension limit value of horizontal well significantly. The research findings provide useful reference for the integrated design and control of liner completion and drilling of horizontal wells.

The analysis of natural fracture development characteristics is crucial for evaluating deep shale gas exploration and development. It provides valuable insights for assessing reservoir quality comprehensively and designing fracturing strategies differentially. This study focused on the deep shale of the Wufeng-Longmaxi formations in Luzhou area of southern Sichuan Basin (hereinafter referred to as southern Sichuan). Using core analysis, horizontal well imaging logging and seismic data, this study systematically investigated aspects such as descriptions of core natural fractures, development characteristics of horizontal well imaging logging, and the correlation between natural fractures in horizontal wells and seismically predicted fracture zones. The results show that horizontal well imaging logging can accurately identify three types of natural fractures: high-conductivity fractures, high-resistance fractures, and micro-faults. The fracture orientations identified by horizontal wells align with the direction of the current maximum horizontal principal stress, with fracture dip distribution patterns similar to those observed in vertical evaluation wells in the same structural positions. Seismically predicted fracture zones control the development of core-scale natural fractures identified through imaging logging. The influence distances of medium-intensity curvature body fracture zones, low-intensity curvature body fracture zones, and ant-track fracture zones on core-scale fractures are 110, 80, and 30-50 m, respectively. The Luzhou area's core-scale natural fractures exhibit "double-high" characteristics (high dip angle and high degree of calcite filling). The revealed correlations between the deve-lopment characteristics of core-scale natural fractures in horizontal wells, vertical well sections and seismic fracture zones serve as valuable references for the fine characterization of natural fractures, reservoir classification evaluation and differential fracturing technology testing of marine shale in southern Sichuan.

Our target USH reservoir in the D oilfield is characterized by "inverse rhythm" deposition with the noticeable features of "high porosity and low permeability". The reservoir has been developed with waterflooding using horizontal wells. Due to the strong heterogeneity of the reservoir, water channeling is severe, and the water cut has reached 79%. Considering the high temperature and high salinity reservoir conditions, polymer microspheres (PMs) were selected to realize conformance control. In this study, characterization of the polymer microsphere suspension was achieved via morphology, size distribution, and viscosity measurement. Furthermore, a multi-scale visualization study of the reservoir development process, including waterflooding, polymer microsphere flooding, and subsequent waterflooding, was conducted using macro-scale coreflooding and calcite-etched micromodels. It was revealed that the polymer microspheres could swell in the high salinity brine (170,000 ppm) by 2.7 times if aged for 7 days, accompanied by a viscosity increase. This feature is beneficial for the injection at the wellbore while swelled to work as a profile control agent in the deep formation. The macro-scale coreflood with a 30 cm × 30 cm × 4.5 cm layer model with 108 electrodes installed enabled the oil distribution visualization from different perpendicular cross sections. In this way, the in situ conformance control ability of the polymer microsphere was revealed both qualitatively and quantitatively. Furthermore, building on the calcite-etched visible micro-model, the pore-scale variation of the residual oil when subjected to waterflooding, polymer microsphere waterflooding, and subsequent waterflooding was collected, which revealed the oil displacement efficiency increase by polymer microspheres directly. The pilot test in the field also proves the feasibility of conformance control by the polymer microspheres, i.e., more than 40,000 bbls of oil increase was observed in the produces, accompanied by an obvious water reduction. [ABSTRACT FROM AUTHOR]

Most of the implemented marine gas hydrate test exploitation in the world adopt the depressurization method to break down the hydrate in the reservoir into natural gas and then extract it, but because the gas production results are still a certain distance away from the commercial exploitation, and it mainly stays in the stage of theoretical research and trial exploitation. Based on two trial productions in the Shenhu area of the South China Sea, this study established a model for hydrate exploitation and investigated the impact of different well types on the recovery rates of hydrates and free gas in different development layers during depressurization. For the Class 1 hydrate reservoirs, horizontal wells are the optimal solution to extract hydrate and free gas simultaneously when exploiting the hydrate three-phase layer. Meanwhile, the effect of different well spacing in vertical wells on the recovery rate of hydrate and free gas was studied. It is found that the best recovery efficiency is achieved when the spacing between two wells is 80 m. The lower the bottom flow pressure of the well, the higher the production capacity, but its influence is limited. [ABSTRACT FROM AUTHOR]

