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Optimizing the deployment of infill wells is significant for improving the recovery of shale gas reservoir. A multi-well productivity prediction model considering complex fracture morphology and flow interference between multiple-staged fractured horizontal wells is established in order to optimize the deployment of infill well. The cumulative production curves of three simultaneous wells in a shale gas area in Sichuan Basin are accurately predicted with a relative error less than 5.5%. The optimal deployment location and timing of infill wells were determined quantitatively to maximize the 20-year cumulative production of infilling well and parent wells. The results show that: The later the infill wells were deployed, the more production the two parent wells produced, and the less the infill well produced; When the spacing d1,3 between parent well 1 and infill well is larger, the two wells produce more and the parent well 2 produces less; The optimal deployment time for infill well is 2.85 years; The optimal well spacing d1,3 between parent well 1 and infill well is 450 m, and the optimal well spacing d2,3 between parent well 2 and infill well is 350 m. The findings of this study can help for better understanding of improving shale gas EUR. [ABSTRACT FROM AUTHOR]

With the development of shale gas horizontal well-filling technology, by drilling infill wells between wells, the well spacing is continuously reduced to make shale reservoir reconstruction more effective. However, in shale gas reservoirs in China, the problem of inter-well interference is becoming increasingly serious, which not only affects the production of well groups but also causes wellbore damage. Currently, the process of interference in the production process is unclear. This study addresses the inter-well interference issue in deep shale gas reservoirs. An integrated numerical simulation method combining the Discrete Fracture Network, Finite Element Method, and Finite Difference Method is proposed. A comprehensive reservoir numerical model considering the production process is proposed. According to the actual reservoir model parameters and operation parameters, a multi-factor analysis model under multiple production conditions was established. Cumulative gas production and inter-well interference were analyzed. Finally, a field model was established, and the history matching of formation pressure was carried out. According to the history-matching results, the pressure expansion range in the production stage was analyzed. These research results provide a scientific basis and practical suggestions for the effective management and mitigation of inter-well interference and are expected to play an important role in practical engineering applications. [ABSTRACT FROM AUTHOR]

In order to overcome the defects that the analysis of multi-well typical curves of shale gas reservoirs is rarely applied to engineering, this study proposes a robust production data analysis method based on deconvolution, which is used for multi-well inter-well interference research. In this study, a multi-well conceptual trilinear seepage model for multi-stage fractured horizontal wells was established, and its Laplace solutions under two different outer boundary conditions were obtained. Then, an improved pressure deconvolution algorithm was used to normalize the scattered production data. Furthermore, the typical curve fitting was carried out using the production data and the seepage model solution. Finally, some reservoir parameters and fracturing parameters were interpreted, and the intensity of inter-well interference was compared. The effectiveness of the method was verified by analyzing the production dynamic data of six shale gas wells in Duvernay area. The results showed that the fitting effect of typical curves was greatly improved due to the mutual restriction between deconvolution calculation parameter debugging and seepage model parameter debugging. Besides, by using the morphological characteristics of the log-log typical curves and the time corresponding to the intersection point of the log-log typical curves of two models under different outer boundary conditions, the strength of the interference between wells on the same well platform was well judged. This work can provide a reference for the optimization of well spacing and hydraulic fracturing measures for shale gas wells. [ABSTRACT FROM AUTHOR]

This study conducted a series of true triaxial hydraulic fracturing experiments on Longmaxi Formation shale. We investigated the interaction between internal factors and external factors on the inter-well interference of 400 mm cubic porous specimens. During dual wellbore fracturing at different formations, forming inter-well interference through secondary hydraulic fractures lead to a lower interference intensity and larger stimulated rock area. When adopting a three-layer well layout during three-wellbore fracturing, the vertical distance between the wells is shortened, activating more bedding planes. Regardless of a horizontal well placement with two wellbores or a three-dimensional two-layer well placement with three wellbores, increasing the vertical stress leads to more potent inter-well interference. There is no absolute positive correlation between the stimulated rock area and inter-well interference. It can be influenced by the presence of natural fractures within the formation that can even lead to a reduction in the stimulated area. When the well placement changes from two horizontal wellbores to three-dimensional two-layer sites with three wellbores and the vertical stress increases, the inter-well interference becomes stronger, but the stimulated rock area only increases by 22.6%. These findings provide crucial guidance for the hydraulic fracturing design of shale reservoirs.

