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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]

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]

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]

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]

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]

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]

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]

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]

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]

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]

Bohai X oilfield has reached the extra-high water cut stage of more than 95%, dominated by the bottom water reservoir. The oilfield mainly adopts horizontal-well exploitation, with the characteristics of high difficulty and low success rate for well water plugging. To solve the above problem, the segmented production technology of horizontal wells was developed to guide oilfield applications and tap their potential. In the segmented design stage, the horizontal section is objectively segmented by drilling condition analysis, optimally based on drilling through interlayers or permeability discrepancy formation, simultaneously combined with the numerical simulation method. When implementing measures, annulus chemical packer materials are squeezed between segments to effectively inhibit the fluid flow between the open hole and the sand-packing screen pipe. Moreover, the packers are used to seal between segments to effectively restrain the flow between the screen and the central tube, achieving the establishment of compartments. In the production process, the valve switch on the central tube can be independently controlled by a remotely adjustable method to achieve optimal production. This segmented production technology was successfully tested for the first time in Bohai oilfield. Up to now, a total of six compartment measures have been implemented, remarkably decreasing water cut and increasing oil production for horizontal wells in the bottom water reservoir. This method does not require water testing, and the optimal production section can be chosen through segmented independent production, greatly improving the success rate of water-plugging measures for horizontal wells. This technology opens up a new mode for the efficient development of horizontal wells in bottom water reservoirs and is planned to be widely promoted and applied in similar oilfields. [ABSTRACT FROM AUTHOR]

A 3D vertical seismic profiling (VSP) survey was acquired using a distributed acoustic sensing (DAS) system in the Permian Basin, West Texas. In total, 682 shot points from a pair of vibroseis units were recorded using optical fibers installed in a 9000 ft (2743 m) vertical part and 5000 ft (1524 m) horizontal reach of a well. Transmitted and reflected P, S, and converted waves were evident in the DAS data. From first-break P and S arrivals, we found average P-wave velocities of approximately 14,000 ft/s (4570 m/s) and S-wave velocities of 8800 ft/s (3000 m/s) in the deep section. We modified the conventional geophone VSP processing workflow and produced P–P reflection and P–S volumes derived from the well's vertical section. The Wolfcamp formation can be seen in two 3D volumes (P–P and P–S) from the vertical section of the well. They cover an area of 3000 ft (914 m) in the north–south direction and 1500 ft (460 m) in the west–east direction. Time slices showed coherent reflections, especially at 1.7 s (~11,000 ft), which was interpreted as the bottom of the Wolfcamp formation. Vp/Vs values from 2300 ft (701 m) –8800 ft (2682 m) interval range were between 1.7 and 2.0. These first data provide baseline images to compare to follow-up surveys after hydraulic fracturing as well as potential usefulness in extracting elastic properties and providing further indications of fractured volumes. [ABSTRACT FROM AUTHOR]

Proppant transport and distribution law in hydraulic fractures has important theoretical and field guidance significance for the optimization design of hydraulic fracturing schemes and accurate production prediction. Many studies aim to understand proppant transportation in complex fracture systems. Few studies, however, have addressed the flow path mechanism between the transverse fracture and horizontal well, which is often neglected in practical design. In this paper, a series of mathematical equations, including the rock elastic deformation equation, fracturing fluid continuity equation, fracturing fluid flow equation, and proppant continuity equation for the proppant transport, were established for the transverse fracture of a horizontal well, while the finite element method was used for the solution. Moreover, the two-dimensional radial flow was considered in the proppant transport modeling. The results show that proppant breakage, embedding, and particle migration are harmful to fracture conductivity. The proppant concentration and fracture wall roughness effect can slow down the proppant settling rate, but at the same time, it can also block the horizontal transportation of the proppant and shorten the effective proppant seam length. Increasing the fracturing fluid viscosity and construction displacement, reducing the proppant density and particle size, and adopting appropriate sanding procedures can all lead to better proppant placement and, thus, better fracturing and remodeling results. This paper can serve as a reference for the future study of proppant design for horizontal wells. [ABSTRACT FROM AUTHOR]

The effectiveness of horizontal well drilling in improving the gas recovery efficiency of hydrate production makes it a promising technology for commercial exploitation. However, during horizontal well drilling in hydrate reservoirs, it is crucial to control hydrate dissociation to ensure the reservoir stability and drilling safety. In this work, a two-dimensional model using polar coordinates was built to study the influences of hydrate reservoir characteristics and drilling fluid salinity on gas production. The simulation applies to the hydrate reservoir of the second natural gas hydrate (NGH) production test in the Shenhu area of the South China Sea. The characteristics of hydrate dissociation and secondary formation and the drilling invasion behavior in the NGH layer and the mixing layer (free gas + hydrate) during horizontal well drilling were analyzed and compared. The simulation results indicated that the pressure and temperature transmission rates in the mixing layer (free gas + hydrate) are higher than those in the NGH layer. The invasion amount of drilling fluid in the mixing layer is 18.8 times more than that in the NGH layer. Under the high invasion of the drilling fluid, the hydrate dissociation amount in the mixing layer is similar to that of the NGH layer even though the initial hydrate saturation of the NGH layer was 2.65 times that of the mixing layer. The area of the hydrate dissociation in the mixing layer is much larger than that in the NGH layer, which may lead to the increase in risk of wellbore instability. The secondary hydrate formation is only observed in the NGH layer, which inhibits the drilling fluid invasion. The salinity of the drilling fluid has a more significant impact on the hydrate dissociation near the wellbore in the mixing layer compared to the NGH layer. With the increase in salinity from 3.05 wt% to 20 wt%, the hydrate dissociation range in the mixing layer increases from 0.16 m to 0.23 m, while the hydrate dissociation range in the NGH layer does not significantly change. [ABSTRACT FROM AUTHOR]