During the drilling process of horizontal wells in offshore oil fields, when encountering highly clayey shale or sandy shale sections, a common practice is to use a combination of blank pipes and screen pipes in the completion column to isolate high clay content layers. This helps prevent significant clay blockage in the screen pipes or wellbore, thereby reducing production loss. However, when blank pipes cannot effectively isolate clayey or sandy shale sections, the migration of clay content can lead to screen pipe blockage, adversely affecting production capacity. Given the current lack of evaluation methods for the impact of combined blank and screen pipe completion columns on production capacity, an experiment was designed to evaluate the skin factor of the completion column with a combination of blank and screen pipes. Through the calculation of the skin factor, the variation patterns of the skin factor for completion columns with blank and screen pipes under different conditions were obtained. These findings were then applied to a production evaluation. The research results revealed the following: (1) As the proportion of blind pipes increases, the skin factor of the combination of blind pipes and screen pipes in the completion tubing also increases. Excessive blind pipe ratios reduce production capacity. (2) In cases where the annular space is not completely filled, the influence of the blind pipe proportion on production capacity can be negligible. However, when the annular space is 100% filled, a higher proportion of blind pipes and silt content results in a larger skin factor, which leads to reduced production. In the application of the XH horizontal well case study, using the calculated model for the skin factor of the combination of blind pipes and screen pipes in the completion tubing established in this paper, it was determined that when the annular space was not completely blocked and 20 m of blind pipes were not placed in the designated position, the impact on the production index was 0.73%. However, when the blind pipes were not placed in the designated position for 100 m, the impact on the production index reached 1.47%. The method developed in this paper provides theoretical guidance for the optimization of completion tubing in mudstone and sandy mudstone sections and for production evaluation. [ABSTRACT FROM AUTHOR]

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Gravel packing in deep-water horizontal wells is an effective and practical sand control method, which is a key technical method to ensure efficient exploitation of deep-water oil and gas. To ensure the successful implementation of gravel packing in deep water horizontal wells, it is crucial to carry out effective optimization design of packing parameters. This paper proposes a novel optimization design approach for gravel packing in deep-water horizontal wells. In the proposed approach, an optimization model is proposed for gravel packing in deep-water horizontal wells, in which the gravel packing length is regarded as the objective function. Then, an improved artificial electric field algorithm (IAEFA) is introduced for optimizing the key gravel packing parameters so as to determine the maximum gravel packing length. For a specific case study, we conducted optimization calculations for gravel packing in a deep-water horizontal well. Results of the case study demonstrate that the optimization design approach based on the IAEFA algorithm can effectively address the parameter optimization problem of deep-water horizontal well gravel packing. For the target well of the case study, the maximum packing length obtained by the IAEFA algorithm could reach 1000.22 m, and the corresponding 3 sets of optimal packing parameters were also obtained. In the scenario of optimal packing parameters, the total time of gravel packing in target well is 566.6 min, and the total amount of sand consumption is 54,050.94 lbs. The bottom hole pressure during the injection stage remains stable with about 9780 psi, then slowly rises from 9788 psi to 9837 psi in the α-wave packing stage, and rapidly increases from 9837 psi to 9986 psi in the β-wave packing stage. The proposed approach provides an efficient and practical optimization tool for the optimal design of gravel packing in deep water horizontal wells. [ABSTRACT FROM AUTHOR]

