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Pressure and stress fields after the phase one production: a formation pressure p; b minimum horizontal stress; c orientation of maximum horizontal stress σ H
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Stimulation of unconventional tight oil formations via horizontal wells has seen increasing cases of fracturing infill wells in recent years. The effectiveness of such a strategy is mainly dependent on the proper characterization of the stress evolution and an accurate forecast of the subsequent fracture propagation in the region neighboring the in...
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... distribution of the simulation model are consistent with the field production log data. The production data obtained from the numerical simulation are close to the recorded, as displayed in Table 4. The formation pressure, minimum horizontal stress, and orientation of maximum horizontal stress after phase one are calculated and presented in Fig. 6. It is demonstrated that after phase one production, the formation pressure p in well M-P1 decreased from 35 to 12 MPa, while the minimum horizontal stress σ h declined from 56 to 46 MPa. The orientation of maximum horizontal stress σ H is most significantly affected at the south end of well M-P1, displaying a rotation of up to 30° to ...
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... production, the formation pressure p in well M-P1 decreased from 35 to 12 MPa, while the minimum horizontal stress σ h declined from 56 to 46 MPa. The orientation of maximum horizontal stress σ H is most significantly affected at the south end of well M-P1, displaying a rotation of up to 30° to its original azimuth (marked by the red ellipse in Fig. ...
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... is discovered that the M-P1 production has little impact on the region between the M-P2 and M-P3 wells (c.f., Fig. 6). The effects of injection on pore pressure and stress field are evaluated in terms of the magnitude of pressure and the orientation of σ H (represented as blue-colored arrow lines in Fig. 9c), the latter of which largely determines the paths of the hydraulic fractures. Figure 9 represents the pressure and stress field after injection ...
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... 7c shows that the depletion of the parent wells causes a rotation of the fractures (relative to the normal direction) in the infill well ranging from 25 to 45 degrees due to the alteration of the stress field. Figure 16 shows the fracture geometry obtained by fracturing the infill wells directly after the production of the three old wells ended. Figure 16a shows the fracture propagation of the three clusters at the 16th stage, while Fig. 16b shows an enlarged view. ...
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... 16 shows the fracture geometry obtained by fracturing the infill wells directly after the production of the three old wells ended. Figure 16a shows the fracture propagation of the three clusters at the 16th stage, while Fig. 16b shows an enlarged view. The relatively small simulation time leads to the slightly extended fractures in the child well. ...
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... to the normal direction) in the infill well ranging from 25 to 45 degrees due to the alteration of the stress field. Figure 16 shows the fracture geometry obtained by fracturing the infill wells directly after the production of the three old wells ended. Figure 16a shows the fracture propagation of the three clusters at the 16th stage, while Fig. 16b shows an enlarged view. The relatively small simulation time leads to the slightly extended fractures in the child well. As the legacy production time for parent wells increases, the fractures along the infill well become more longitudinal ( Guo et al. 2019a, b). On the other hand, the complete fracturing process was not fully ...
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... the deflection of infill well fractures in this research demonstrates the quality of infill well completion, especially the SRV of the infill area. Figure 16 shows that the fracture geometries at the infill well are complex, implying that the stress field has seriously been disturbed by the production of the parent wells. Fig.16 The fracture configuration of the 16th stage of M-I2 after parent well production ...
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... 16 shows that the fracture geometries at the infill well are complex, implying that the stress field has seriously been disturbed by the production of the parent wells. Fig.16 The fracture configuration of the 16th stage of M-I2 after parent well production ...
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... and are much lower than in other zones. Figure 17 displays the fracture propagation after fracturing the M-I2 using different injection volumes at the parent wells. As the ξ i increases from 0 to 0.25, 0.3, and 0.5, the rotation angle of the middle fracture (marked by the red line segment) decreases from 26 to 18, 16, and 2 degrees gradually (Figs. 16 and 17). The angle decreases with the increase in injection volume at the old well, and eventually reaches 2 degrees when ξ i becomes 0.5. In addition, a larger fracture deflection seems to be accompanied by stronger fracture interference. The two clusters of fractures in Fig. 16b repulse each other, whereas such an interference declines at an ...
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... segment) decreases from 26 to 18, 16, and 2 degrees gradually (Figs. 16 and 17). The angle decreases with the increase in injection volume at the old well, and eventually reaches 2 degrees when ξ i becomes 0.5. In addition, a larger fracture deflection seems to be accompanied by stronger fracture interference. The two clusters of fractures in Fig. 16b repulse each other, whereas such an interference declines at an increased injection volume in the parent well. Figure 18 examines the fracture patterns of the infill well under the zero and 30 days of soaking. Before soaking, both models are injected 0.3 times the depletion volume fluid to recover the formation pressure (schemes 3 & 4 ...
