The depletion of producing layers leads to significant stress changes in adjacent targets, especially when complex natural fractures are present. Due to weak bedding interfaces or small stress barriers, hydraulic fractures can easily penetrate neighboring layers, and this further increases the chance of multilayer stress disturbance. In this work, we investigate the effects of vertical fracture complexity, i.e., hydraulic fracture penetration and interlayer natural fracture existence, on stress interference between different layers using a data set from a typical shale gas well in the Sichuan Basin. Two geological contexts, i.e., without interlayer natural fractures (w/o INF) and with interlayer natural fractures (w/ INF), are considered under different degrees of fracture penetration and interlayer connectivity. An in-house iteratively coupled geomechanics and compositional reservoir simulator is used to model the three-dimensional pressure and stress changes. The non-uniform hydraulic fractures and stochastic natural fractures are incorporated in our coupled simulation with an embedded discrete fracture model (EDFM). Comprehensive spatial-temporal stress analysis quantifies the approximate range of orientation change of S_Hmax and magnitude change of S_hmin under various reservoir conditions. Numerical results indicate that the presence of natural fractures in the interlayer upgrades the risk of stress interference between different pay zones. A larger hydraulic fracture penetration increases gas production, but also exerts a significant impact on stress reorientation and redistribution in the upper potential layer. The orientation change of S_Hmax along the prospective infill location is below 10 degrees in the w/o INF cases but up to 30 degrees in the w/ INF cases with a moderate number of interlayer natural fractures. The average magnitude change of S_hmin is within 3.5 MPa along the prospective infill location for most w/o INF cases, whereas that in the w/ INF cases is above 10 MPa at most times. Moreover, the existence of natural fractures in the interlayer brings forward the occurrence of maximum orientation change in the upper layer by around one year. While inducing non-negligible stress drop in the upper layer, higher interlayer matrix permeability does not significantly reorient the horizontal principal stresses. Varying the density of interlayer natural fractures not only affects the stress magnitude but also causes considerable orientation change in the upper layer. The findings from this work help understand the extent of stress interference in the upper potential layer of the Sichuan Basin under different vertical fracture complexities. It is of guiding significance for future hydraulic fracture design and child-well operations in similar highly fractured tight formations.

Summary “Fracture hit” was initially coined to refer to the phenomenon of an infill-well fracture interacting with an adjacent well during the hydraulic-fracturing process. However, over time, its use has been extended to any type of well interference or interaction in unconventional reservoirs. In this study, an exhaustive literature survey was performed on fracture hits to identify key factors affecting the fracture hits and suggest different strategies to manage fracture hits. The impact of fracture hits is dictated by a complex interplay of petrophysical properties (high-permeability streaks, mineralogy, matrix permeability, natural fractures), geomechanical properties (near-field and far-field stresses, tensile strength, Young’s modulus, Poisson’s ratio), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount), and development decisions (well spacing, well scheduling, fracture sequencing). It is difficult to predict the impact of fracture hits, and they affect both parent and child wells. The impact on the child wells is predominantly negative, whereas the effect on parent wells can be either positive or negative. The “child wells” in this context refer to the wells drilled with pre-existing active/inactive well(s) around. The “parent well” refers to any well drilled without any pre-existing well around. Overall, fracture hits tend to negatively affect both the production and economics of lease development. The optimal approach rests in identifying the reservoir properties and accordingly making field-development decisions that minimize the negative impact of fracture hits. The different strategies proposed to minimize the negative impact of fracture hits are simultaneous lease development, thus avoiding parent/child wells (i.e., rolling-, tank-, and cube-development methods); repressuring or refracturing parent wells; using far-field diverters and high-permeability plugging agents in the child-well fracturing fluid; and optimizing stage and cluster spacing through modeling studies and field tests. Finally, the study concludes with a recommended approach to manage fracture hits. There is no silver bullet, and the problem of fracture hits in each shale play is unique, but by using the available data and published knowledge to understand how fractures propagate downhole, measures can be taken to minimize or even completely avoid fracture hits.

