Numerical analysis and multilayer perceptron prediction of proppant distribution in multi-cluster perforated horizontal wells

Positive displacement downhole motors (PDMs) are widely applied in modern drilling due to their ability to provide efficient rock destruction and precise trajectory control, especially in directional and horizontal well drilling. However, drilling inclined sections introduces additional operational challenges, including increased hydraulic losses, intensified vibration, elevated lateral loads, and accelerated wear of bottom hole assembly (BHA) components. Under such conditions, maintaining stable and reliable motor performance becomes a critical task. This paper examines the operating principles of positive displacement motors and analyzes how drilling parameters influence their performance. Particular emphasis is placed on key operational variables such as bit rotational speed, weight on drill bit (WOB), pressure difference across the motor, and flow rate of the drilling fluid, as well as the BHA structural features. Optimal operating ranges deviations occurring may lead to rotor stalling, increased torsional and lateral vibrations, reduced rate of penetration (ROP), and premature motor failure. Special attention is given to hydraulic conditions in deviated well sections, where inefficient cuttings transport and uneven drilling fluid distribution significantly affect motor stability. The role of drilling fluid rheology and its adaptation to specific geological and technical conditions is also highlighted. Keywords: Positive displacement motor, deviated well, drilling parameters, drilling fluid, weight on bit, flow rate, rotational speed, vibration.

Shale oil reservoirs are characterized by ultra-low matrix permeability. After large-scale hydraulic fracturing is applied to horizontal wells, fluid transport becomes highly complex, posing major challenges for accurately predicting production performance. In this study, a coupled multi-mechanism numerical model is developed for shale oil reservoirs with complex fracture networks. Using the Embedded Discrete Fracture Model (EDFM), the mass transport between the fracture and matrix and within the hydraulic fracture network can be accurately quantified. Based on core analysis and fluid experimental data, the dynamic evolution of rock and fluid properties is characterized by incorporating nanopore confinement effects, stress sensitivity, and threshold pressure gradient behavior. Numerical simulations are then conducted to investigate the impacts of multiple mechanisms, including nanopore confinement effects, stress sensitivity, and threshold pressure gradient, as well as their coupling effects on shale oil production. A field application is carried out using Well H1 in the Qingcheng shale oil reservoir. Simulation results indicate that nanopore confinement reduces bubble-point pressure, leading to a 3.60% increase in cumulative oil production and a noticeable reduction in the producing gas–oil ratio. Stress sensitivity causes a 2.68% decrease in cumulative oil production and suppresses gas production. The threshold pressure gradient exerts the strongest negative impact, resulting in an 8.01% reduction in cumulative oil production and a slight decrease in gas–oil ratio. When all mechanisms are simultaneously considered, strong nonlinear interactions emerge, yielding a 7.09% reduction in cumulative oil production—significantly different from the linear superposition of individual effects. These results demonstrate the necessity of accounting for multi-mechanism coupling to achieve reliable production forecasting in fractured shale oil reservoirs.

In recent years, screen pipe scaling and blockage have occurred in dozens of wells in the Fuling Shale Gas Field, seriously affecting the normal production of gas wells. Investigations show that similar problems exist in the Weirong Shale Gas Field of Sinopec Southwest Branch, and the Changning and Weiyuan Shale Gas Fields of PetroChina. Although well production has been restored through pipe inspection operations, key issues specific to shale gas wells remain unresolved, including the scaling mechanism under gas–liquid two-phase flow regimes unique to horizontal shale gas wells, the scale deposition law at screen pipes caused by complex flow direction changes, and the targeted prevention technologies for high-hardness BaSO4 scale in high-salinity produced water. By jointly conducting research on the scaling mechanism and prevention technology of shale gas wellbores with Southwest Petroleum University, the Fuling Shale Gas Field has identified the reasons why the amount of BaSO4 scaling increases with the decrease in pressure and temperature, while it increases with the increase in gas–water ratio. It has clarified the influencing characteristics of factors such as pressure, temperature, gas–water ratio and pipe wall roughness. The amount of scaling on the tubing wall of shale gas wells in this area is very small, and blockage mainly occurs at and near the screen pipe. Due to the complex flow direction change in gas and water in the screen pipe, the precipitated tiny scale particles separate, settle and accumulate, forming variable-diameter steps that continue to grow. Two agents have been developed: the LPPAS scale inhibitor and the barium-strontium-sulfate-chelating plug-removing agent, with a scale inhibition rate as high as over 90% and a scale dissolution rate over 70%, respectively, laying a foundation for the efficient and stable production of shale gas wells.

