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Horizontal well intensive fracturing is a critical technology used to stimulate unconventional oil and gas reservoirs. Accurate prediction of wellbore breakdown pressure is conducive to optimal fracturing design and improvement of the reservoir stimulation effect. In this work, the three-dimensional displacement discontinuity method (DDM) is used to characterize fracture deformation and fracture closure after the pumping pressure relief. The influences of key parameters such as the minimum horizontal principal stress, fracture spacing, the Young's modulus, the Poisson's ratio and pumping pressure on the breakdown pressure are analyzed. The results show that, assuming that the fracture half-length is a, the breakdown pressure outside the fracture surface area increases significantly within 2a in the direction of the minimum horizontal principal stress and a in the directions of the vertical stress and maximum horizontal principal stress before pressure relief. The breakdown pressure of the modified zipper-type fracturing in the later stage is lower. When the fracture spacing is small, the fracture breakdown pressure decreases after the modified zipper-type fracturing of two horizontal wells. The fracture breakdown pressure of the first fractured well reaches a maximum when the fracture spacing is a – 1.5a, and the breakdown pressure decreases with increasing well spacing.

To address the issue of uneven productivity release in the Shizhuangnan block of the Qinshui Basin, the initial well pattern is optimized through horizontal well infill to enhance reservoir utilization. However, frequent occurrences of drilling mud and fracturing fluid migration to neighboring wells have resulted in varying degrees of effect to old well productivity. Based on the coalbed methane development in the Shizhuangnan block, the study analyzed the main causes for well-to-well interference and its impact on productivity. From the geological and engineering perspectives, countermeasures and suggestions on well deployment were proposed. The results revealed that staged fracturing of new horizontal wells is the primary cause impairing old well productivity. The proportion of wells affected by drilling is relatively low, with poor productivity recovery efficiency. The impact from fracturing is predominantly concentrated near the wellbore (minimum well spacing < 120 m). The minimum well spacing for fracturing-affecting wells generally ranges from 120 to 300 m, with impact observed at burial depth between 550 to 900 m. The abnormal production in affected wells is characterized by the height increase in liquid water column. Some old wells, with a minimum well spacing of less than 150 m or developed tectonic coal, experience black water production and pump shutdowns. Wells with these issues exhibit lower recovery efficiency. While the production can be significantly restored by manual real-time unclogging, failure in unclogging results in a substantial decrease in gas production. Old wells affected by new well fracturing are distributed in the perforation direction of the horizontal section of new wells. Geologically, the distribution is mainly controlled by the anisotropy of horizontal principal stress. There are two propagation mechanisms depending on well spacing: hydraulic fracture communication and fracturing fluid front propagation. The horizontal stress difference in the coal reservoir of the Shizhuangnan block ranges from 5.5 to 13.5 MPa, with the average horizontal stress difference in the fracturing-affected wells greater than 10 MPa. Under high horizontal stress differences, the strong orientation of hydraulic fractures disturbs the fluid field of the old wells. To mitigate the impact, the deployment of new wells should maintain a minimum well spacing of over 300 m to the old wells and avoid faults. In areas with high stress differences, temporary plugging and diverting fracturing, reducing spacing between clusters, and enhancing stress interference between fractures can be employed to mitigate the fracturing impact on old well productivity.

Horizontal well production prediction is crucial for the efficient development of tight reservoirs. However, owing to the complexity of the parameters affecting horizontal well production, improving the prediction accuracy has always been the unremitting goal pursued by the oil and gas industry. Limited by the number of parameters, the traditional linear fitting method has low computational efficiency and a large error, which brings difficulties to horizontal well production prediction. In this paper, chaotic genetic algorithm is used to optimize the traditional support vector machine, and the problems of slow convergence and local convergence are solved by chaotic genetic algorithm, and an improved support vector machine horizontal well production prediction method is established. At the same time, on the basis of the previous data processing, the fuzzy set classification method is used to build the model, and the learning model is more close to different types of well production, which enhances the applicability of the model in the field practice. Compared with traditional support vector machine, BP neural network, KNN and naive Bayes, the improved support vector machine has a higher prediction accuracy, and the average error is only 2.7%. The results show that the improved support vector machine method has high accuracy in the prediction of small sample data, and the method can be widely used in the production prediction of horizontal Wells in tight reservoirs, providing a reference for the efficient development of tight reservoirs.

With the implementation of infilling new wells and refracturing existing ones, the spacing between wells has decreased, the scale of stimulation for individual wells has expanded, and the level of interference among wells has heightened, significantly impacting fracturing effectiveness and production. Objective Addresses issues related to evaluating and preventing interference between wells, Methods based on an integrated geological engineering workflow, 3D DDM and EDFM technologies have been comprehensively used to establish an integrated geological engineering simulation model for horizontal well groups. Then, the operating range of single wells and well groups following fracturing stimulation was evaluated, and factors affecting the degree of interference between wells were analysed. Results The findings indicate that (1) when the matrix permeability exceeds 0.3×10-3 μm2, the half-length of fractures is greater than 100 m, and the spacing between fractures is less than 40 m, a largerrange of fracturing transformation correlates with an increased degree of interwell interference. (2) As the well spacing increases, the degree of interwell interference diminishes. At a spacing of 400 m, the impact of interwell interference on a single well's EUR can be ignored. (3) It is essential to balance the relationship between the block recovery rate and cumulative production of a single well by optimizing and determining appropriate well spacing. Conclusion The above research results can provide valuable insights for optimizing well spacing and enhancing the effectiveness of repeated fracturing technology.