There are many natural fractures in shale reservoirs, changes in hydraulic fracture extension patterns. In the paper, a multi-fracture extension finite element model for horizontal wells in shale reservoirs under the disturbance of natural fractures is established by combining the actual geological parameters and construction parameters of a horizontal well multi-fracturing operation in X oilfield to analyze the effects of the difference in geostress, elastic modulus, angle of natural fractures, and the number of natural fracture groups on the hydraulic fracture extension. The results show that with the increase in ground stress difference and natural fracture angle, hydraulic fractures are more likely to penetrate the natural fractures; with the increase in elastic modulus, the fracture stress and tip stress increase, the volume of rupture unit, the fracture extension width and the pore pressure concentration area decrease, and it is easy to form a long and narrow fracture; with the increase in the number of fracture groups, the connectivity of reservoir fractures increases, the extension of fractures is stronger, and it is easier to form a complex fracture network. [ABSTRACT FROM AUTHOR]

Multilayered reservoirs with coexisting free gas and hydrates are primary targets for commercialization, nevertheless, the extremely low permeability greatly limits their extraction efficiency. Herein, multilayer commingled production using horizontal wells stimulated by hydraulic fracturing and thermal fluid injection was proposed to enhance productivity, and the effects of key factors on co-production performance were numerically examined, with the reservoir located in the Shenhu Area as the geological background. The results indicated that due to severe interlayer contradictions, the stimulation capabilities of using fracturing or thermal fluid injection alone were limited, in particular, the extraction of hydrates severely lagged behind. However, their combination exhibited tantalizing productivity due to strengthened inter-well interaction. Reducing the fracture spacing was more effective than increasing fracture conductivity in shortening the production cycle, and intensive fractures with adequate flow capacity were suggested for gas enhancement and water control. When the fracture spacing was reduced from 30 to 5 m and the fracture conductivity increased from 10 to 100 D·cm, the horizontal section length for commercial production (average daily gas production of 50,000 m3 and recovery ratio of 0.7) was reduced from 1758 to 146 m, which is lower than the on-site horizontal section length of 250–300 m. Therefore, the proposed development mode is promising for the commingled production of gas and hydrates. [ABSTRACT FROM AUTHOR]

As global oil demand continues to increase, in recent years, countries have continued to expand the development of oil reserves, highlighting the importance of oil. In order to adapt to different strata distribution conditions, domestic drilling technology is becoming more and more perfect, resulting in a gradual increase in horizontal and inclined wells. Because of the influence of various downhole factors, the flow pattern in the wellbore will be more complex. Accurately identifying the flow pattern of multiphase flow under different well deviation conditions is very important to interpreting the production log output profile accurately. At the same time, in order to keep up with the footsteps of artificial intelligence, big data and artificial intelligence algorithms are applied to the oil industry. This paper uses the GA-BP neural network and random forest algorithm to conduct fluid flow pattern prediction research on the logging data of different water cuts at different inclinations and flow rates. It compares the predicted results with experimental fluid flow patterns. Finally, we can determine the feasibility of these two algorithms for predicting flow patterns. We use the multiphase flow simulation experiment device in the experiment. During the process, the flow patterns are observed and recorded by visual inspection, and the flow pattern is distinguished by referring to the theoretical diagram of the oil-water two-phase flow pattern. The prediction results show that the accuracy of these two algorithms can reach 81.25% and 93.75%, respectively, which verifies the effectiveness of these two algorithms in the prediction of oil–water two-phase flow patterns and provides a new idea for the prediction of oil–water two-phase flow patterns and other phases. [ABSTRACT FROM AUTHOR]

Natural gas is an eco-friendly energy source with low carbon emissions, making it attractive globally. Understanding gas reservoirs is crucial for sustainable extraction and optimizing potential. However, the complicated fluid flow and production dynamics within intricate gas reservoirs, particularly those characterized by abnormally high pressures and tight porous media, remain partially understood and demand further investigation. In a tight porous medium subjected to high pressure, the assumption of constant permeability is no longer valid. Consequently, a novel composite seepage model has been developed in this study, which considers the responsiveness of permeability to stress. Perturbation theory is employed to address the inherent non-linearity demonstrated by the permeability modulus. The solution of dimensionless pressure responses under constant production conditions is accomplished in the Laplace domain by implementing integral transformation methods. Overall, a comprehensive model is provided to understand the production behaviors of tight gas reservoirs. Moreover, in order to comprehend the transient flow characteristics of tight gas reservoirs, log–log plots are generated through the Stehfest numerical inversion approach, with the flow regimes categorized based on the normalized time phases of the pressure curves. Parametric investigations reveal that stress sensitivity detrimentally affects permeability, resulting in more pronounced pressure declines during the intermediate and late flow phases. The transient seepage model elaborated in this study is able to consider the pertinent formation and well parameters. These interpreted parameters bear significance in designing hydraulic fracturing operations, assessing the potential of tight gas reservoirs, and ultimately enhancing gas production. The presented model not only enhances our understanding of the behavior of horizontal wells in stress-sensitive tight gas reservoirs but also makes a valuable contribution to the broader discussion on transient flow phenomena in petroleum engineering. [ABSTRACT FROM AUTHOR]