Copyright of Coal Geology & Exploration is the property of Xian Research Institute of China Coal Research Institute and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Conventional fracturing design generally only considers the propagation of a single fracture in homogeneous storage, but the heterogeneity characteristics of the reservoir and the development of complex natural fractures will affect the fracturing effect. In order to study the horizontal well fracture propagation law under the synergistic effect of complex natural fracture reservoir heterogeneity, the globally embedded cohesive element finite model is established, and the heterogeneous reservoirs are built by Python programming. The influencing factors of multi-fracture propagation with heterogeneous reservoirs are analyzed, including the in situ stress difference, the injection rate of fracturing fluid, the perforation spacing, and the perforating clusters number. The results show that the heterogeneity and the natural fracture of the reservoir will affect the in situ stress distribution and propagation direction. When the in situ stress difference is low, the reservoir heterogeneity and natural fractures have a great influence on the fracture morphology. With the increase in injection rate, the fracture length and fracture width increase. With the in situ stress difference increase, the fracture deflection angle decreases. With the increase in fracturing fluid injection rate, the fracture length increases. The number of hydraulic fractures communicating with natural fractures increases with the natural fracture number and the number of perforation clusters under the synergistic effect of complex natural fracture and reservoir heterogeneity. [ABSTRACT FROM AUTHOR]

Soluble bridge plug is a key tool to improve the speed and quality of staged fracturing, which requires system design of pressure-bearing capacity, low manufacturing cost and dissolution rate to achieve different downhole environments. In order to study the application of soluble bridge plugs made in China under real working conditions and put forward improvement measures. In this paper, with the help of field engineering examples, relying on the working steps of "quality experimental detection → application collection → stability study," the systematic study of soluble bridge plugs from material determination to damage is realized. The results of this study are as follows: The release pressure is 15.6 MPa (converted release value is 19.66t). Matching with the driving force of the hydraulic release tool 23–25t under production conditions. The effective sealing time in various working environments is 24 h. Under the condition of different KCL solution concentrations at 90 °C, the dissolution time is 9–11 days, and 0.19–0.23 kg of cast iron and ceramic residues remain. The next step is to construct different stability research schemes under the premise of long time span, optimize the performance of bridge plug and strengthen the strength of anti-collision ring and spacer ring. At the same time, ensure the perfection of ground equipment in the construction process. [ABSTRACT FROM AUTHOR]

Aiming at the problems of large load of rotation drive system, low efficiency of torque transmission and high cost for operation and maintenance of liner steering drilling system for the horizontal well, a new method of liner differential rotary drilling with double tubular strings in the horizontal well is proposed. The technical principle of this method is revealed, supporting tools such as the differential rotation transducer, composite rotary steering system and the hanger are designed, and technological process is optimized. A tool face control technique of steering drilling assembly is proposed and the calculation model of extension limit of liner differential rotary drilling with double tubular strings in horizontal well is established. These results show that the liner differential rotary drilling with double tubular strings is equipped with measurement while drilling (MWD) and positive displacement motor (PDM), and directional drilling of horizontal well is realized by adjusting rotary speed of drill pipe to control the tool face of PDM. Based on the engineering case of deep coalbed methane horizontal well in the eastern margin of Ordos Basin, the extension limit of horizontal drilling with double tubular strings is calculated. Compared with the conventional liner drilling method, the liner differential rotary drilling with double tubular strings increases the extension limit value of horizontal well significantly. The research findings provide useful reference for the integrated design and control of liner completion and drilling of horizontal wells. [ABSTRACT FROM AUTHOR]

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Copyright of Diamond & Abrasives Engineering is the property of Zhengzhou Research Institute for Abrasives & Grinding and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of China Petroleum Machinery is the property of China Petroleum Machinery Editorial Department and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Old-well sidetracking is a key method for controlling low-productivity wells in the Bohai oilfield. This study employs reservoir engineering and numerical simulation techniques to investigate the maximum drainage radius and natural coning control mechanism in heavy-oil reservoirs with bottom water. Based on these findings, an alternate production technology was developed for dual-branch horizontal wells. The technology creates a new branch through sidetracking, connecting and isolating the old and new wellbores using a combination of wall hangers and branch guides. Initially, the old wellbore with an ultra-high water cut is temporarily sealed. When the new branch reaches a high water-cut stage, production is switched back to the old wellbore. This technology was successfully applied to three wells in the Bohai oilfield, resulting in the new branch achieving expected production levels, while reopening the old wellbore increased daily oil output by 27 m3 and reduced water cut by 5.6%. Cumulative oil production from these wells reached 95,000 m3. This technology improves well-slot resource utilization, enhances recovery rates, and has significant potential for broader application. [ABSTRACT FROM AUTHOR]