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

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

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

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

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

An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example. The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing. The optimization of the stimulated reservoir volume (SRV) fracturing fluid volume strength should meet the requirements of estimated ultimate recovery (EUR), increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount. Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed, above which the single-well EUR increase rate kept decreasing. An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production. Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

Objective An enhanced geothermal system (EGS) is a crucial means of extracting thermal energy from hot dry rock reservoirs, and the pattern of well plays a key role in influencing heat extraction efficiency. Currently, there is limited research on pattern of well considering fractured reservoir exploitation models. Methods This paper establishes a numerical model for heat extraction from hot dry rock fractured reservoirs and analyses the impact of four different patterns of wells on EGS heat extraction performance through a comparative analysis of the temperature decrease of the bedrock, heat extraction rate, production temperature, and heat extraction power. Results The results indicate that, compared to vertical wells, horizontal wells have a larger area for fluid heat exchange, allowing for more efficient heat development between fractures. After 30 years of production, considering the case of hydraulic fracturing fracture connectivity, the one injection and two production schemes of horizontal wells exhibit the highest heat extraction efficiency. In the vertical well direction, the temperature influence range is approximately 690 m, with an average temperature decrease of 38.09 K in the bedrock, a heat extraction rate of 24.42%, and a heat extraction power of 3.5 MW. Conclusion The research results provide a theoretical reference for enhancing the heat production of geothermal systems and achieving efficient and sustainable development of hot dry rock resources.

In recent years， tight oil horizontal wells in Daqing oilfield are mainly fractured by close cutting. However， the multi-cluster fracture propagation generates induced stress， which leads to uneven fracture extension in each cluster. To this end， the finite element software ABAQUS was used to establish the numerical model of multi-cluster fracture propagation in horizontal wells in Daqing tight-oil reservoir. The effects of two fracture parameters （cluster spacing， clusters within one fracturing stage） and three construction parameters （fracturing processes， construction displacement， and liquid viscosity） on fracture propagation were studied by the extended finite element （XFEM） simulation method. At the same time， it is found that there is a good consistency between the simulated fracture length of each cluster and the oil production contribution of each cluster when the simulated result is compared with the capacity contribution result of each cluster tested by actual optical fiber in the field. This confirms the correctness of the simulation results. The simulation results show that the stress interference of each cluster is obvious when the cluster spacing is reduced to 5 m， which is not conducive to fracture propagation. The mean fracture half-length of a single cluster does not change significantly when the cluster spacing reaches 10 m or more， and the reasonable cluster distance is about 10 m. The fracture half-length increases with increased clusters within one fracturing stage， but the non-uniform extension also becomes obvious. Compared with the simultaneous stimulation of multiple clusters in the bridge plug stage， the coiled tubing single-cluster stimulation mode is more favorable to fracture propagation. The average half-length of single cluster fractures increases with the rise of the construction displacement， and the uniform extension of fractures can be promoted by increasing the construction displacement. The average fracture half-length of a single cluster rises with the increase of liquid viscosity， and the proportion of high viscous liquid can be increased appropriately.

Abstract As the development of well types for low permeability reservoirs shifts from vertical to highly inclined/horizontal wells, targeted studies of oil and gas reservoir damage must be conducted for such well types to improve the science and effectiveness of acidification conversion. Taking into account the formation of mud cake and the dynamic damage factors caused by drilling fluid on the reservoir during horizontal well drilling, a refined dynamic description model for nonuniform damage in horizontal wells was established. The coupled simulation accounts for the dynamical destruction of the skin factor of the reservoir and the dynamical generation of the slurry. The coupled model consists of a radial mud cake dynamic formation model, a reservoir damage radius model, a permeability distribution model, and a horizontal well inhomogeneous skin factor model. It captures the dynamic evolution of reservoir damage due to drilling fluid contamination during horizontal well drilling and provides a real‐time representation of changes in the reservoir skin factor of horizontal wells, measuring the depth and extent of radial reservoir damage. Clarifying the extent of reservoir damage and its impact in horizontal well sections can help select appropriate acidification methods, improve acid distribution processes, and ultimately improve the effectiveness of mitigating reservoir damage and increasing oil and gas well productivity.

Abstract Steam-assisted gravity drainage (SAGD) is an efficient thermal recovery technique for oil sands and extra heavy oil exploitation. The development of steam chamber goes through multi-stage physical processes for SAGD production in a heavy oil reservoir with an interlayer. In this study, considering the situation that an interlayer is located directly above a pair of horizontal wells, we analyzed the whole process of steam chamber development. We divided the whole process into stages I–V, which are the first rising stage, the first lateral expansion stage, the second rising stage, the second lateral expansion stage and the confinement stage, respectively. Particularly, we further divided stage II into 2 periods and stage IV into 3 periods. These stages and periods can help us understand the development process of steam chamber dominated by an interlayer more profoundly. Based on the divided stages and periods, we established different models of SAGD production by assuming different geometric shapes of steam chamber in different stages and periods. Oval shape was assumed in stages I and III, and inverse triangle shape was hypothesized in stages II, IV and V. The formulas of the front distance of steam chamber and the oil production rate of SAGD were deduced from the established models for different development stages. At the end, we performed two example applications to SAGD production in heavy oil reservoirs with an interlayer. The real oil production rates were matched very well with the theoretical oil production rates calculated by the deduced formulas, which implies the multi-stage development model of steam chamber is of reliability and utility.