The prediction and optimization of the rate of penetration (ROP) for horizontal wells are more complicated than for vertical wells, but most of the current ROP prediction studies are for vertical wells, which cannot be adapted to the complex drilling characteristics of horizontal wells. To this end, this paper proposes a data knowledge dual-driven horizontal well ROP prediction method. Firstly, the drilling characteristics of horizontal wells are analyzed, showing that the horizontal wells ROP prediction model cannot be modeled using surface measurement data; secondly, based on the analysis of horizontal well drilling characteristics, a physical model-based horizontal well ROP modeling data pre-processing method is proposed by introducing the drag and torque model. Finally, a data knowledge dual-driven horizontal well ROP prediction method is proposed in conjunction with data-driven algorithms. The proposed horizontal well ROP prediction method is applied to the A1~A4 wells in the Sichuan area. Compared with the conventional data-driven ROP prediction method, the prediction accuracy of this method is improved by 30%. The proposed method can provide a basis for the intelligent optimization and management of ROP during the drilling of horizontal wells. [ABSTRACT FROM AUTHOR]

This publication discusses the experiments and findings of project ROCCS (Establishing a Research Observatory to Unlock European Coal Seams for Carbon Dioxide Storage), which aimed to investigate the potential for carbon dioxide storage in coal seams. The project involved large-scale ex situ laboratory tests, where CO2 was injected into an experimental coal seam using a high-pressure reactor at the Central Mining Institute in Poland. The reactor simulated underground conditions, and the experimental coal seam measured 3.05 m in length with a cross-section of 0.4 × 0.4 m. Parameters such as gas flow, temperatures, and pressures were monitored during the experiments. In the study conducted, the sorption capacity of coal from the Polish mine "Piast-Ziemowit" for CO2, at a sorption pressure of 30 bar, was determined to be 4.8% by weight relative to the raw coal mass. The data collected from these ex situ tests can support the design of a potential commercial-scale CO2 storage installation. [ABSTRACT FROM AUTHOR]

Employing multi-stage fracturing technology in horizontally accessed wells is a well-known way to successfully develop shale reservoirs. The interaction between natural fractures and hydraulic fractures has a significant impact on the fracturing effect. In this study, a coupled model of rock deformation and fluid flow was established using the cohesive zone method to simulate the propagation of hydraulic fractures under the synergistic effect of natural fractures and wellbore interference. The influence of in situ stress, fracture spacing, the number of fracture clusters, and the fracturing methods on the formation of fracture networks was analyzed. Studies on the fracture morphology and connectivity of fracture networks show that when the in situ stress difference is small, multiple fractures can easily form, and when the in situ stress difference is large, they can easily gather into a single fracture. An excessive reduction in fracture spacing may impede the optimal propagation and interconnection of hydraulic fractures. The findings reveal that augmenting the fracture spacing from 5 m to 8 m results in a significant 15.59% increase in the overall extent of fracture propagation. Moreover, it also adds to the complexity of the fracture network. Increasing the number of hydraulic fracturing clusters can improve the fracture length and fracture propagation complexity. When the number of fracturing clusters increased from two clusters to five clusters, the maximum fracture propagation width increased by 25.23%. Comparing sequential fracturing and simultaneous fracturing, the results show that simultaneous fracturing can form a more complex fracture network with better connectivity, which is conducive to increasing oil and gas production. The obtained results can provide a reference for horizontal well fracturing designs of shale reservoirs. [ABSTRACT FROM AUTHOR]

Frequent accidents may happen during the string run-down and pull process due to the lack of accuracy in the prediction of string force analysis. In order to precisely predict the completion string axial force in horizontal wells, a new model is established, and an in-house software has been developed. The model aims to predict the multiple local resistances that occur at different points on the completion string, which makes up for the technical defects of the commonly used software. It can calculate resistance at different points of the string, which will lead to varying hook load amplification. This method can also predict the axial force of the completion string. By changing the hook load, location, and direction, the resistance can be determined more accurately. Based on the calculation and analysis, the relationship between local resistance, the blocking point, and the amplification factor is also obtained. Furthermore, this model is used to analyze the local resistance of a horizontal well with multiple external packers in the low-permeability Sadi Reservoir of Halfaya Oilfield, Iraq. The recorded data from in-site operations are compared with the predicted results from this model. The results show that the relative errors between the recorded data and model calculation are within the range of 10%, which indicates that the calculated values are reliable. Meanwhile, the results indicate the success of the subsequent completion design and the construction of the oilfield. [ABSTRACT FROM AUTHOR]

The accurate prediction of wellbore temperature and pressure is important for safe drilling. However, annulus temperature and pressure changes are more complicated due to phase transition. To study this problem, a prediction model of temperature and pressure in deep water riserless drilling is established by considering hydrate cuttings decomposition, interphase mass transfer, and phase transition heat. Based on this model, the effects of hydrate cuttings decomposition on the temperature and pressure of drilling in a hydrate reservoir are explored. The results show that the influence of hydrate cuttings decomposition increases significantly with an increase in the inlet temperature. The influence of hydrate cuttings decomposition on temperature and pressure decreases with an increase in displacement. A small range in the variation of density and penetration rates has little impact on the annulus pressure but mainly affects the temperature. The influence of hydrate cuttings decomposition increases with an increase in the penetration rate. In normal drilling conditions, hydrate cuttings decomposition has little impact on annulus temperature and pressure, but under the conditions of a high inlet temperature, high hydrate saturation, low displacement, and high penetration rate, it is necessary to consider the impact of hydrate cuttings decomposition. This study can provide reference for the prediction of temperature and pressure in deep water hydrate reservoir riserless drilling. [ABSTRACT FROM AUTHOR]