Citations
... Fracturing technology is an important technology in petroleum engineering and plays a critical role in many applications within the oil and natural gas industry. The process can be generally considered as the intentional (or unintentional) initiation and propagation of a fracture due to the pressurization of fluid that flows within the fracture (Shi et al. 2023). Examples of applications include (a) the stimulation of rock formations with poor or damaged permeability to increase conductivity between the reservoir and the producing wells, (b) improvement of produced water reinjection (PWRI) where water is injected to replace produced fluids and maintain reservoir pressure or provide enhanced oil recovery, (c) cuttings reinjection (CRI) where a slurry of drill cuttings is injected into a formation to mitigate the cost and risk of surface disposal, (d) in situ stress measurement by balancing the fracturing fluid pressure in a hydraulically opened fracture with the geostatic stresses, and (e) wellbore integrity analysis of drilling operations to avoid propagating near-wellbore fractures that could result in drilling fluid losses to the formation and an inability to effectively clean the wellbore. ...
Controllable shock wave (CWS) parameters such as amplitude, operating area and number of operations are easy to control and have received extensive attention as a potential new technology for reservoir permeability enhancement. Based on the continuous-discontinuous element method (CDEM) and considering the coupling mechanism of reservoir deformation, failure, pore seepage and fracture flow, a multiphysical field coupling model of reservoir permeability enhancement under CWS is proposed. Under the fluid–solid coupling condition, the formation and development dynamic process of reservoir fractures are obtained, and the change of reservoir permeability is also obtained. The compression fracture zone, tensile fracture zone and undamaged zone are formed around the wellbore. After repeated impact, the number of fractures is more sensitive to tectonic stress, the fracture aperture is more sensitive to reservoir strength. Different from hydraulic fracturing, a large number of fractures in different directions will appear around the main fracture after repeated impact, forming a complex fracture network similar to spider web, which may be beneficial to improve reservoir permeability. The permeability of reservoirs with different tectonic stresses and strengths increases nonlinearly and monotonicly with repeated impacts. Based on CDEM, the change of reservoir permeability with tectonic stress, strength and impact times is obtained, which is a nonlinear monotonic three-dimensional relationship. Based on that relationship, the parameters of CWS can be controlled to predict the change of reservoir permeability, such as peak pressure, duration, impact times, etc. Therefore, it can optimize the reservoir fracturing scheme and improve the reservoir fracturing efficiency, which has considerable practical significance in engineering.
In the unconventional oil and gas domain, shale gas development adheres to the technical concept of "tight well spacing and infill well." Infill wells, along with large-scale hydraulic fracturing, have become effective strategies for increasing shale gas production. Nevertheless, during hydraulic fracturing operations in the horizontal wells, there is often a risk of frac hits due to geological and engineering factors, which has a significant adverse impact on on-site operations, resulting in lower individual well production and posing challenges to the efficient development of shale gas. Managing frac hits is critical for the industry's growth rate in future. Therefore, based on the current state of hydraulic fracturing in the southern Sichuan shale gas, this study aims to clarify the mechanisms of frac hits and the influencing factors, and to propose effective methods for preventing frac hits, thereby improving the performance of gas wells.
In this article, we employed a fully coupled reservoir-fracture-wellbore geomechanical simulation method originated from Zheng (2019a), combined with the establishment of shale gas diffusion properties, to establish a frac hits model. A detailed analysis of the mechanisms and influencing factors of frac hits between shale gas wells under different interference patterns were conducted, and the effectiveness of mitigation methods for each pattern was validated. The results indicate that in reservoirs with developed natural fractures, the fractures in stimulated wells tend to propagate easily along these natural fractures, affecting offset wells. To some extent, this impact can be mitigated by avoiding fracturing in the risky stages. Similarly, the depletion of offset wells leads to a rapid decrease in rock pressure around the fracture tip. Due to the influence of pore elastic effects, rocks undergo elastic deformation, resulting in low-stress zones. The fractures in stimulated wells are affected by this phenomenon and tend to propagate towards offset wells, causing frac hits. The application of pre-pressurization in offset wells can lower the occurrence rate of frac hits.
The simulation of inter-well interference between offset wells and stimulated wells provides a theoretical foundation for understanding the frac-hit phenomenon in the southern Sichuan shale gas. This method can be used to predict or mitigate the risk and damage associated with frac hits.