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Multi-horizontal well hydraulic fracturing is a widely employed and highly effective method for stimulating tight and shale reservoirs. However, most existing studies primarily focus on investigating the impact of intra-well interference on fracture propagation while neglecting the influence of inter-well interference. Here, a multi-well hydraulic-fracture-propagation model is established to examine the effects of inter-well interference on fracture propagation within a multi-well system. In this study, based on the bilinear T-S criterion, the stiffness degradation is used to describe the damage and evolution process of fracture, the coupling process of fluid flow and solid damage and deformation is realized, and the dynamic distribution of inter-fracture flow is realized by using Kirchhoff function on the basis of the cohesive zone method (CZM) finite element model. Finally, the fracture-propagation model of multiple horizontal wells is established. Based on this model, the mechanism of inter-well interference on fracture propagation is studied, and the influence law of Young's modulus and fracture displacement on fracture propagation in multi-wells is investigated. The results show that the reservoir can be divided into self-influence area, tension area and compression area according to the stress distribution state in the hydraulic fracture propagation of multi-wells. The propagation rate of hydraulic fractures in horizontal wells is significantly accelerated when they propagate to the local tension area generated by the fracture tip of neighboring wells, and rapidly decreases as the hydraulic fractures continue to propagate to the compression area of neighboring wells. Rocks with a lower Young's modulus tend to be more plastic, forming hydraulic fractures with usually lower fracture lengths and usually larger fracture widths. The hydraulic fracture has an inhibitory effect on the propagation of fractures closer to each other in neighboring wells, and this inhibitory effect gradually increases as the distance decreases. The dominance of the dominant fracture to propagate in the self-influence area gradually decreases under inter-well and intra-well interference. As the dominant fracture propagates into the tension and compression areas of the neighboring well fractures, the feed fluid will show a brief rise and then eventually stabilize. This study quantifies the effect of inter-well interference on fracture propagation and lays the foundation for treatment optimization of small well spacing hydraulic fracturing. [ABSTRACT FROM AUTHOR]

To address the problem that the energy deficit of the old well formation has an impact on the reservoir stimulation and production of the new well, a numerical model of the reservoir is established on the basis of a three-dimensional geological and ground stress model, the dynamic change law of the stress field of the old well is studied in combination with the production data, the characteristics of the fracture pattern of the new well are predicted based on the fracture propagation model, and the fracturing design parameters are optimized. The study shows that the ground stress area caused by the development of old wells has an induced effect on the fracture propagation of neighboring wells, and optimizing the ratio of the front fluid in new wells can compensate for the formation energy deficit, avoid the artificial fracture in new wells from extending excessively in the deficit direction, so that the reservoir stimulation is more adequate and post-fracturing capacity is more desirable. The example application of Well Group H1 in the Mahu conglomerate reservoir shows that the preferred cluster spacing is 25-30 m, the fluid intensi- ty used is 18 m³/ m, and the single cluster pad fluid volume is 400 m³, which can effectively inhibit the induction of artificial fractures in new wells by low stress zones and improve the proppant placement concentration. This study has important guidance for the development of similar conglomerate reservoirs. [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.)

With the continuous shortening of horizontal well clusters and the increase in the single-stage fracturing scale, the inter-well interference phenomenon has increased. Moderate inter-well interference can improve single-well production, but excessive inter-well interference will reduce gas well production and slow production recovery. This paper analyzes the causes of inter-well interference from well patterns and spacing, single-stage fracturing scale and engineering. Taking three infill horizontal wells in the Sulige East II area gas field as examples, the effects of inter-well interference on productivity are analyzed by field data, which has certain guiding significance for optimizing fracturing design.

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.)