With the continuous advancement of petroleum extraction technologies, the importance of horizontal and inclined wells in reservoir exploitation has been increasing. However, accurately predicting oil–water two-phase flow regimes is challenging due to the complexity of subsurface fluid flow patterns. This paper introduces a novel approach to address this challenge by employing extreme gradient boosting (XGBoost, version 2.1.0) optimised through Bayesian techniques (using the Bayesian-optimization library, version 1.4.3) to predict oil–water two-phase flow regimes. The integration of Bayesian optimisation aims to enhance the efficiency of parameter tuning and the precision of predictive models. The methodology commenced with experimental studies utilising a multiphase flow simulation apparatus to gather data across a spectrum of water cut rate, well inclination angles, and flow rates. Flow patterns were meticulously recorded via direct visual inspection, and these empirical datasets were subsequently used to train and validate both the conventional XGBoost model and its Bayesian-optimised counterpart. A total of 64 datasets were collected, with 48 sets used for training and 16 sets for testing, divided in a 3:1 ratio. The findings highlight a marked improvement in predictive accuracy for the Bayesian-optimised XGBoost model, achieving a testing accuracy of 93.8%, compared to 75% for the traditional XGBoost model. Precision, recall, and F1-score metrics also showed significant improvements: precision increased from 0.806 to 0.938, recall from 0.875 to 0.938, and F1-score from 0.873 to 0.938. The training accuracy further supported these results, with the Bayesian-optimised XGBoost (BO-XGBoost) model achieving an accuracy of 0.948 compared to 0.806 for the traditional XGBoost model. Comparative analyses demonstrate that Bayesian optimisation enhanced the predictive capabilities of the algorithm. Shapley additive explanations (SHAP) analysis revealed that well inclination angles, water cut rates, and daily flow rates were the most significant features contributing to the predictions. This study confirms the efficacy and superiority of the Bayesian-optimised XGBoost (BO-XGBoost) algorithm in predicting oil–water two-phase flow regimes, offering a robust and effective methodology for investigating complex subsurface fluid dynamics. The research outcomes are crucial in improving the accuracy of oil–water two-phase flow predictions and introducing innovative technical approaches within the domain of petroleum engineering. This work lays a foundational stone for the advancement and application of multiphase flow studies. [ABSTRACT FROM AUTHOR]

Inter-well frac-hit has become an important challenge in the development of unconventional oil and gas resources such as fractured tight sandstone. Due to the presence of hydraulic fracturing fractures, secondary induced fractures, natural fractures, and other seepage media in real formations, the acquisition of stress fields requires the coupling effect of seepage and stress. In this process, there is also stress sensitivity, which leads to unclear dynamic evolution laws of stress fields and increases the difficulty of the staged multi-cluster fracturing of horizontal wells. The use of a multi-stage stress-sensitive horizontal well production stress field prediction model is an effective means of analyzing the influence of natural fracture parameters, main fracture parameters, and multi-stage stress sensitivity coefficients on the stress field. This article considers multi-stage stress sensitivity and, based on fractured sandstone reservoir parameters, establishes a numerical model for the dynamic evolution of the production stress field in horizontal wells with matrix self-supporting fracture-supported fracture–seepage–stress coupling. The influence of various factors on the production stress field is analyzed. The results show that under constant pressure production, for low-permeability reservoirs, multi-stage stress sensitivity has a relatively low impact on reservoir stress, and the amplitude of principal stress change in the entire fracture length direction is only within the range of 0.27%, with no significant change in stress distribution; The parameters of the main fracture have a significant impact on the stress field, with a variation amplitude of within 2.85%. The ability of stress to diffuse from the fracture tip to the surrounding areas is stronger, and the stress concentration area spreads from an elliptical distribution to a semi-circular distribution. The random natural fracture parameters have a significant impact on pore pressure. As the density and angle of the fractures increase, the pore pressure changes within the range of 3.32%, and the diffusion area of pore pressure significantly increases, making it easy to communicate with the reservoir on both sides of the fractures. [ABSTRACT FROM AUTHOR]