Compared with previous analytical designs for deep UBHE, the present study is new in three aspects: (1) a segmented FLS model combined with the virtual heat source method is applied to the full U-shaped path (injection, horizontal, and production wells) in a unified formulation; (2) equivalent thermal conductivity is introduced to account for groundwater seepage in porous media, avoiding the need for separate CFD or coupled numerical solvers; (3) the relationship between production well depth and the maximum effective insulation length is quantified and discussed. Deep U-shaped borehole heat-exchangers (UBHE) systems boast high heat-exchange efficiency, yet most analytical models are too simplistic, causing inaccuracies. This study proposes a segmented finite line source (FLS) model for UBHE using the virtual heat source method. Introducing equivalent thermal conductivity (kequ), it treats rock-soil as a groundwater-saturated porous medium, coupling seepage’s dynamic heat-transfer impact. By comparing the simulation results of the same type of research within 720 h, the average temperature difference between the models was found to be 1.31 °C, with an error rate of 5.31%, which is 40.87 percentage points lower than the existing achievements, thereby demonstrating the accuracy of this model. In addition, based on this model, the influence trends of five main factors such as seepage velocity and geothermal gradient on the system’s heat exchange were drawn and analyzed. Among them, the laying length of the insulation layer was analyzed in detail. The results show that its maximum laying length should be in line with the depth node where reverse heat exchange occurs with the production well. Under the set conditions of this study, when the depth of the production well is 2500 m, the maximum laying length of the insulation layer is 1900 m.

As a vital future energy resource, achieving high-efficiency exploitation of natural gas hydrates (NGHs) still faces challenges, and depressurization combined with other enhancement technologies, such as reservoir stimulation, may be the optimal path. Unlike previous studies that mainly focused on the impact of boundary sealing on single-well or complex-structure well types, this work systematically compared the production performance of two well-net modes under boundary sealing conditions. Based on China’s first offshore NGH trial production, and a numerical simulation method combined with J index (mainly affected by well type) was used to systematically compare the short- and long-term yield-increasing effects of five-spot wells (FSW) and cluster horizontal wells (CHW) for depressurization of Class 1 hydrate reservoirs with boundary sealing. The results indicate that both types of wells have better productivity performance due to the low-permeability barrier formed by boundary sealing to suppress water invasion and concentrate pressure energy to decompose hydrates, but their performance differs over time. The five-spot wells showed a more substantial overall improvement. Compared with the base case, with the boundary sealing, the cumulative gas production ( V g ) of the five-spot wells and cluster horizontal wells increased by 169.8% and 155.1%, respectively, and the gas-to-water ratio ( R gw ) increased by 680.6% and 409.3%, respectively. Although the cluster horizontal wells performed well in the first 120 days, the five-spot wells with boundary sealing performed well after 120 days and achieved a higher J index of 9.5 after 720 days. The results indicate that cluster horizontal wells demonstrate higher short-term gas production efficiency, whereas five-spot wells offer long-term development potential. The optimal engineering decision should therefore be based on whether the project’s core strategic objective is short-term pilot verification or long-term development. These findings provide a theoretical reference for multi-well development strategies in Class 1 hydrate reservoirs under boundary sealing conditions.

Fluid flow and heat transfer during staged multi-cluster fracturing treatments along horizontal wells — Application for hydraulic fracture characterization using distributed temperature sensing

Multi-physics field coupling simulation of oil shale SRV-heating of multi-volume-fractured horizontal well and vertical well production

A numerical model for predicting the thermophysical parameters of superheated steam in full-length horizontal wells considering phase change

Stratified flow detection in horizontal wells based on distributed fiber-optic temperature sensing

Heat extraction mechanism in hot dry rock based on horizontal wells with multi-stage fracturing

An inter-well interference quantitative evaluation approach of multiple multi-stage fractured horizontal well with non-uniform simulated reservoirs volume in tight gas reservoirs

Relevance. Improving the confidence of well testing results in horizontal wells with multi-stage hydraulic fracturing widely used for hard-to-recover oil and gas production. Aim. To develop methods for improving the confidence of parameter estimation for the “reservoir–well” system based on well test data in horizontal wells with multi-stage hydraulic fracturing by obtaining a radial-like flow regime response. Methods. Analytical and numerical modelling of pressure buildup and drawdown responses. Results and conclusions. The features of pressure superposition during interference between fractures in horizontal wells with multi-stage hydraulic fracturing determine the occurrence of a radial-like flow regime in the mid-time period of pressure buildup, provided the well is shut in after a short production. An empirical relation is obtained for this regime, which can be used to estimate reservoir flow capacity kh/µ with acceptable accuracy. It is shown that for reservoir with permeability of ~0.1 mD the radial-like flow regime can predominantly be achieved only during the initial stage of well production period. Methodology is presented to obtain reliable interpretation results based on a series of well tests with the achievement of the radial-like flow regime. Blind testing of the methodology on synthetic pressure buildup data revealed that, in addition to the radial-like flow response, the subsequent transitional flow regime plays an important role in improving interpretation confidence, and the way the model is matched to this regime predetermines further steps in interpretation. Analysis of synthetic buildup data for reservoirs with permeability of ~0.01–0.1 mD shows that the appearance of the radial-like flow regime is preserved for a sufficiently long time even with a complex production history. Although the time to reach the radial-like flow regime in such wells is within 1–3 months, the proposed testing methods have potential for application at pilot stages of field development.