Due to variables like wellbore deviation variation and flow rate, the local flow velocity in the output wellbore of horizontal shale oil wells varied significantly at various points in the wellbore cross-section, making it challenging to calculate the total single-layer production with accuracy. The oil–water two-phase flow rate calculation techniques for horizontal wells developed based on particular flow patterns and array spinners had excellent applicability in their respective niches but suffered from poor generalizability and demanding experience levels for logging interpreters. In this study, we employed five spinners in a triangular walled array instrument to create the multi-decision tree after figuring out how many leaf nodes there were and examining the defining characteristics of the observed values gathered under various experimental setups. The construction of the entire oil–water two-phase flow prediction model was made possible when the random forest regression approach was used with it. The total oil–water flow rate at each perforated layer was predicted using the model in sample wells, and the mean square error with the third party's interpretation conclusion was 1.42, indicating that the model had an excellent application effect. The approach, which offered a new interpretation method for calculating the oil–water two-phase flow rate of horizontal wells based on multi-location local flow rate, required less interpretation knowledge from the interpreter and had a stronger generalization capacity. [ABSTRACT FROM AUTHOR]

A conventional oil and gas well does not have a natural production capacity, which necessitates a hydraulic fracturing operation. The effectiveness of the fracturing directly impacts the economic benefit of a single well. Among the various parameters, including fracture spacing, fracture width, and conductivity, fracture half-length is one of the main influencing factors on the productivity of horizontal wells. For conventional homogeneous reservoirs, research mainly focuses on fracture patterns with equal fracture lengths. However, in actual production processes, due to mutual interference and the superimposition of drainage areas between fractures, the production distribution of each fracture is non-uniform. Typical fracture distribution patterns mainly include uniform, staggered, dumbbell, and spindle. While many believe that the dumbbell-shaped fracture distribution pattern has the best effect, there has been no quantitative study on the length of each fracture under the dumbbell-shaped pattern. Based on this, this paper proposes a modeling approach for function-shaped fracture distribution that takes advantage of the high production of edge fractures and the low output of middle fractures in horizontal wells. The influence of this approach on production capacity is studied. Constant, linear, and parabolic functions are used to establish the relationship between fracture position and fracture half-length, optimizing the fracture distribution function to achieve the best production effect. This method can guide the horizontal well fracture distribution in the block to maximize productivity. The results show that the parabolic function-shaped model is better than the linear function-shaped model and the constant function-shaped model is the least effective. The research presented in this paper offers a new idea for optimizing on-site fracturing plans. It utilizes mathematical expressions to describe the parameters that affect productivity, which provides valuable guidance for designing multi-stage fractured horizontal wells in the field. In the future, this research will be extended by exploring the optimal fracture distribution function under different formation conditions. [ABSTRACT FROM AUTHOR]

Heavy oil reservoirs are often characterized by high viscosity and poor mobility, which is more complex with the presence of bottom water. The conventional vertical well development method has low oil recovery efficiency and limited controlled reserves of a single well. In addition, water cut can increase dramatically when the edge-bottom water breaks through. Horizontal well and CO2 huff-n-puff is an effective alternative development model for heavy oil reservoirs. This development method makes efficient use of CO2 and accords with the "Carbon Capture, Utilization, and Storage (CCUS)". The horizontal well can increase the drainage area. The dissolution of CO2 improves the mobility of crude oil and increases formation energy. In this paper, we established numerical simulation models based on the Liuguanzhuang oilfield in Dagang. The characteristics and producing rules of the horizontal well and CO2 huff-n-puff development in the heavy oil reservoir were studied. The results show that the production characteristics of horizontal well and CO2 huff-n-puff were similar to Steam-Assisted Gravity Drainage (SAGD). CO2 forms a viscosity reduction area above the horizontal well and the heavy oil flows into the wellbore due to gravity after viscosity reduction. The CO2 huff-n-puff can effectively enhance the production area of horizontal wells compared with the depletion development. However, the improvement in the production area gradually decreased as CO2 huff-n-puff cycles continued. There was a boundary of production area against the horizontal well, with the main production of heavy oil occurring at the upper and either end of the horizontal well. The CO2 huff-n-puff has a restraining effect on the edge-bottom water, which is confirmed via the proposed theoretical model. [ABSTRACT FROM AUTHOR]

The failure of wellbore sealing will cause leakage of greenhouse gases, such as carbon dioxide and methane, which will harm oil and gas recovery and environmental safety. Cementing is an important part of wellbore sealing. Only good cementing can keep the wellbore seal for a long time and improve the well life. In this study, we considered the construction of a horizontal shale oil well in eastern China as the background and analysed the rheological properties of the annulus fluid. We developed a displacement motion model and a calculation model for the annulus dynamic equivalent circulation density, and numerical simulations were used to study the impact of the dosage and injection sequence of the pad fluid on the displacement efficiency and annulus dynamic equivalent circulation density. The results show that when the pad fluid is composed completely of flushing fluid, the displacement performance is better than that of the spacer. By increasing the dosage of the flushing fluid from 0.3 times the annular volume to 1.0 times, the displacement efficiency can be increased by 3.3%, and the retention of the drilling fluid is also reduced by 3.6%. However, it can lead to a significant reduction in the annulus dynamic equivalent circulation density and increase in the risk of leakage. After adding the spacer, the structure of the flushing fluid–spacer provides the optimal injection sequence. Considering the application status in the field example well, it was shown that it can not only ensure the safety of cementing operations, but also improve the displacement efficiency. The results of this study have important theoretical significance and application value and can provide guidance for the optimisation design of the engineering scheme. [ABSTRACT FROM AUTHOR]

