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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.

Buckling may cause drill string damage or even drilling failure. For the 3 000-m-long horizontal section drill string, a simplified analysis model of drill string in horizontal well is established, and the dynamic response results of axial displacement, angular displacement and contact force are obtained. When buckling, the closer the position of drill string is to the bottom, the later the buckling time, the smaller the buckling deformation degree, the slower the growth rate of axial displacement, and the smaller the attenuation degree of angular displacement and contact force amplitude. After buckling, drill string undergoes tensile deformation and eventually remains stable in the tensile state. After stabilization, from the top of drill string to the bottom of drill string, axial displacement increment increases first, then remains unchanged and then decreases, and the relative torsion angle between different positions gradually decreases. The drill string is always in horizontal contact with the wellbore, resulting in the same contact force values at different locations. The change of well inclination angle does not affect the change law of displacement and contact force. The absolute value of angular displacement is negatively correlated with the change of well inclination angle, and the value of axial displacement increment and contact force is positively correlated with the change of well deviation angle, but the value of contact force is quite close. The research results can provide reference for alleviating the buckling of drill string in horizontal wells. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

A simplified mathematical model of two-phase multicomponent flow in the reservoir— multistage hydraulic fractures—horizontal well system is proposed. The formulation of transport problems in the well and in hydraulic fractures is simplified based on the dimensional analysis and similarity theory. The possibility of transition to a quasi-steady-state problem of distribution of the mixture components in high-permeability hydraulic fractures is shown. The dimension of the problem in reservoir is reduced by decomposing the problem into a set of problems in independent fixed stream tubes. For numerical solution of the problem, the resulting reduction in computer time reaches two orders of magnitude and can be further reduced by using parallel computing. Accelerating the solution of the direct problem is fundamentally necessary for the possibility of solving the inverse problem of identifying the porosity and permeability properties of fractures from the results of interpretation of tracer studies. [ABSTRACT FROM AUTHOR]

In order to select a better design trajectory, it needs to spend a lot of energy on parameter adjustment and calculation. Therefore, this paper establishes the intelligent optimization design model of horizontal well trajectory in with the target length and drilling string drag under rotary drilling conditions as the targets, and takes the target entry accuracy as the complex constraints. Meanwhile, multi-objective optimization algorithm and distributed calculation are used to realize the automatic optimization of the well trajectory. Under the given arithmetic conditions, compared with the original design trajectory, a horizontal well was designed with this method, the trajectory length is shortened by 92.1 m, and the maximum build-up rate is changed from 5.50° per 30 m to 4.97° per 30 m, reducing by 9.6%. Under the same BHA and boundary conditions, the drag becomes 232.42 kN, which is 6.8% lower than that before optimization. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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

The stability analysis of horizontal wells is essential for a successful underground coal gasification (UCG) operation. In this paper, a new 3D coupled thermo-mechanical numerical modeling is proposed for analyzing the stability of UCG horizontal wells. In this model, the effect of front abutment stresses, syngas pressure, syngas temperature and thermal stresses is considered to predict the mud weight window and drilling mud pressure during UCG process. The results show that the roof caving in UCG panel has a greatest impact on the stability of horizontal well. Moreover, when the time of coal gasification is increased, the well convergence increases and for more stability it is necessary to increase the drilling mud pressure. This research was carried out on the M2 coal seam in Mazino coal deposit (Iran). The results showed that the mud weight window for horizontal well drilling is between 0 and 33 MPa. The appropriate stress for the maximum stability of the horizontal well, taking all the thermal and mechanical parameters into account, is 28 MPa. The suggested numerical method is a comprehensive and consistent way for analyzing the stability of horizontal wells in UCG sites. [ABSTRACT FROM AUTHOR]

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

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

Unsteady filtration of a Bingham non-Newtonian fluid to a horizontal well is considered. The experimental results show that when such liquids flow in porous media at low pressure gradients, deviations from the linear Darcy law appear. A feature of the movement of Bingham non-Newtonian fluids in a porous medium is the fact that filtration becomes noticeable only after the pressure gradient reaches a certain critical value—the limiting pressure gradient. The formulation of the inverse coefficient problem for determining filtration parameters during the flow of Bingham non-Newtonian fluid to a horizontal well is given. Pressure change curves measured at the well are used as initial information. To numerically solve the inverse coefficient problem, a computational algorithm based on regularization methods is proposed. [ABSTRACT FROM AUTHOR]

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

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

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

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. [ABSTRACT FROM AUTHOR]

The problem of natural vibrations of a fluid in a horizontal well with multiple fractures obtained by hydraulic fracturing is considered. A mathematical model of the natural vibrations of fluid in a horizontal oil well connected to the reservoir by a system of radial hydraulic fractures is constructed and the frequency characteristics of the natural vibrations of fluid as functions of the hydraulic fracture and reservoir parameters are determined. Using a numerical analysis of the frequency characteristics of vibrations, the effect of changes in the fracture width, the number of fractures, and the reservoir permeability on the natural frequencies is demonstrated. [ABSTRACT FROM AUTHOR]

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 FROM AUTHOR]

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

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

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

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 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 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.

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.

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.

Compared with vertical wells and deviated vertical wells, the dynamic characteristics of the drill string in horizontal wells are more complicated and more prone to failure because of the drag-pressure effect under gravity. Most researchers only consider the movement of some drill strings at a certain depth and do not analyze the rotary drilling process of the whole drill string. When most researchers do drill string simulation research, the drill string system diameter of the simulation model is consistent, and the actual drill string assembly is not considered. Based on the finite element method (FEM) and the nonlinear dynamic equation of drill string, the drilling simulation model of the drilling string system in a horizontal well is established by considering the curved hole trajectory and the nonlinear impact contact between the drill string and wellbore. The buckling and dynamic characteristics of the drill string in horizontal wells are analyzed by simulating the whole drilling process, the effect of rotating speed and hook load on the buckling characteristics of the drill string, and the effect of hook load on the whole dynamic characteristics of drill string system are analyzed. The results show that in the drilling process, the buckling deformation of the drill string near the wellhead presents a trend of"Sinusoidal buckling-helical buckling-sinusoidal buckling," the "sinusoidal buckling-helical buckling "appears near the oblique section. When the hook load applied at the end of the drill string is greater than the critical value, the drill string will get stuck during drilling. When it is less than the critical value, the greater the value of the hook load, the more stable the axial feed and lateral vibration of the drill string, and the smaller the contact force between the drill string and the wellbore. With the increase in rotating speed, the vibration period of the drill string decreases, and the amplitude of the vibration increases. With the increase of drill string drilling depth, the buckling deformation of the drill string can be reduced by reducing the value of the hook load. The conclusion is that the research results can be helpful for drill string design and structural optimization. [ABSTRACT FROM AUTHOR]