AbstractHorizontal wells have the advantages of high production, considerable access to reserves, and effective sand production control; thus, they are potential well types for hydrate exploitation. In the process of hydrate mining, the decomposition of hydrate will cause the deterioration of the mechanical properties of the reservoir, which may induce submarine landslides, especially in the case of multiple horizontal wells, and the risk of submarine landslides is further increased. Therefore, it is necessary to study the influence of the horizontal well pattern adopted for hydrate mining on the stability of submarine slopes. First, a triaxial mechanical experiment of gas hydrate-containing sediments was carried out, and the mechanical parameters of the hydrate-containing sediments were obtained. Second, a thermal-fluid-solid multifield coupling model considering the hydrate phase transition during the production process was established. Finally, on the basis of the finite element strength reduction method, a slope stability evaluation model for hydrate extraction from a horizontal well pattern was established, and the influence of hydrate extraction from horizontal wells on the stability of submarine slope was analyzed. The results show that the peak strength, elastic modulus and cohesion of gas hydrate-containing sediments increase with increasing hydrate saturation. In the process of hydrate exploitation via horizontal wells, with the reduction in well spacing and the increase in the number of production wells, the risk of slope instability increases. Wells positioned along the slope strike are more conducive to slope stability than those positioned perpendicular to the slope strike. The slope stability increases gradually as the slope dip decreases. When the number of wells is the same, the slope stability increases gradually with increasing well spacing and production pressure. [ABSTRACT FROM AUTHOR]

Two wells, the well Long-XX and the well Ning-XX, in Longdong area are recently tested, and the target zone located in the bauxite formation has been found an important alternative resource for the Changqing Oilfield. Significant findings were obtained in exploring the bauxite formation through these two wells. Technical difficulties, such as prevailing of dissolution pores and fractures, borehole wall collapse, mud losses and poor hole cleaning etc. have been encountered in drilling the target bauxite formation. The main factors contributing to borehole wall collapse were found in analyzing and testing the bauxite samples for physical properties, chemical properties, mechanical properties and sensitivity characteristics, and a fast-plugging, inhibitive drilling fluid for safe drilling of the bauxite formation was developed. This drilling fluid has high temperature (170 ℃) high pressure filter loss of less than 10 mL and percent secondary cuttings recovery of greater than 91%. After soaking the bauxite samples in the drilling fluid and fresh water respectively for 15 days, the compressive strength of the samples tested in the drilling fluid is 81.8% higher than that of the samples tested in the fresh water. This drilling fluid has been tried in drilling the first horizontal Long-4XX well targeted the bauxite reservoir in Changqing, a horizontal section of 700 m was successfully drilled. The daily flowing production rate of this well is 3.53 × 106 m³, a new record made in developing the upper Paleozoic resources in the Erdos basin in the last 50 more years. This technology has provided a technical support to the development of the similar reservoirs. [ABSTRACT FROM AUTHOR]

Horizontal well fracturing technology is an important way to improve the oil recovery efficiency of low-permeability reservoirs. Aiming at a certain test area on the edge of Daqing oilfield, a simulation conceptual model is established using CMG reservoir numerical simulation software. The influence of engineering parameters such as the number of fracture clusters, fracture half-length, fracture permeability, production pressure difference on the peak daily oil production is analyzed. Moreover, the gray correlation method is used to analyze the influence of the above factors on the peak daily oil production. Using key factors as variables in the regression model, a mathematical prediction model for daily oil production peak is established. The findings should make an important contribution to the oil production peak prediction. [ABSTRACT FROM AUTHOR]