Design and optimization of well spacing is a key indicator for evaluating the development effect of shale gas reservoirs. On the basis of theoretical understanding, and after the verification by analogy, numerical simulation, and economic evaluation, a complete workflow from inter-well interference simulation and dynamic data diagnosis to multi-well production simulation and well spacing optimization was formed. First, a pressure detection boundary propagation model is established to simulate the response degree of inter-well interference under different connected conditions. Second, inter-well interference is identified and diagnosed depending on the inter-well interference response behaviors and the interpretation of performance data from gas wells. Third, taking the geological interpretation and dynamic analysis results as basic parameters, a multi-well numerical model for volume fracturing in gas reservoirs is established to simulate the production performance of gas field, and then well spacing is optimized in combination with the net present value model. The application in the Ning 201 well block in the Changning National Shale Gas Demonstration Area has shown that a smaller well spacing can allow a premature inter-well interference and also the enhancement of recovery in the entire block. Given the current fracturing scale and parameter system, the well spacing of 300–400 m can be optimized to 260–320 m, that is, the number of wells per unit area increases by 20%–30%. As a result, the recovery percent of reserves in the block increase by about 10%. The net present value of the block rises, but the corresponding optimal well spacing does not change, with the production period.

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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.)

Based on the characteristics of injection-production units in fractured-vuggy carbonate reservoirs, nine groups of experiments were designed and performed to analyze the interference characteristics and their influencing factors during water flooding. Based on percolation theory, an inversion model for simulating waterflooding interferences was proposed to study the influence laws of different factors on interference characteristics. The results show that well spacing, permeability ratio, cave size, and cave location all affect the interference characteristics of water flooding. When the cave is located in high permeability fractures, or in the small well spacing direction, or close to the producer in an injection-production unit, the effects of water flooding are much better. When the large cave is located in the high-permeability or small well spacing direction, the well in the direction with lower permeability or smaller well spacing will see water breakthrough earlier. When the cave is in the higher permeability direction and the reserves between the water injector and producer differ greatly, the conductivity differences in different injection-production directions are favorable for water flooding. When the injection-production well pattern is constructed or recombined, it's better to make the reserves of caves in different injection-production directions proportional to permeability, and inversely proportional to the well spacing. The well close to the cave should be a producer, and the well far from the cave should be an injector. Different ratios of cave reserves to fracture reserves correspond to different optimal well spacings and optimal permeability ratios. Moreover, both optimal well spacing and optimal permeability ratio increase as the ratio of cave reserves to fracture reserves increases.

In recent years, the commercially developed tight conglomerate reservoirs have been benefiting from the continuous progress of fracturing technology. The overall development trend of fracturing is focused on providing small well spacing, large-scale cutting, and cross-well fracturing. The productive construction of new wells is restricted by fracture interference. In this paper, to improve the accuracy of the fracturing design and the final recoverable reserves (EUR) of the well groups, the authors have put forward a new fracturing optimization method. Based on a discrete fracture model and the dynamic in-situ stress field data, they have established a refined three-dimensional in-situ stress model. The model is solved by the coupling analysis of finite element geomechanics and seepage mechanics, combined with the production data. The model is applied to simulate the evolution of the reservoir in-situ stress field under the condition of the formation energy deficit. Then, the fracture distribution of the new wells in the new dynamic in-situ stress field is simulated, and the fracturing parameters are optimized according to the comparison of the predicted productivity data for different schemes. Taking the well group H1 in the Jin 202 demonstration area as an example, the method has been applied to analyze the factors determining lower productivity after the new wells are put into production. Based on subsection clustering and pump-injection design, the authors have put forward the principles of design optimization of the new wells. As shown by the analysis results, the dynamic in-situ stress model incorporating the influence caused by the production of the old wells is applicable for the evaluation and interactive characterization of fractured layers of the new wells. When the new wells are characterized by significant cross-well interference of fractures, the new model provides an important basis for predicting productivity and optimizing fracturing parameters. When the target horizontal well group is fractured with a cluster spacing of 20 m and a preflush ratio of 55%, the maximum productivity is obtained and the development effect is the best. [ABSTRACT FROM AUTHOR]

It is of great significance to find out the mutual interference mechanism between CBM drainage wells to rationally arrange well networks and improve CBM recovery. To this end, Lattice Boltzmann Method （LBM） was used to reproduce the migration process of CBM from cleat space to drainage wellhead, and the influence mechanism of different drainage parameters and mutual interference between CBM drainage wells on gas production were systematically analyzed. The results showed that the difference of gas production between wellbores showed fluctuation characteristics with the change of well spacing due to inter-well interference. If single well gas production was considered, inter-well interference had segmented effect on gas production. When the spacing of Ds between wells was less than 382.5 lu, it showed inhibiting effect; otherwise, it showed facilitation. Too small well spacing was not conducive to CBM production. When the well spacing exceeded the critical threshold of 382.5 lu, the recovery rate of CBM could be accelerated. The power law relationship ■≈3.2△p0.94 was followed by mean velocity ■ of CBM in wellhead and pressure difference △p.

