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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.

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.

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.

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.

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.

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]

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]

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]

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]

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]

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]

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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]

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]