The use of Horizontal wells is a common method of underground natural gas storage (UGS), but there is still a need to discuss whether they are more suitable for slotted liner or perforation completions. To address this issue, a numerical model is developed to predict the gas injection rate of horizontal wells while considering the skin factor. Here, a novel uncoupled iteration method is employed to determine the skin factor deriving from turbulence in each time step when the bottom hole pressure is fixed. The uncoupled method begins with an estimate of the initial gas injection rate, which is then used to calculate a turbulent skin factor. This turbulent skin factor is then used to update the gas injection rate, iterating continuously until convergence is achieved. The effects of slotted liner and perforation design parameters, formation damage, and injection pressure on the skin factor are analyzed. The main findings suggest that the error in the gas injection rate calculated by the non-coupled model compared with the coupled model is only 0.6%, yet it can reduce the number of sub-iterations to 1/10 of that required by the coupled model. Moreover, the uncoupled model can provide results within four steps, even when the convergence condition is 10−14. The open area and perforation density play a significant role in determining the connection degree between the horizontal well and the reservoir, with a larger perforation density resulting in a negative skin factor. Perforations are more suitable than slotted liners for reservoirs with severe formation damage, and the difference in skin factor between the two can reach a value of 40.87 when the ratio of the damage zone's permeability to that of the normal reservoir zone is 0.05. It is easier to reduce turbulence damage in slotted liner completions than perforation completions, with the turbulence damage of the slotted liner being only 15.9% of that of the perforation. However, to avoid damage it is crucial to prevent the screen tube from being plugged in, as it might otherwise rise to three to ten times the original level. This study provides a theoretical basis and practical reference for the application of slotted liner and perforation method in UGS horizontal wells. [ABSTRACT FROM AUTHOR]

Deep un-mineable coal deposits are viable reservoirs for permanent and safe storage of carbon dioxide (CO2) due to their ability to adsorb large amounts of CO2 in the microporous coal structure. A reduced amount of CO2 released into the atmosphere contributes in turn to the mitigation of climate change. However, there are a number of geomechanical risks associated with the commercial-scale storage of CO2, such as potential fault or fracture reactivation, microseismic events, cap rock integrity or ground surface uplift. The present study assesses potential site-specific hydromechanical impacts for a coal deposit of the Upper Silesian Coal Basin by means of numerical simulations. For that purpose, a near-field model is developed to simulate the injection and migration of CO2, as well as the coal-CO2 interactions in the vicinity of horizontal wells along with the corresponding changes in permeability and stresses. The resulting effective stress changes are then integrated as boundary condition into a far-field numerical model to study the geomechanical response at site-scale. An extensive scenario analysis is carried out, consisting of 52 simulation runs, whereby the impacts of injection pressures, well arrangement within two target coal seams as well as the effect of different geological uncertainties (e.g., regional stress regime and rock properties) is examined for operational and post-operational scenarios. The injection-induced vertical displacements amount in maximum to 3.59 cm and 1.07 cm directly above the coal seam and at the ground surface, respectively. The results further demonstrate that neither fault slip nor dilation, as a potential consequence of slip, are to be expected during the investigated scenarios. Nevertheless, even if fault integrity is not compromised, dilation tendencies indicate that faults may be hydraulically conductive and could represent local pathways for upward fluid migration. Therefore, the site-specific stress regime has to be determined as accurately as possible by in-situ stress measurements, and also fault properties need to be accounted for an extensive risk assessment. The present study obtained a quantitative understanding of the geomechanical processes taking place at the operational and post-operational states, supporting the assessment and mitigation of environmental risks associated with CO 2 storage in coal seams. [ABSTRACT FROM AUTHOR]

With the advancement of completion technology for horizontal wells in bottom water reservoirs, Autonomous Inflow Control Devices (AICDs), which have achieved good results in recent years, have been widely used in the oil fields of the eastern South China Sea. Although some mathematical methods can be used to predict the production performance of horizontal wells, there is no dynamic prediction method for the production performance of horizontal wells completed with AICDs. In this work, a mathematical model of porous flow in the reservoir, nozzle flow in the AICD, and pipe flow in the horizontal well is established, and then a new model is presented for predicting the dynamic performance of horizontal wells completed with AICDs in bottom water reservoirs. The new coupling model is compared with two horizontal wells completed with AICDs in the bottom water reservoirs of the eastern South China Sea, and the results indicate that the accuracy of the new model is sufficiently high to provide theoretical support for the further prediction of horizontal wells in the eastern South China Sea. [ABSTRACT FROM AUTHOR]

To better understand the horizontal well transient productivity in the bottom-water reservoir with finite water bodies, the horizontal well transient productivity model for the bottom-water reservoir with finite water-body multiple was developed using Green's function and potential superposition method. Laplace transforms, Fourier transforms, superposition of point source, and Duhamel principle were used to obtain the transient productivity of the horizontal well, and the transient productivity of the horizontal well in real space was obtained by the Stehfest numerical inversion method. The typical pressure response curve and dimensionless productivity curves were plotted. The effects of the water-body multiple, the distance between the horizontal well and oil–water contact, and the skin factor, were analyzed. Six main flowing stages were divided for horizontal wells in the bottom-water reservoir with finite water bodies. When the water body multiples are zero or tend to infinity, the results obtained from the model are consistent with the calculations by the conventional top-bottom closed reservoir model or infinite rigid bottom-water reservoir model, respectively, and the pressure dynamic for the finite water body falls in between both. With the increase in the water body multiples and the decrease in distance between the horizontal well and the oil–water contact, and the horizontal well productivity decreases slowly. With the increase in the skin factor, the initial productivity decreases; moreover, the skin factor has a great influence on the initial productivity of the horizontal well, while the later influence gradually decreases. Accurate horizontal well productivity prediction in the bottom-water reservoir with finite water bodies provides a strong basis for horizontal well deployment, design optimization, and formulation of development policy. [ABSTRACT FROM AUTHOR]