A productivity simulation for hydraulically fractured wells with complex fracture geometry involves a heavy computational burden and is therefore not suitable for engineering-scale fracture-optimization designs and production-analysis applications. This paper develops a productivity-prediction surrogate model based on a deep convolution–bidirectional gated recurrent unit temporal network (DC-BiGRU) framework where a deep convolutional neural network is used to extract features from fracture images, while a BiGRU model was designed to fully capture valuable information from the production sequence. Some additional inputs, e.g., cluster spacing and stage spacing, that account for different fracture-placement designs in horizontal wells were also considered. A large number of shale-gas production data samples at different times were generated using a fractured-horizontal-well productivity simulator under diverse hydraulic-fracture geometries and bottom-hole flowing pressures. The surrogate model had relative errors below 10% with an average error of about 6%. Compared to high-fidelity capacity prediction simulators, the computational efficiency of the deep learning surrogate models was improved by two to three orders of magnitude. The runtime of the high-fidelity numerical simulator was about 20 min, while the surrogate model, which was run on an NVIDIA Tesla P100 GPU (NVIDIA, Santa Clara, CA, USA), took less than 1 s, which is almost negligible. The proposed surrogate model resolved the low efficiency of the productivity simulation for complex-fracture hydraulic fracturing wells in unconventional reservoirs, enabling rapid dynamic forecasting of fractured-well productivity.

A system of artificially created fractures formed during multi-stage hydraulic fracturing in a low-permeable gas-saturated reservoirs has been investigated in this study. The task addressed is to parameterize the object under consideration given limited input geomechanical information. The results of hydraulic fractures modeling have been obtained, as well as their geometric and filtration parameters, by using analytical and explicit numerical methods. Interpretation of the findings revealed the limitations in analytical methods when considering the geomechanical properties of rocks; specifically, their reservoir and geomechanical heterogeneities and stimulation design. The consequence is the greatly increased uncertainty in production forecasting because fractures are represented by average values of key parameters (L = 120–330 m, w = 2.4–7.8 mm) for determining well productivity. The explicit method demonstrated higher flexibility and adaptability depending on the available input data. The average results, which were obtained by applying both methods, showed similarity between key parameters (L = 199–339 m, w = 7–10 mm, Cf = 774–1098 mD*m), which confirms these methods' validity. However, the ability of the explicit modeling approach to provide a detailed description of key fracture parameters, including 3D geometry, variation of fracture width (w = 3–11 mm), and proppant saturation over the fractured area (Cp = 75%), gives a higher priority to this method during research. The use of an explicit method, in contrast to the analytical one, makes it possible to determine the asymmetry of the fracture flanks, relative to the direction of the minimum horizontal stress, the change in thickness and permeability along the fracture, the distribution and concentration of proppant. All this leads to an uncertainty ranges reduction in the production forecast from horizontal wells with multi-stage hydraulic fracturing, during the development of shale reservoirs. This is the next step for further use of the results.

CO2-assisted steam huff and puff is an effective method to improve oil recovery and store CO2 in heavy oil reservoirs. However, few studies focused on complex geological formations, such as bottom water. The bottom water condition not only complicates the process of oil production and CO2 sequestration, but also makes migration and distribution of oil, water and CO2 unclear. In this paper, a numerical geological model of an offshore heavy oil reservoir with bottom water is established to analyze the influence of bottom water on injection and production parameters, oil recovery and CO2 storage capability under vertical and horizontal well layouts. The results show that the bottom water could maintain the formation pressure, but reduce the steam chamber radius and heavy oil utilization area, increase water production and decrease the oil–water ratio. CO2 could enhance oil recovery in the bottom water reservoir. Oil development indicators of the horizontal well are higher than the vertical well. Meanwhile, CO2-assisted steam huff and puff use in the bottom water reservoir can create a high-pressure and -temperature environment to make CO2 supercritical, as it has better CO2 storage capability and efficiency. The CO2 storage efficiency of the horizontal well is 63% larger than the vertical well. Thus, the horizontal well layout should be used as a priority if bottom water presents. Conducted analysis of bottom water formation sensitivity parameters shows that the advantageous formation conditions are high oil saturation, porosity of 0.2–0.4 and permeability of 2000–3000 mD. The influence degrees of each formation parameter were evaluated as well.