The article describes a numerical-analytical model for gas breakthrough to a well during the development of oil fields with a gas cap using horizontal wells. The employed semi-analytical model allows describing the process of gas cone development and reproducing oil and gas production parameters from the well by matching to the actual production history using several coefficients. The numerical scheme of the model was implemented as a computational library in the Python 3.6 programming language.The algorithm was tested on oil deposits with a gas cap in the South Yamal oil and gas region and showed good results in history matching and forecasting calculations. The average calculation time of one iteration being less than 10 seconds allows for multiple model run scenarios using optimization algorithms for automatic calibration to actual production data. The results of the testing show the possibility of achieving satisfactory convergence using automated calibration to the production history. The developed algorithm reduces the workload of specialists in forecasting production, thereby enhancing the effectiveness of decisions made for development optimization.

The efficiency of using horizontal drilling technology largely depends on a number of factors, including the geological structure of the productive formation, fracturing, anisotropy, heterogeneity, porosity, and permeability. This necessitates the design of the process of oil inflow to the horizontal section of the well. The article presents analytical and numerical methods used in modeling liquid inflow to horizontal and multilateral wells. The main attention is paid to taking into account the anisotropy of reservoir permeability, the trajectory of the horizontal wellbore and hydraulic pressure losses due to friction.

The boundary value problem of transient pressure field development around a horizontal well in a laterally infinite, inhomogeneous, anisotropic reservoir is formulated under assumption of slow spatial variation of the matrix permeability along the well axis. The well is represented as a linear fluid source/sink. The pressure distribution is expressed in the integral form on the basis of the instant point source perturbation function found explicitly. The inverse problem for fluid in/outflow density rates simulation is reduced to solution of the integral equation at a given pressure inside the well. A computational procedure is developed and implemented to predict the in/outflow rates along the well and estimate the impact of the permeability variations on the well performance. Series of calculations for constant, linear, and variable permeability cases are analyzed and compared. The difference of the obtained solution from the so-called “locallyconstant” permeability approximation is demonstrated, accuracy and applicability of the latter approach are discussed.

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

Relevance. The need to estimate the time of formation sand accumulation near the annulus of a horizontal well and the unit length of filter elements in the bottom of production strings and to determine the stresses on the surface of production strings equipped with sand filters when lowering into the well. Aim. Based on a study of the reasons for the continued flow of sand into wells equipped with anti-sand filters, to develop and propose measures related to the need to choose a reduction in the number of filters that provide the design flow rate of a horizontal well or a significant increase in the length of the filtering surface of the filters in order to reduce erosive wear of the wire winding. Objects. We are considering a well with a horizontal section, equipped with sand filters, the same size as the casing strings. It was assumed that the integrity of the surface of the filter elements would be preserved and the conditions for their destruction would be eliminated when lowering into the horizontal shaft. This presupposes the necessary efficient operation of the well throughout the entire operational period. The section of the first set of curvature and the forces arising during this are considered as wellas stability of a pipe string during possible stops. Centralizers are evenly located along the length of the column, then in some sections we will have a multi-span statically indeterminate beam, in each section of which a radial load acts. Methods. When studying the time of formation sand accumulation in the annular space of a horizontal well and a unit length of filter elements in the bottom of production strings, it is necessary at the first stage to determine the stresses on the surface of production strings equipped with sand filters when lowering into the well. Studying the assessment of the existence time of the transition period is of particular interest. This is, in other words, during what operational period there is a complete accumulation of formation sand in the annular space and the transition of formation drainage along the entire length of the horizontal wellbore to drainage of only zones adjacent to the filters. To calculate the fluid flow rate when the annular space of the horizontal well is completely filled with sand, the design values ​​of the AC4.8 formation parameters were used. The maximum value of depressions used in the calculations is assumed to be 1.5 MPa. Results. Consideration of situations that arise when filters are lowered into horizontal wells indicates that the outer surface of the filter elements is not protected from destruction as a result of contact stresses with the walls of the drilled wellbore. To protect against destruction and rubbing open gaps by clay-containing rocks, rigid centralizers should be installed along the edges of the filter elements, the maximum allowable distances between which should not exceed 4.0–4.5 m.

Abstract Understanding the stress state caused by a subsequent failure is crucial for successful refracturing. However, there are many differences between the stress reorientation phenomena of a multi-fracture horizontal well and that of a single fracture in a vertical well, including the interaction of multi-fractures. These factors can lead to a change in the stress field of multiple fractures, which is more complex than that of a single fracture. In this paper, based on the elastic theory of porous media and the mechanism of fluid–structure interaction, a finite element numerical model of multi-fracture stress fields is established. The net pressure loaded on the fracture wall was corrected using the fracture line model, which was solved using the separated coupling method with a staggered strategy, and a full coupling simulation of fluid flow and rock deformation was achieved. The results showed that with an increase in production time, the stress reorientation area around the fracture and at both ends first increased at a faster rate, then slowly decreased, and finally disappeared,indicating an optimal refracturing time window. This suggests that the greater the number of fractures, the greater the fracture inclination and fracture bending degree, and the more unfavorable it is for the formation and maintenance of the stress reorientation area near the fracture and at both ends of the fracture. The reorientation of the stress field between horizontal wells may lead to the fracture of the infill wells, causing bending and propagation towards the pressure-depletion area, thus reducing productivity.

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.