Horizontal wells with extended lateral lengths and large-scale hydraulic fracturing are a key technology for shale gas development. Lateral length is the key factor in determining the production and economic benefits of horizontal wells. Therefore, based on geology–engineering–economy integration, a method for optimizing the lateral length of shale-gas horizontal wells is established. Through fracture-shape prediction, productivity simulation and input–output analysis, the net present-value model of the technical–economic evaluation of the economic lateral length is established. A comprehensive evaluation of lateral lengths in Changning Block is then conducted. The results show that, under the current geological, engineering, and economic conditions in Changning Block, a horizontal well with a lateral length between 175 m and 3508 m is economically viable, and the optimal economic lateral length is 2000 m. The porosity and thickness of the reservoir matrix, the production time, the drilling investment, and the price of the natural gas wellhead in the first year have a great impact on the economic lateral length. On one hand, we can increase the drilling rate by increasing the technical research and development efforts. On the other hand, we can improve the construction management level to reduce investment and reasonably increase the price subsidy to optimize the lateral length of shale-gas horizontal wells. [ABSTRACT FROM AUTHOR]

During drilling in deep shale gas reservoirs, drilling fluid losses, hole wall collapses, and additional problems occur frequently due to the development of natural fractures in the shale formation, resulting in a high number of engineering accidents such as drilling fluid leaks, sticking, mud packings, and buried drilling tools. Moreover, the horizontal section of horizontal well is long (about 1500 m), and the problems of friction, rock carrying, and reservoir pollution are extremely prominent. The performance of drilling fluids directly affects drilling efficiency, the rate of engineering accidents, and the reservoir protection effect. In order to overcome the problems of high filtration in deep shale formations, collapse of borehole walls, sticking of pipes, mud inclusions, etc., optimization studies of water-based drilling fluid systems have been conducted with the primary purpose of controlling the rheology and water loss of drilling fluid. The experimental evaluation of the adsorption characteristics of "KCl + polyamine" anti-collapse inhibitor on the surface of clay particles and its influence on the morphology of bentonite was carried out, and the mechanism of inhibiting clay mineral hydration expansion was discussed. The idea of controlling the rheology and water loss of drilling fluid with high temperature resistant modified starch and strengthening the inhibition performance of drilling fluid with "KCl + polyamine" was put forward, and a high temperature-resistant modified starch polyamine anti-sloughing drilling fluid system with stable performance and strong plugging and strong inhibition was optimized. The temperature resistance of the optimized water-based drilling fluid system can reach 180 °C. Applied to on-site drilling of deep shale gas horizontal wells, it effectively reduces the rate of complex accidents such as sticking, mud bagging, and reaming that occur when resistance is encountered during shale formation drilling. The time for a single well to trip when encountering resistance decreases from 2–3 d in the early stages to 3–10 h. The re-use rate of the second spudded slurry is 100 percent, significantly reducing the rate of complex drilling accidents and saving drilling costs. It firmly supports the optimal and rapid construction of deep shale gas horizontal wells. [ABSTRACT FROM AUTHOR]

Projects that feature unconventional geothermal systems are complex and come at great investment risk and high project cost. The purpose of this work is to present a method for modelling an enhanced geothermal system (EGS) that utilizes a horizontal well-doublet setup. The proposed wells' positioning was to minimize one of the biggest cost factors: the flow rate. As a part of the research, a case study was conducted and a fully coupled EGS model prepared, based on the data from the Utah FORGE site. The model includes a discrete fracture network (DFN) that represents hydraulic fractures and a stimulated reservoir volume (SRV) for controlling the fractures' properties. The model's viability was checked by a series of reservoir simulations, which provided the results for sensitivity analysis of the production parameters. Analysis of the results was conducted based on the temperature decline over an EGS system lifetime, which is one of the primary indicators for EGS. The proposed solution allowed for effectively minimising the injection and production flow rate while maintaining reasonable temperature drawdown levels. It was proven that reservoir modelling and simulation tools, used in the oil and gas industry, can be successfully applied for modelling geothermal systems. [ABSTRACT FROM AUTHOR]

The application of horizontal well volume fracturing technology is an important method for enhancing oil recovery in tight oil reservoirs. However, the influence mechanism of the fracture placement scheme (FPC) on postfracturing productivity is still unclear. Based on the theory of the black oil model, combined with the reservoir stimulation characteristics of horizontal well volume fracturing in tight oil reservoirs, this paper established a postfracturing reservoir production simulation model. History fitting was used to verify the accuracy of the production model simulations. A series of numerical simulations was carried out to study the influence mechanisms of the fracture parameters and FPC on productivity. The simulation results show that compared with the fracture conductivity, the fracture length and number are the main parameters affecting tight oil reservoir productivity. Selecting a reasonable fracture length and number can realize the economical and efficient production of tight oil reservoir volume fracturing. Compared with the traditional fracture equal-length scheme, an FPC with an uneven fracture length can increase the cumulative oil production of oil wells. Under the condition of the same total fracture length, the scheme with a staggered distribution of long fractures and short fractures has the largest cumulative oil production over five years. A reasonable well spacing can greatly reduce the impact of interwell interference on postfracturing dual branch horizontal well productivity. When dual branch horizontal well fractures are alternately distributed, the postfracturing productivity is higher. The production simulation model established in this paper provides a method to accurately evaluate the productivity of horizontal wells after volume fracturing, which can provide guidance for the optimization of hydraulic fracturing operation parameters. [ABSTRACT FROM AUTHOR]

Inadequate drill cuttings removal can cause costly problems such as excessive drag, lower rate of penetration, and even mechanical pipe sticking. Cuttings bed height is usually used to evaluate hole-cleaning efficiency in horizontal wells. In this study, artificial intelligence models, including artificial neural network (ANN), support vector regression (SVR), recurrent neural network (RNN), and long short-term memory (LSTM), were employed to predict cuttings bed height in the well-bore. A total of 136 different tests were conducted, and cuttings bed height under different conditions were measured in our previous study. By training four different artificial intelligence models with the experiment data, it was found that the ANN model performed best among other artificial intelligence models. The ANN model outperformed the dimensionless cuttings bed height model proposed in our previous study. Due to the amount of data points, the memory ability of RNN and LSTM models has not been entirely played compared with the ANN model. [ABSTRACT FROM AUTHOR]