ABSTRACT CO 2 flooding is an effective method of increasing production in tertiary oil recovery, but it faces engineering difficulties such as channeling. The main issue is that the heterogeneity of the reservoir leads to CO 2 fingering in the reservoir. To this end, this paper constructs a method for identifying and calculating the volume of gas channeling channels in horizontal wells with consideration of permeability differences, and conducts field application verification. The results show that the permeability extreme limit is 4, the permeability extreme range is 4.5–10, and the liquid production ratio is positively correlated with the permeability difference. The calculation results of the gas channeling volume have a good correspondence with the gas invasion volume, and the calculation results are relatively accurate. This method realizes the identification of gas channeling channels and the calculation of gas channeling volume, provides data reference for the selection of site channeling points and the screening of channeling systems.

Due to reservoir heterogeneity and drilling/completion damage, the gas production distribution along the wellbore in low-permeability gas reservoirs generally exhibits significant unevenness, restricting the full utilization of single-well productivity. To address this issue, this paper constructs a novel multi-segment horizontal-well flow model considering the permeability differences along the wellbore. Our methodology developed the skin factor calculation method to quantitatively predict production after acid stimulation. Studies have shown that the heterogeneity of permeability along the wellbore significantly controls the gas production contribution and early production response of each well section, and the traditional homogeneity assumption is prone to leading to biases in production capacity evaluation. Compared with general acidizing, targeted acidizing combined with flow constraints can effectively reconstruct the gas production distribution, significantly enhance the contribution of low-yield sections, and improve overall production performance. Taking the P002-H3 well in the Sichuan Basin as an example, based on gas production profile identification and skin coefficient decomposition, drilling fluid invasion was identified as the dominant damage mechanism, and the acidizing scheme was optimized accordingly, verifying the engineering applicability of the proposed method in horizontal-well production capacity evaluation and stimulation optimization.

Due to the gravitational differentiation effect, the oil-water two-phase flow in the horizontal well exhibits significant asymmetry and inhomogeneity in terms of phase distribution and velocity field. The existing logging techniques are difficult to use to precisely characterize the wellbore flow field under these conditions. To solve this problem, this study, based on the logging data of the Capacitance Array Tool, proposes a three-dimensional visualization method for the water holdup field in the wellbore and applies and evaluates three interpolation algorithms: linear interpolation, cubic spline interpolation, and natural neighbor interpolation. This paper relies on the multiphase flow experimental platform and uses industrial white oil and tap water as fluid media for experiments. It systematically studies the three-dimensional imaging characteristics under different angles, flow rates, and water cuts. The results show that the natural neighbor interpolation algorithm, with its advantage in topological reconstruction, effectively overcomes local mutations in complex flow states. It exhibits superior imaging accuracy and robustness under all operating conditions but has higher computational costs. In contrast, linear interpolation and cubic spline interpolation perform well only in stable flow fields with low-to-moderate flow rates and water holdup. In practical applications, for simple flow states, it is recommended to use computationally efficient linear or cubic spline interpolation methods; for complex flow states or scenarios requiring strict imaging details, the natural neighbor interpolation algorithm should be prioritized.

As coalbed methane exploration and development advance into deeper and more geologically complex areas, borehole stability has become one of the core technical bottlenecks restricting the safe and efficient development of coalbed methane. This paper systematically reviews recent research progress in the field of coalbed methane wellbore stability, with a focus on two main directions: mechanical analysis models and numerical simulation methods. First, it elaborates in detail on five types of mechanical models based on approximate strength theory, fracture damage mechanics, weak plane structures, discontinuous media, and fracture mechanics, analyzing the theoretical foundations, applicable conditions, and their applications and limitations in evaluating coal seam wellbore stability. Second, it provides an overview of early international numerical simulation studies represented by software such as FLAC and STAB-ViewTM, and then comprehensively summarizes the latest applications of multi-physics field numerical simulation techniques—including discrete element method, finite element method, RFPA, and COMSOL—in research on coalbed methane wellbore stability, revealing the influence mechanisms of factors such as in-situ stress, joint systems, drilling fluid parameters, and multi-field coupling effects on borehole stability. Finally, in light of the current engineering requirements for deep coalbed methane horizontal well development, it points out deficiencies in existing research regarding the adaptability of theoretical models, multi-field coupling mechanisms, and intelligent prediction methods, and provides an outlook on future research directions, aiming to offer theoretical support and methodological reference for the optimized design and risk control of coalbed methane drilling engineering.