The sensitivity of gas and water phases to DAS acoustic frequency bands can be used to interpret the production profile of horizontal wells. DAS typically collects acoustic signals in the kilohertz range, presenting a key challenge in identifying the sensitive frequency bands of the gas and water phases in the production well for accurate interpretation. In this study, a gas–water two-phase flow–acoustic coupling model for a horizontal well is developed by integrating a gas–water separation flow model with a pipeline acoustic model. The model simulates the sound pressure level (SPL) and amplitude variations of acoustic waves under different flow patterns, spatial locations, and gas–water ratio schemes. The results demonstrate that within the same flow pattern, an increase in the gas–water ratio significantly elevates acoustic amplitude and SPL peaks within the 5–50 Hz frequency band. Analysis of oil field DAS data reveals that the amplitude response range for stages with a lower gas–water ratio falls within 5–10 Hz, whereas stages with a higher gas–water ratio exhibit an amplitude response range of 10–50 Hz.

The flow dynamics of low-yield horizontal wells demonstrate considerable complexity and unpredictability, chiefly attributable to the structural attributes of the wellbore and the interplay of gas–water two-phase flow. In horizontal wellbores, precisely predicting flow patterns using conventional approaches is often problematic. Consequently, accurate monitoring and analysis of water holdup in gas–water two-phase flows are essential. This study performs a gas–water two-phase flow simulation experiment under diverse total flow and water cut conditions, utilizing air and tap water to represent downhole gas and formation water, respectively. The experiment relies on the measurement principles of an array fiber holdup meter (GAT) and the response characteristics of the sensors. In the experiment, GAT was utilized for real-time water holdup measurement, and the acquired sensor data were analyzed using three interpolation algorithms: simple linear interpolation, inverse distance weighted interpolation, and Gaussian radial basis function interpolation. The results were subsequently post-processed and visualized with 2020 version MATLAB software, generating two-dimensional representations of water holdup in the wellbore. The study findings demonstrate that, at total flow of 300 m3/d and 500 m3/d, the simple linear interpolation approach yields superior accuracy in water holdup calculations, with imaging outcomes closely aligning with the actual gas–water flow patterns and the authentic gas–water distribution. As total flow and water cut increase, the gas–water two-phase flow progressively shifts from stratified smooth flow to stratified wavy flow. In this paper, the Gaussian radial basis function and inverse distance weighted interpolation algorithms exhibit superior accuracy in water holdup calculations, effectively representing the fluctuating features of the gas–water interface and yielding imaging outcomes that align more closely with experimentally observed gas–water flow patterns.

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.

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.

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.

Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.

The relationship between fractures and gas logging in Nanchuan-Wulong area in eastern Sichuan Basin is utilized to study the identification of fractures in shale gas horizontal wells based on geological (core), imaging logging, logging evaluation, seismic prediction, and other data. First, to solve the problems of lack of core and imaging logging and difficulty in identifying natural fractures in shale gas horizontal wells, a core scale shale natural-fracture identification model is established through vertical wells from a geological perspective in this paper, and the development of high angle fractures in the core is consistent with the high values and peaks of total hydrocarbon anomalies. Second, in combination with the fracture identification mode, the fracture development section of non-coring vertical wells can be quickly and qualitatively identified at a low cost based on total hydrocarbon information. There will be a sudden increase in the total hydrocarbon value in the fracture development section, especially in the shale section with low total organic carbon (TOC). The sudden increase in the total hydrocarbon value also represents the existence of fractures. Finally, the plate method of TOC and normalized total hydrocarbon correlation is used to quantitatively identify vertical and horizontal well fracture sections without coring and imaging logging data. The area delineated by a normalized total hydrocarbon value ≥0.4 and TOC ≥0.5% are considered as the fracture development section of a horizontal well. Based on the identified horizontal well fracture section, from the perspective of geological engineering integration, it is possible to avoid or pay attention to these densely developed large or giant fractures in advance, thereby increasing the production of a single well.

Aiming at the problems such as large deformation difference of coal structure, strong heterogeneity of physical properties, complex coal structure during horizontal drilling, single completion & stimulation technology and so on, a completion technology with composite tubular string for coalbed methane (CBM) horizontal well is proposed. Completion tools, inner operation tubing and outer completion string are designed. The outer completion string is composed of casing and screen pipe. The mechanics and hydraulics calculation model of dual tubular string are optimized. A field test of this completion technology had been accomplished in No. 15 coal seam in Yangquan, Shanxi Province, China. A dual tubular string of 659.5 m was run into the depth of 1591 m, and the horizonal well section in coal seam is divided into four sections by external casing packers (ECP). The tests of dual tubular string running, hydraulic circulation removing dual tubular string blocking and sticking, well washing, ECP expansion sealing and segmental completion in coal seam were accomplished. Based on the engineering data of this well, the force of dual tubular string was calculated by finite difference method, and the related hydraulic calculation was carried out. The results show that the inner tubing increases the lateral force of completion string, and the friction resistance on downhole tubular string increases by 5642.75 N. The pressure of completion tubular string is mainly affected by hydraulic loss of inner tubing and nozzles. The recommended displacement of hydraulic circulation is 16~20 L/s to remove rock and cuttings and maintain wellbore stability during completion string running. The displacement is increased to 20~24 L/s to eliminate the damage of drilling fluid to shaft wall during well washing operation. The research and field test verified the feasibility and innovation of the completion technology with composite tubular string for horizontal well, which provides a reliable basis for horizontal well diversified and adaptive stimulation in coal reservoir with complicated structure.