The largest Precambrian gasfield in China has been found in the central Sichuan Basin. It has been assumed as an Ediacaran (Sinian) mound–shoal, microfacies-controlled, dolomite reservoir. However, the extremely low porosity–permeability and heterogeneous reservoir cannot establish high production by conventional development technology in the deep subsurface. For this contribution, we carried out development tests on the fractured reservoir by seismic reservoir description and horizontal well drilling. New advances have been made in recent years: (1) the prestack time and depth migration processing provides better seismic data for strike-slip fault identification; (2) seismic planar strike-slip structures (e.g., en échelon/oblique faults) and lithofacies offset together with sectional vertical fault reflection and flower structure are favorable for strike–slip fault identification; (3) in addition to coherence, maximum likelihood and steerable pyramid attributes can be used to identify small strike-slip faults and for fault mapping; (4) fusion attributes of seismic illumination and structural tensor were used to find fractured reservoir along fault damage zone; (5) horizontal wells were carried out across the strike-slip fault damage zone and penetrated fractured reservoir with high production. Subsequently, a large strike-slip fault system has been found throughout the central intracratonic basin, and the "sweet spot" of the fractured reservoir along the strike-slip fault damage zone is widely developed to be a new favorable domain for high-production development. There is still a big challenge in seismic and horizontal well technology for the economical exploitation of the deep fractured reservoirs. This practice provides new insight in the deep tight matrix reservoir development. [ABSTRACT FROM AUTHOR]

To resolve the issues of the high porous medium flow resistance, low oil production rate, high oil decline rate, and low oil recovery factor for the cyclic steam stimulation (CSS) of horizontal wells in heavy oil reservoirs, the CSS method assisted by the electric heating (E-CSS) of horizontal wells was proposed in this study. Combining the heat from electric heating and steam during E-CSS, the analytical model of formation temperature rise was established for the three phases of electric-assisted CSS (i.e., injection, soaking, production), and physical experiments were carried out to compare the performance of conventional CSS and E-CSS. The experimental results were used to validate the analytical model and reveal the impact of the key electric heating mechanism on the horizontal CSS performance. Meanwhile, the typical well model was used to forecast the E-CSS potential. The results indicate that electric heating can achieve uniform heating in the steam injection phase, maintain heating around the wellbore in the soak phase, and reduce flow resistance and enhance oil output in the production phase. Forecasts of the typical well model indicate that electric heating can enhance the oil recovery factor by 9.4% and the oil-steam ratio from 0.14 to 0.23, implying a significant application potential in heavy oil reservoirs developed by horizontal CSS. [ABSTRACT FROM AUTHOR]

Existing fractured gas reservoir development techniques are mainly based on dual medium numerical-simulation models, which can, to a certain extent, effectively simulate natural fractures with high fracture density; however, these models have some limitations, particularly in terms of simulating the fracture morphology and distribution. Considering carbonate gas reservoirs with complex fractures, in this paper, we establish a numerical-simulation model of embedded discrete-fracture seepage in horizontal wells of carbonate gas reservoirs, in order to compare and study the development effect of carbonate gas reservoirs under different horizontal well fracture parameters. The fracture distribution and structure in carbonate gas reservoirs is obtained using an ant-tracking approach based on 3D seismic bodies, and a numerical-simulation model based on the embedded discrete-fractures model is solved using the open-source program MRST. We considered the following parameters: half fracture length, fracture permeability, and horizontal segment length. By changing the fracture parameters of horizontal wells and comparing the gas-production trends, technical optimization in gas reservoir development can be realized. The results show that the embedded discrete-fracture model can effectively solve the difficult problem of characterizing fluid seepage in fractures of different scale in carbonate gas reservoirs. Although gas production increases with increasing fracture length, fracture conductivity, horizontal section length, and natural fracture conductivity, the contributions of these parameters to gas well production capacity are greatly influenced by the natural fractures. [ABSTRACT FROM AUTHOR]

Mahu Oilfield is the largest tight glutenite oilfield in the world, and the upper Wuerhe formation is an important succeeding exploration horizon. However, the upper Wuerhe formation in the Mahu 1 zone has a high clay content, which can lead to serious wellbore collapse. Meanwhile, the horizontal well logging is not corrected. These factors lead to the inconsistency between the logging interpretation results and the oil test results. The interpretation precision of the clay content, water saturation, and porosity, which are crucial to reservoir evaluation, is very low. In this paper, a workflow of logging curve correction using multiple methods is proposed. The multiple linear fitting is used to correct boreholes, and then histogram frequency distribution matching is used to standardize multi-well logging curves. Finally, the optimization method is used to build a volume model based on skeleton analysis, and the results are calibrated with core analysis results. Horizontal well density logs are corrected using adjacent vertical well logs. The interpretation results of clay content, water saturation, and porosity with high precision are obtained. The reservoir interpretation is more in line with the oil test results than the original interpretation. The clay content distribution is more reasonable. [ABSTRACT FROM AUTHOR]

Horizontal well drills are difficult to operate and require high borehole cleaning operations. The impact of cuttings accumulation on friction and torque cannot be ignored. In the process of horizontal well drilling, it is very easy to form a cuttings bed in the highly inclined eccentric annulus. The formation of the cuttings bed will not only increase the friction torque but also have a greater impact on the annulus flow. Based on the application of gas drilling in horizontal wells, this paper uses laboratory experiments to study the influence of cuttings with different particle sizes and lithology on the friction coefficient between the drill string and the borehole wall of the horizontal well section. In addition, in view of the difficulty in the migration of cuttings in gas drilling horizontal wells and the formation of cuttings deposits, this paper carries out an experimental study on the effect of the cuttings bed on drill pipe coating height and cuttings bed thickness on friction coefficient. Experimental results show that the friction coefficient of gas drilling horizontal wells is about 0.44–0.58. When the coating height of the cuttings on the drill pipe exceeds a certain value (26 mm), the friction coefficient tends to be stable, but its value is as high as about 0.55. When the thickness of the accumulation of cuttings exceeds a certain value (10 mm), the subsidence hindering effect between the particles in the cuttings bed is weakened, so the friction coefficient of the casing section and the open hole section tends to be stable, about 0.53. [ABSTRACT FROM AUTHOR]