Based on the characteristics of injection-production units in fractured-vuggy carbonate reservoirs, nine groups of experiments were designed and performed to analyze the interference characteristics and their influencing factors during water flooding. Based on percolation theory, an inversion model for simulating waterflooding interferences was proposed to study the influence laws of different factors on interference characteristics. The results show that well spacing, permeability ratio, cave size, and cave location all affect the interference characteristics of water flooding. When the cave is located in high permeability fractures, or in the small well spacing direction, or close to the producer in an injection-production unit, the effects of water flooding are much better. When the large cave is located in the high-permeability or small well spacing direction, the well in the direction with lower permeability or smaller well spacing will see water breakthrough earlier. When the cave is in the higher permeability direction and the reserves between the water injector and producer differ greatly, the conductivity differences in different injection-production directions are favorable for water flooding. When the injection-production well pattern is constructed or recombined, it's better to make the reserves of caves in different injection-production directions proportional to permeability, and inversely proportional to the well spacing. The well close to the cave should be a producer, and the well far from the cave should be an injector. Different ratios of cave reserves to fracture reserves correspond to different optimal well spacings and optimal permeability ratios. Moreover, both optimal well spacing and optimal permeability ratio increase as the ratio of cave reserves to fracture reserves increases. [ABSTRACT FROM AUTHOR]

The geochemical response of produced water from coalbed methane (CBM) well group with multiple coal seams has rich geological significance. Taking 8 CBM wells of Songhe well group in western Guizhou as an example, the geochemical response characteristics and productivity significance of the CBM well group with multiple coal seams when inter-well interference or inter-layer interference appears have been examined mainly based on analyzing conventional ions, hydrogen and oxygen isotopes (δD and δ18O) of 7 batches of produced water samples in the stable production period of 1 year and 4 months, and dissolved inorganic carbon (DIC) stable isotopes (δ13C DIC) of 5 batches of produced water samples by cluster analysis and geological analysis methods. The study found that the change in dynamic fluid level has a good correlation with the Q-type clustering of δD-δ18O of produced water in the process of forming inter-well interference. With the formation of inter-well interference, the δD and δ18O clustering coefficient gradually decreases, and the fluids produced from the wells become more and more similar in property. In addition to the influence of drainage time, another main geological factor affecting inter-well interference is the buried depth of the coal seam. The larger the buried depth is, the larger the cumulative production of water, the faster the water circulation, the larger the Cl− concentration in produced water, the smaller the d-excess value (δD surplus index), and the smaller the cumulative production of CBM will be. In commingled CBM production of multiple coal seams, with larger span and multiple layers, inter-layer interference is likely to occur, resulting in unbalanced productivity contribution of the layers hard to tell. Because the δ13C DIC value in produced water from a well has a positive anomaly, the producing coal seams in the well are in the middle-upper layer of coal bearing strata; these coal seams have better permeability and higher water content, higher CO 2 concentration and lower heavy hydrocarbon gas concentration offsetting each other, together with other geological conditions, it is concluded that the relatively large amount of CO 2 formed by microbial reduction is the main cause of the positive δ13C DIC abnormality. Taking this well as the calibration well, combined with the Q-type clustering result of the δ13C DIC in produced water from the well group, considering the distribution of the developed coal seams and the change of the dynamical liquid level during the stable production period of the well group, the contribution of multi-coal layers in each well were estimated. If the cluster distance between the calibration well and another well is farther, the lower layer makes a larger contribution to the CBM productivity. If the cluster distance between the calibration well and another well is closer, the middle and upper layer contribute more to the CBM productivity, and it is mainly the production layers under the liquid level that produce CBM. This provides a unique hydrogeochemical analysis method for analyzing and identifying the contribution of production layers. • The change of dynamic fluid level in CBM group has a good correlation with the Q-type clustering of δD-δ18O of produced water in the process of forming inter-well interference • The larger the buried depth of CBM well is, the larger the cumulative production of water, the faster the water circulation, the larger the Cl- concentration in produced water, the smaller the d-excess value, and the smaller the cumulative production of CBM will be. • The δ13C DIC value of produced water is negative in wells in which deep production layers make more contribution to productivity; while the δ13C DIC value of produced water is positive and larger in wells in which shallow production layers make more contribution to productivity. [ABSTRACT FROM AUTHOR]