The risk of well control is high when displacement gas kick occurs in the deep fractured reservoir, and improper handling can easily lead to blowout, which will seriously affect the deep well drilling. Using Fluent software, a simulation model was constructed to depict the interaction of a horizontal well with vertical fractures. The displacement gas kick process was simulated in horizontal well under formation temperature and pressure conditions. An analysis was conducted to assess the impact of fracture width, quantity, as well as the viscosity and density of drilling fluid on the process of gas-liquid displacement. It further compared the effectiveness of three measures in counteracting displacement gas kick: applying back pressure at the wellhead, altering the viscosity and density of the drilling fluid. New findings suggest that the gas-liquid interface within the fracture exhibits a funnel-like shape, where the gas and liquid phases are layered in the annulus and manifest in a streak-like pattern. Fracture width, quantity, and drilling fluid density promote displacement, while drilling fluid viscosity inhibits the displacement. Different from vertical wells, in horizontal wells, displacement gas kick mainly appears in the underbalanced interval. The fracture width primarily determines the size of the displacement window, while the density and viscosity of the drilling fluid exert lesser influence. Horizontal wells are highly sensitive to variations in external conditions when it comes to displacement gas kick. Therefore, enhancing the wellhead back pressure is advisable to address the displacement gas kick in horizontal wells.

In the process of oil and gas drilling, it is of great significance to accurately predict the drag coefficient and settling rate of cuttings in the drilling fluid for hydraulic parameters and borehole cleaning. In this paper, particle settling experiments were used to obtain the final settling velocity of 196 groups of spherical particles and 224 groups of terrestrial high-clay pure-shale cuttings in the power-law fluid. Based on data analysis, a settlement drag coefficient model suitable for irregular-shaped shale cuttings was established. The model can be used to predict the settlement drag coefficient and settling velocity of irregular-shaped shale cuttings in power-law fluid, which can provide theoretical guidance for wellbore cleaning and hydraulic parameter optimization in Daqing Gulong shale oil drilling operations.

According to the variable toe-to-heel well spacing, combined with the dislocation theory, discrete lattice method, and finite-element-method (FEM) based fluid-solid coupling, an integrated geological-engineering method of volume fracturing for fan-shaped well pattern is proposed considering the geomechanical modeling, induced stress calculation, hydraulic fracturing simulation, and post-frac productivity evaluation. Besides, we propose the differential fracturing design for the conventional productivity-area and the potential production area for fan-shaped horizontal wells. After the fracturing of the conventional production area for H1 fan-shaped well platform, the research shows that the maximum reduction of the horizontal principal stress difference in the potential productivity-area is 0.2 MPa, which cannot cause the stress reversal, but this reduction is still conducive to the lateral propagation of hydraulic fractures. According to the optimized fracturing design, in zone-I of the potential production area, only Well 2 is fractured, with a cluster spacing of 30 m and an injection rate of 12 m3/min per stage; in zone-II, Well 2 is fractured before Well 3, with a cluster spacing of 30 m and an injection rate of 12 m3/min per stage. The swept area of the pore pressure drop in the potential production area is small, showing that the reservoir is not well developed. The hydraulic fracturing in the toe area can be improved by, for example, properly densifying the fractures and adjusting the fracture distribution, in order to enhance the swept volume and increase the reservoir utilization.

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.

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.

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.

During the course of actual oilfield development, judicious selection and design of well placement are paramount due to cost constraints and operating conditions. This paper introduces the Matrix Directional Continuous Elements Summation Algorithm (MDCESA), which is utilized to identify that segment with the largest summation for a given length in a 2D or a 3D matrix. An additional function that accounts for the distance between segments was added when searching for multiple segments to avoid intersections or overlaps between segments. The well placement optimization was transformed into a segment summation on a 3D matrix. Our findings reveal significant advancements in well placement optimization. Employing the MDCESA method, six producers were identified and their production performance was compared against two previously selected producers using a reservoir numerical simulator. The results demonstrated that the wells selected through MDCESA exhibited a substantial improvement in production efficiency. Specifically, there was an 11.6% increase in average cumulative oil production over a 15-year period compared to the wells selected by traditional methods. This research not only presents a significant leap in well placement optimization but also sets a foundation for further innovations in reservoir management and development strategies in offshore oilfields.

This paper reviews the multiple rounds of upgrades of the hydraulic fracturing technology used in the Gulong shale oil reservoirs and gives suggestions about stimulation technology development in relation to the production performance of Gulong shale oil wells. Under the control of high-density bedding fractures, fracturing in the Gulong shale results in a complex fracture morphology, yet with highly suppressed fracture height and length. Hydraulic fracturing fails to generate artificial fractures with sufficient lengths and heights, which is a main restraint on the effective stimulation in the Gulong shale oil reservoirs. In this regard, the fracturing design shall follow the strategy of “controlling near-wellbore complex fractures and maximizing the extension of main fractures”. Increasing the proportions of guar gum fracturing fluids, reducing perforation clusters within one fracturing stage, raising pump rates and appropriately exploiting stress interference are conducive to fracture propagation and lead to a considerably expanded stimulated reservoir volume (SRV). The upgraded main hydraulic fracturing technology is much more applicable to the Gulong shale oil reservoirs. It accelerates the oil production with a low flowback rate and lifts oil cut during the initial production of well groups, which both help to improve well production. It is suggested to optimize the hydraulic fracturing technology in six aspects, namely, suppressing propagation of near-wellbore microfractures, improving the pumping scheme of CO2, managing the perforating density, enhancing multi-proppant combination, reviewing well pattern/spacing, and discreetly applying fiber-assisted injection, so as to improve the SRV, the distal fracture complexity and the long-term fracture conductivity.