Horizontal well water coning in offshore fields is one of the most common causes of rapid declines in crude oil production and, even more critical, can lead to oil well shut down. The offshore Y oil field with a water cut of 94.7% urgently needs horizontal well water control. However, it is a challenge for polymer gels to meet the requirements of low-temperature (55 °C) gelation and mobility to control water in a wider range. This paper introduced a novel polymer gel cross-linked by hydrolyzed polyacrylamide and chromium acetate and phenolic resin for water coning control of a horizontal well. The detailed gelant formula and treatment method of water coning control for a horizontal well in an offshore field was established. The optimized gelant formula was 0.30~0.45% HPAM + 0.30~0.5% phenolic resin + 0.10~0.15% chromium acetate, with corresponding gelation time of 26~34 h at 55 °C. The results showed that this gel has a compact network structure and excellent creep property, and it can play an efficient water control role in the microscopic model. The thus-optimized gelants were successively injected with injection volumes of 500.0 m3. The displacement fluid was used to displace gelants into the lost zone away from the oil zone. Then, the formed gel can be worked as the chemical packer in the oil–water interface to control water coning after shutting in for 4 days of gelation. The oil-field monitoring data indicated that the oil rate increased from 9.2 m3/d to 20.0 m3/d, the average water cut decreased to 60~70% after treatment, and the cumulative oil production could obtain 1.035 × 104 t instead of 3.9 × 103 t. [ABSTRACT FROM AUTHOR]

To obtain local flow velocity and holdup for oil–water in a near-horizontal well, array probes were adopted in the cross section of the wellbore. In this study, a fluid flow imaging logging tool called the single-probe multi-position measurement fluid imager (SPFI) was developed, which consisted of only a single turbine flowmeter and a single capacitance holdup probe. Most importantly, it could collect local velocity and holdup information at different locations along the vertical direction of the wellbore diameter. Firstly, in the large-diameter multi-phase flow simulation test loop, the instrument was placed at five different positions along the wellbore cross section to perform simulated measurements in different wellbore deviation angles and oil–water flowrates. Secondly, the experiment data was analyzed, and the experiment flow pattern chart, instrument response coefficient, and rule of the instrument response were obtained. At the same time, the calculation methods of local holdup and local velocity were derived. Thirdly, by combining the interpolation algorithm, velocity imaging and holdup imaging were implemented, and the stratified flow model was used to calculate the flowrate of each phase. Finally, this study provides technology support for production profile data interpretation using the fluid flow imaging tool for oil–water in a near-horizontal well. [ABSTRACT FROM AUTHOR]

The application of hole cleaning devices can effectively solve the hole cleaning problem during the drilling of horizontal wells. Improving the hole cleaning performance is directly related to subsequent drilling time and cost. In this paper, the solid–liquid two-phase hydrodynamic characteristics under the action of the V-shaped hole cleaning device for drilling horizontal wells were studied experimentally and numerically. The decay law of spiral flow induced by the V-shaped hole cleaning device was obtained numerically using the commercial CFD code "Fluent" by changing the blade rotational speed, blade helix angle, and consistency coefficient of drilling fluid. The helix angle will cause the flow direction of local fluid to deflect. The swirl intensity of spiral flow increases significantly with an increase in rotational speed. The hole cleaning performance was better when the helix angle was from about 10 to 20 degrees. Increasing the fluid consistency coefficient will rapidly make the spiral flow decay, resulting in a shorter effective action distance and a worse hole cleaning effect. The simulation results were validated against the experimental results of the flow loop. Both experimental and simulation results showed that the hole cleaning performance was improved by using the V-shaped hole cleaning device. The very good agreement achieved between the results has presented an opportunity to study the hole cleaning effect of a hole cleaning device in unsteady state conditions. The results will provide theoretical guidance for efficient hole cleaning using V-shaped hole cleaning devices for horizontal well drilling. [ABSTRACT FROM AUTHOR]

The production profile logging technology of Oil-water two-phase flow is an important support technology for efficient development of horizontal oil wells. Moreover, the water holdup of Oil-water two-phase flow is one of the important dynamic measurement parameters for production profile logging technology. Flow patterns in horizontal oil wells are more complex than those in vertical oil wells, making water holdup measurements more difficult. In China, horizontal oil wells are characterized by low liquid production, high water cut and layered development; hence, the concentrating flow logging scheme is adopted to reduce the effects of flow patterns on measurement. In this paper, we proposed a new method of measuring water holdup of Oil-water two-phase flow for the production profile logging in horizontal oil wells. Firstly, the structure of water holdup sensors and the measuring principle of water holdup were introduced. Secondly, the dynamic test research was carried out on the horizontal well simulation facility by using the test prototype of the water holdup measurement method of Oil-water two-phase flow. Additionally, the response characteristics of water holdup sensors at five inclined angles were emphatically discussed. Finally, the measurement error of water holdup was calculated and evaluated in detail. Experimental results show that the absolute values of measurement error of water holdup are less than 5% while the total flow rate ranged from 10 m3/d to 200 m3/d, and the water cut ranged from 30% to 90%, respectively. [ABSTRACT FROM AUTHOR]