The Fanzhuang block from the southern Qinshui basin was used as a monitoring area to determine the components, the methane carbon isotopes (δ 13 C 1 ) and the methane hydrogen isotopes (δD) of the recovered coalbed methane (CBM) during the different production times. The spatial evolution characteristics of the CBM components, δ 13 C 1 and δD and their response to inter-well interference during multi-well drainage in CBM production areas were analyzed visually. The results show that CBM components, δ 13 C 1 and δD all fluctuated; the spatial distribution direction of CBM components, δ 13 C 1 and δD also changed twice or more during sampling in the studied area. The fractionation of δD lags behind the fractionation of δ 13 C 1 . The spatial distribution of the CBM components is affected by the CBM components obtained from partial CBM wells; the spatial distribution of δ 13 C 1 and δD of coalbed methane is affected by the fractionation of δ 13 C 1 and δD from the produced CBM. The decrease in the CBM components and the δ 13 C 1 and δD ratios reveals the effects of inter-well interference on the multi-well patterns. The variability in the spatial distribution direction of CBM components, δ 13 C 1 and δD shows that inter-well interference may still be in an early stage or the degree of inter-well interference may be relatively weak. The incomplete consistency of the spatial evolution of CBM components, δ 13 C 1 and δD is mainly related to the fractionation of CBM components and methane isotopes during drainage and the change in the CBM supply caused by the unstable fluid field under unbalanced inter-well interference. It was shown that inter-well interference during multi-well drainage increases and then begins to stabilize. The established geochemical response model and evaluation program of inter-well interference provide a method to determine the stage and the degree of inter-well interference in CBM production areas, not only in the southern Qinshui basin but also in other CBM basins with low permeability. [ABSTRACT FROM AUTHOR]

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The Weirong shale gas field, located within a low-steep structural belt in southern Sichuan Basin, China, is characterized by gentle structural deformation. Production results have shown that inter-well interference, also known as fracture channeling, affects the productivity of shale gas wells by facilitating fluid flow between wells along pre-existing natural fractures. In this study, we used core observational data, scanning electron microscopy, and image logging analysis to determine the type, intensity, occurrence, and genetic mechanism of the natural fractures in the Upper Ordovician Wufeng-Silurian Longmaxi Formation. Attributes such as seismic coherence, AFE (fault-enhanced attribute), dip, and curvature were utilized to predict the macro and meso fault-fractures in the study area. We modeled the micro fault-fractures using the seismic and tracking algorithm to characterize the faults at multiple scales in the Weirong shale gas field, and then completed a comprehensive evaluation of the overall fracture development patterns with respect to the fracture channeling of neighboring shale gas wells. Results indicate that both horizontal and vertical structural fractures have been developed in the shale reservoir of the Wufeng-Longmaxi Formation in the Weirong shale gas field, although the horizontal fractures heavily outnumber the inclined ones. While a few high-conductivity macro and meso fractures display a NE-SW strike, abundant micro-faults have NE-SW and NWW-SEE strikes. Due to the pre-existing basement faults, stress fields and micro-amplitude structure, the NWW-SEE-trending micro fault-fractures are more active than those oriented in the NE-SW direction. Based on field observations, we conclude that regions with well-developed natural fault-fracture networks are more likely to have experienced fracture channeling between or within the platforms of well groups; and the NWW-SEE-trending micro fault-fractures generate more inter-well interference than the NE-SW-trending ones. Predicting the distribution and understanding the origin of the micro fault-fractures make it possible to prevent or mitigate the effects of fracture channeling during the drilling and artificial stimulation of shale gas wells. • Post-stack seismic techniques are used for fracture prediction. • Micro fractures can be accurately characterized by using tracking algorithm. • Natural fault-fracture networks are related to phenomena fracture channeling. • Predicting the micro fractures can prevent the effects of fracture channeling. [ABSTRACT FROM AUTHOR]