In coal mine production, advance and precise identification of coal-rock interface can improve recovery and reduce mining risk, which is one of the bottleneck technologies to realize intelligent coal mining. Azimuth electromagnetic wave logging instrument has larger detecting depth and the azimuth resolution ability, which has a certain advantage in coal-rock interface detection, in order to study the oil the applicability of the azimuth electromagnetic wave instrument Periscope in coalfield well logging, coal log level layered formation model was established, using the generalized reflection coefficient method and finite element numerical simulation method, Taking Periscope as an example, the detection characteristics of coal seam boundary are investigated. Application of Periscope instrument transmitting frequency and spacing, set its instrument radius drill pipe radius of the commonly used for coal mine, the simulation results show that the geological response in line with the typical characteristics of signals in the interface, geological signal change with instrument rotation Angle with periodic response, frequency and delineation of distance is not a simple positive correlation, spaced and offset distance have positive correlation, The geological signal amplitude increases with the increase of coal layer thickness, but when the thickness increases to a certain value, the geological signal does not change with the thickness. When the eccentricity is large, the geological signal is affected by the eccentricity, and the azimuth electromagnetic wave measurement response can reflect the resistivity change of the goaf. Results show that the geological signal detection ability of the coal rock boundary by frequency resistivity contrast, layer thickness, spacing, and a variety of factors, such as electromagnetic wave instrument Periscope bearing geological signal has the azimuth resolution, can be used to set of coal rock interface detection model and identification of mined-out area, but in the case of surrounding rock and coal seam resistivity are high, It is necessary to increase the source distance of the instrument or select the appropriate transmission frequency to meet the requirements of the measurement signal intensity.

Based on the characteristics of the No.3 coal seam and No.15 coal seam in Zhengzhuang Field and the need for low-cost and high-efficiency development of coalbed methane, a technical method for enhancing coalbed methane mining in non-cemented L-type staged fracturing horizontal wells in coal seams is proposed. The numerical simulation results show that hydraulic jet fracturing can produce 1.5-2.0 MPa annular sealing effect and 3.5-4.5 MPa hole pressurization effect, which can meet the purpose of annular air anti-channeling and fixed-point fracturing in the non-cemented horizontal wells. In view of the construction technology problems in drilling and completion, fracturing and drainage of non-cemented coalbed methane horizontal wells, four core key technologies have been explored, including “high-quality, fast and safe” drilling and completion technology, coiled tubing with bottom seal fast dragging jet-fracturing combined staged fracturing technology, “large displacement, large-scale, medium-sand ratio” active water fracturing stimulation technology, L-shaped horizontal well fine drainage control technology. Practice has proved that the non-cementing staged fracturing horizontal well development technology for coalbed methane has achieved large-scale application in Zhengzhuang Field, and achieved a double breakthrough in coalbed methane development technology and high gas production.

Well path design is an important factor in horizontal drilling. A reasonable well profile scheme can significantly reduce drilling drag and torque, which also can enhance drilling rate. This study proposes an approach to faster drill a three-dimensional horizontal well by integrating well path and bottomhole assembly (BHA) design. The shortcomings of two classic well path design principles of shortest well length and minimum drag are investigated and a method integrating well path and BHA design is developed by altering inclination holding section to a slightly build up section and predicting build rate of BHA. For two conventional design principles, the design processes are developed by minimum curvature model and genetic optimizing algorithm. Case studies show that the optimized well depth or drag of two conventional methods have little difference compared to the unoptimized ones, which indicates that these two optimization methods cannot significantly improve drilling efficiency. For proposed design method, the well path design is developed by minimum curvature model, and the drilling tendency prediction method is established by three-dimensional beam-column theory and the rock-bit interaction model. Besides, a set of bent-housing mud motor with double stabilizers (BH-PDM-D) BHA is chosen to drill the well, according to the build rate prediction of both slide drilling and rotary drilling. The predicted result of drilling cycle shows that for the six-section well profile, the proposed method can reduce the drilling time by 24.2 days.

Compared to conventional vertical wells, horizontal wells with Ultra-Long horizontal sections greatly increase the oil drainage area and can significantly increase oil and gas production from individual wells. In order to analyze the limit of horizontal well extension, an extension limit model was developed, which takes into account formation, rated pump pressure, rated pressure and string buckling, and is used to predict the limit of horizontal well extension under different constraints. The results show that increasing the inside and outside diameter of drill pipe can effectively reduce pressure loss and facilitate the extension of the horizontal section while keeping the hole size unchanged. As the cuttings density, cuttings diameter, mud density, mud performance, pump rates, and ROP increase, the limit extension length of the horizontal section gradually decreases. As the WOB, RPM, friction factor increase, the torque gradually increases and the limit extension length of the horizontal section gradually decreases. Selecting the right combination of drilling tools can reduce the torque, which is beneficial for mechanical extension. This study is instructive for the limit of horizontal well extension with ultra-long horizontal sections in the field.