The application of hydraulic oscillator can solve the problems of large friction and serious pressure support in the drilling process of extended reach well and long horizontal well, but the conventional hydraulic oscillator parameter setting is not reasonable, high pressure consumption, easy to make the ground machine pump overload operation and failure. Therefore, based on the LuGre dynamic friction model theory, a calculation model for the friction between drill string and rock wall under the condition of longitudinal oscillation is established, and the influence law of hydraulic oscillator oscillation parameters on drag reduction efficiency is studied. The results show that the change of oscillation intensity, oscillation frequency and oscillation amplitude can improve the drag reduction efficiency, and the increase trend of drag reduction efficiency is first increased and then decreased. The selection of each parameter has the optimal value. According to the analysis of orthogonal test results, it is found that the reduction degree of friction between drill string and borehole wall rock by each parameter is in the order of oscillation intensity, oscillation frequency and oscillation amplitude from the largest to the smallest. [ABSTRACT FROM AUTHOR]

The transient temperature of the wellbore plays an important role in the selection of downhole tools during the drilling of deep shale gas horizontal wells. This study established a transient temperature field model of horizontal wells based on the convection heat transfer between wellbore and formation and the principle of energy conservation. The model verification shows that the root mean squared error (RMSE) between the measured annular temperature neat bit and the predicted value is 0.54 °C, indicating high accuracy. A well in Chongqing, China, is taken as an example to study the effects of bottom hole assembly (BHA), drill pipe size, drilling fluid density, flow rate, inlet temperature of drilling fluid, and drilling fluid circulation time on the temperature distribution in wellbore annulus. It is found that the increase in annular temperature is about 1 °C/100 m in the horizontal section when a positive displacement motor (PDM) is used. A Φ139.7 mm drill pipe is more favorable for cooling than Φ139.7 mm + Φ127 mm drill pipe. Reducing drilling fluid density and flow rate and inlet temperature is beneficial to reduce bottom hole temperature. Bit-breaking rock, bit hydraulic horsepower, and drill pipe rotation will increase the bottom hole temperature. The research results can provide theoretical guidance for temperature prediction, selection of proper drill tools, and adjustment of relevant parameters in deep shale gas horizontal wells. [ABSTRACT FROM AUTHOR]

The efficient development of tight gas reservoirs is significantly enhanced by multi-stage and multi-cluster fracturing techniques in conjunction with horizontal well technology, leading to substantial increases in reservoir drainage volume and individual well productivity. This study presents a tailored fine-fracturing approach for horizontal wells in tight gas reservoirs, supported by a gas–water two-phase numerical simulation model. Utilizing the orthogonal experimental design method, we simulated and optimized various fracture distribution schemes to refine fracturing parameters for maximum efficiency. The optimization was further validated through a comparison with actual well completion and development dynamics. The quantitative results highlight the optimal fracture distribution for horizontal wells, with a horizontal section length of 1400 to 1600 m and 14 to 16 fracturing stages. The pattern features a "dense at both ends and sparse in the middle" strategy, with stage spacing of 80 to 110 m, and a "longer in the middle and shorter at both ends" fracture half-length of 100 to 140 m, achieving a fracture conductivity of 30 μm2·cm. To ensure the economic feasibility of the proposed fracturing strategy, we conducted an economic evaluation using the net present value (NPV) method, which confirmed the robustness of the optimization outcomes in terms of both technical performance and economic viability. The reliability of these optimization outcomes has been confirmed through practical application in the development of horizontal wells in the study area. This research approach and methodology can provide theoretical guidance for the design of hydraulic fracturing operations and the integration of geological and engineering practices in similar unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

This paper presents an integrated approach to investigate the impact of well spacing on the performance of tight oil and gas reservoirs depleted by advanced multi-stage hydraulic fracture in horizontal wellbores distributed parallelly in rectangular drainage areas. Thus, an analytical models has been developed considering different reservoir configurations and the associated flow rate, cumulative production, ultimate recovery has been recorded. Also, the pressure behavior for early stages of production conditions and the flow regime dominated by boundary effects has been analyzed. The results indicate that well spacing significantly impacts reservoir performance, particularly at late production stages and that well interference and an ee of well spacing optimization in tight oil and gas reservoirs, offering valuable insights for the strategic planning and development of these vital resources. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Experiment is the property of Petroleum Geology & Experiment Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)