Zhengzhuang block is located in the southwest of Qinshui Basin. The main gas producing horizons are No.3 coal of Shanxi Formation and No.15 coal of Taiyuan formation. The occurrence characteristics and gas bearing properties of coal seams in the area are quite different both vertically and horizontally. In this study, the main fracture extension direction and gas content of No.3 coal and No.15 coal were analyzed respectively. On this basis, the horizontal well drilling system in this formation was optimized. The results showed: The maximum horizontal principal stress direction of No.3 coal seam should be NE 45°−60°, SW 225°−240°. The maximum horizontal principal stress direction of No.15 coal seam should be NE 60°−75°, SW 240°−255°。The difference of maximum horizontal principal stress direction between No.15 coal and No.3 coal is 15°. No.3 coal seam belongs to extra low sulfur - low sulfur anthracite, the thickness of coal is 5−6 m. No.15 coal seam belongs to medium high sulfur high sulfur anthracite, The thickness of coal seam is generally stable horizontally, generally 4−5 m, The structure of coal seam is complex. The gas content of No.3 coal seam and No.15 coal seam increases slightly from the south to the north of the block，there are relatively rich areas with Northeast Distribution and relatively low gas content areas with small area scattered distribution. The optimization of drilling system was mainly implemented from two aspects: drilling design optimization and drilling process optimization. The optimization of drilling design mainly included: the optimization of drilling design concept, well location and drilling trajectory. The optimization of drilling process mainly included: drilling equipment optimization, drilling fluid system optimization and well trajectory control. Well trajectory control includes precise landing without pilot hole, well trajectory control in curved section, well trajectory control during landing and well trajectory control in horizontal section after landing. The optimized drilling system was used in well zh-l36, and the drilling rate of coal seam reached 99% and the gas production after fracturing reached 40000 m3/d. By using the optimized drilling system, the daily gas production increased by 100 m3/d.

Abstract In the foreseeable future, the geothermal exploitation from hot dry rocks (HDR) using a horizontal well will bear potential. Thus, in-depth studies should be conducted on the selection of injection-production scheme (IPS) and working fluid, design of reinjection parameters, optimization of wellbore structure and materials, and analysis of geological settings. This paper proposed a fully coupled model to study the above scientific questions. For Model A, the working fluid was injected into the annulus and then flowed out of the thermal insulation pipe (TIP). Its temperature passes through two stages of temperature rise and two stages of temperature decline. But for model B, the working fluid was injected into the TIP and then flowed out of the annulus. Its temperature undergoes five stages, four stages of temperature rise and one stage of temperature decline. The results show that the Model A is the best IPS owing to its high outlet temperature, stable thermal recovery, and low fluid injection volume. In Model A, when the working fluid was supercritical carbon dioxide and the liquid injection volume was 135.73 m3/d, the heat recovery ratio (HRR) was as high as 85.40%, which was 17.85% higher than that of the Model B whose working medium was water, and its liquid injection volume was only 25% of that. Meanwhile, over ten years of continuous production, the outlet temperature decreased by 7.5 °C and 18.38 °C in the latter. The optimal working fluid has a low volume heat capacity and thermal conductivity for any IPS. Sensitivity studies showed that for the area that met the HDR standard, the effect of reinjection temperature on the outlet temperature can be ignored. As for Model A, HRR drops sharply by 6.74–9.32% when TIP goes from completely adiabatic to nonzero thermal conductivity. Meanwhile, the horizontal segment length of the TIP is shorter when Model A obtains the optimal outlet temperature compared with Model B. In addition, the correlation between the outlet temperature and different formations of thermophysical properties was seriously affected by the IPS and exploitation period, which was summarized in detail.

In this work, the comprehensive properties of flammable casing for underground coal gasification is systematically investigated, including flammable casing material physical, chemical and mechanical properties and full-size flammable casing mechanical properties and burning behavior. The flammable casing material consists of magnesium alloy matrix and rare earth particles, thermal conductivity and expansion property of which are weak. Results of high-temperature tensile test reveal that flammable casing material has good high temperature strength which declines by 30 % at 300 °C. Corrosion rate of flammable casing material is relatively high without extra protection. The full-size flammable casing possesses considerable mechanical property, thread property and high temperature collapse resistance. Burning of flammable casing is safe and stable. Burning rate of flammable casing material can be effectively controlled by water flow. Combustion product of flammable casing presents powder condition, which has no risk of blocking the gasification channel. To sum up, flammable casing is necessary to the realization of underground coal gasifying process, which plays the significant role of the development and application of underground coal gasification technology.

Horizontal well technology is a promising method for oil and gas development. During cementing operations in horizontal wells, it was found that conventional casing centralizers could not meet the requirements for casing cementing in expanded wellbores. Therefore, a new type of casing centralizer needs to be designed for horizontal well sections that have undergone enlargement. By analyzing the most common materials currently used, 45 steel was selected for the spring leaf of the novel casing centralizer. To evaluate the centralization effect of the horizontal well casing centralizer, a casing centralization degree evaluation function was established, and a wellbore-centralizer mechanical model was proposed using the finite element method to simulate the working conditions of the centralizer spring leaf in ϕ215.9 and ϕ311.2 mm well sections. On this basis, a wellbore-centralizer-casing coupling model that does not consider the effect of wellbore fluid on the casing was established to simulate the centralization characteristics of the new casing centralizer and traditional centralizer under different wellbore sizes. Simulation results show that the average casing centralization degree of the new centralizer is 85.53%, while that of the traditional centralizer is 55.58%. That is, the horizontal well casing centralizer can maintain a good centralization effect on the casing string.

Drilling and completion processes can often result in reservoir contamination around the wellbore, leading to decreased oil and gas productivity and significant economic losses for the oil field. This issue is particularly complex in sandstone reservoirs with low porosity and permeability horizontal wells, wherein traditional models have limited accuracy and applicability due to numerous unknown parameters. To address this challenge, this study focuses on non-uniform pollution around horizontal wells and proposes a new approach to divide the horizontal well pollution area into N micro-element sections. By establishing a seepage differential equation and employing the similar flow substitution method, we construct models for the pollution skin coefficient of each micro-element section as well as the total pollution skin coefficient. Furthermore, we combine empirical equation models and an oscillation-decreasing function model to develop a pollution radius distribution model that encompasses linear, parabolic, exponential, and logarithmic patterns. Through these advancements, we can realize a comprehensive reservoir damage assessment method. It is verified that the calculation error of this model is very small, and the influence of skin effect and reservoir anisotropy and the radius distribution of various heterogeneous pollution zones are fully considered. These findings indirectly suggest the rationality and practicality of the model presented in this paper. By incorporating actual gas well data into this model, it has been determined through discussion and analysis that the exponential distribution of the pollution radius has the greatest impact on the pollution skin factor along the horizontal well, from the heel to the toe. Increasing the pollution radius and decreasing the pollution permeability both result in an increase in the skin factor of the micro-segment and the total pollution skin factor of the horizontal well. However, compared to the pollution permeability, the radius of the pollution zone has a relatively minor effect on the total pollution skin factor. The proposed technique aims to serve as a valuable tool in optimizing and designing stimulation measures aimed at boosting production and minimizing formation damage. Through evaluation and analysis to reduce risks, protect reservoirs and extend well life, reduce costs, and enhance technical capabilities and economic benefits.

The throttling performance of conventional throttle orifice structures of fluid control valves is very low. Therefore, this paper proposes a novel trapezoidal throttle orifice with excellent throttling performance. The effect of the taper of the throttle orifice on the erosion was researched. Firstly, two schemes of trapezoidal throttle orifice were proposed according to the fluid control valve. Secondly, the excellent throttling performance of the trapezoidal throttle orifice was compared and optimized. Finally, a numerical simulation method of the erosion-resistant ability of the trapezoidal throttle orifice was established. It was found that for the same throttling area, the differential pressure of the trapezoidal orifice was higher than that of the conventional rectangular orifice by about 18.6%. The taper had little effect on the gas production, which increased by only 3.3% during the 10° to 30° change. The maximum erosion was firstly reduced and then increased with increases in the angle from 0 to 25°of the taper. Moreover, the minimum was achieved at about a 20° taper angle. The above research methods provide a theoretical basis for optimizing the size and structure of orifices and the sealing reliability of fluid control valves.

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.

Blasting fracturing technique has developed into a most promising option replacing the hydraulic fracturing for enhancing the permeability of deep formation in the resource exploitation. At present, blasting-enhanced permeability mostly focus on the blasting-inducing fractures in vertical well. Thus, this paper emphatically studies the issues associated with the multi-stage blasting in horizontal well. In this work, a numerical rectangular-solid model consisting of 64000 elements has a size of 100 × 10 × 8 m (L × W × H) is established based on the finite-difference method to simulate a uranium resource reservoir in the Xinjiang Autonomous Regions, China. A horizontal well with the diameter of 20 cm and the length of 100.0 m is located at the center of this model. The shock wave resulted from the explosive detonation is simulated as a time-varying pressure applied to the wall of the well borehole. Four modes of the multi-stage blasting are investigated with the consideration of different in-situ stress conditions. The results show that multi-stage blasting has great effect on the rock damage and blasting-enhanced permeability, while the in-situ stress condition can not be an ignored factor in this affection. For relatively large compressive in-situ stress, 1-stage blasting is a recommended mode for improving the permeability of rock reservoir. However, for relatively small in-situ stress, the permeability of rock reservoir increase first and then decrease along with the increasing of subsections of multi-stage blasting. There must be an optimal mode of multi-stage to improving the permeability of rock reservoir.

In order to produce natural gas hydrate safely and efficiently, it is quite crucial to research the stability of hydrate reservoir in the process of its exploitation. The coupled thermal-hydrodynamic-mechanical (THM) numerical simulation can clearly present the mechanical response laws in the process of hydrate exploitation by horizontal well, but the model is often simplified as a profile vertical to the production well, so the evolution characteristics of real formation deformation space cannot be described sufficiently. To this end, this paper develops a coupled THM simulator applicable to the large-scale hydrate exploitation by horizontal well by introducing interactive interface to the FLAC mechanics program based on the hydrate exploitation program TOUGH + HYDRATE. Then, based on the field data of second hydrate production test in South China Sea, the gas and water production and formation deformation laws under the middle- and long-term development conditions of horizontal wells are studied by taking the actual gas production of horizontal well during the production test as the constraint of coupled THM model. And the following research results are obtained. First, when the production pressure is 7 MPa and the horizontal well length is 300 m, the gas production of horizontal well can reach 1190 × 104 m3, the pressure drop has a larger influence range in the free gas layer, the produced gas mainly comes from the free gas layer and the hydrate layer and the hydrate dissociation range is not large. Second, it is predicted that the seafloor settlement is about 0.16 m after 60 days' production test and 0.52 m after osne year's production. In conclusion, hydrate exploitation by horizontal well can cause a large range of seafloor settlement. The seafloor surface settles linearly and continuously and the spatial settlement distribute is in the shape of ellipse. What's more, the greatest deformation (vertical displacement) occurs at the horizontal well and above it, where formation damage happens the easiest. It is recommended to study seafloor deformation and landslip risk under the conditions of middle and long-term production based on seafloor topography, valley distribution and nonuniform spatial thickness of mineral ores.