Abstract Interwell interference has been widely observed in the development of unconventional reservoirs. It describes the phenomenon that legacy production of parent wells impact the completion quality of child wells, which in return changes production performance of both parent and child wells. This work models pressure and stress evolutions caused by parent well depletion and the corresponding asymmetric child well hydraulic fracture growth. The study presents a 3D finite-element-based fully coupled flow and geomechanics model that simulates the poroelastic behaviors of pressure and in-situ stress evolutions, and a hydraulic fracture model. Based on the simulated pressure and stress heterogeneities at and around child wells, the complex and asymmetric fracture patterns for the child well can be quantified. In the study, with several candidate child-well locations placed away from the parent well, the stress and pressure evolutions along the child well are observed to be asymmetric. Numerical investigations show that production timing of parent wells, in-situ stress contrast, well spacing, parent well fracture geometry, and the design of perforation clusters along the child wellbore are key parameters affecting the asymmetric fracturing of child wells. Specifically, prolonged parent well production, small in-situ stress contrast and close parent-child well spacing lead to significant asymmetric stress and pressure evolutions along the child well, and consequently contribute to the asymmetric fracture wing growth during child well completion. Effects of the parent-well fracture geometry on asymmetric child-well fracture wing growth are only noticeable when the well spacing is small. This work identifies key parameters in a typical interwell interference case and studies their effects on asymmetric child well fracturing. The work serves as a reference for the avoidance of child-well underperformance, which is widely observed in many major shale plays.

The existence of natural fractures in tight reservoirs causes great uncertainty in the infill-well completion. However, it is difficult to quantify the effects of natural fractures on stress evolution and frac hits due to the stochastic manner of the natural fracture system. In this work, we investigate the impact of two types of lateral complexity, i.e., parallel fracture complexity and transverse fracture complexity, on the stress redistribution and propose suggestions to mitigate frac hits during interwell fracturing. An in-house 3D coupled geomechanics and compositional simulator is used to model the pressure and stress distribution, followed by a displacement discontinuity method hydraulic fracture model to simulate the infill-well fracture propagation. Numerical results show that the parallel natural fracture serves as an attractor of stress reorientation, whereas the transverse natural fracture acts as a disperser of the orientation change. The existence of the parallel fracture complexity induces significant local stress heterogeneity around the natural fracture tip; thus, parallel rather than staggered perforation of the infill-well is favored to reduce the risk of frac hits. Since the transverse fracture complexity leads to more uniform stress reorientation between parent-well and infill-well, the perforation location is not as important as that in the parallel complexity case. By uncovering the fundamental mechanisms of lateral fracture complexity on frac hits, this work provides some insights into the interwell fracturing of tight reservoirs and will facilitate the on-site hydrocarbon production.

Summary Mitigating the negative impact of fracture hits on production from parent and child wells is challenging. This work shows the impact of parent‐well depletion and repressurization on child‐well fracture propagation and parent‐well productivity. The goal of this study is to develop a method to better manage production/injection in the parent well so that the performance of the child well can be improved by minimizing fracture interference and fracture hits. A fully integrated equation‐of‐state compositional hydraulic fracturing and reservoir simulator has been developed to seamlessly model fluid production/injection (water or gas) in the parent well and model propagation of multiple fractures from the child well. The effects of drawdown rate and production time is presented for a typical shale play for three different fluid types: black oil, volatile oil, and dry gas. The results show that different reservoir fluids and drawdown strategies for the parent wells result in different stress distributions in the depleted zone, and this affects fracture propagation in the child well. Different strategies were studied to repressurize the parent well by varying the injected fluids (gas vs. water), the volumes of the preload fluid, and so on. It was found that fracture hits can be avoided if the fluid injection strategy is designed appropriately. In some poorly designed preloading strategies, fracture hits are still observed. Last, the impact of preloading on the parent‐well productivity was analyzed. When water was used for preloading, water blocking was observed in the reservoir, and it caused damage to the parent well. However, when gas was injected for preloading, the oil recovery from the parent well was observed to increase. Such simulations of parent–child well interactions provide much‐needed quantification to predict and mitigate the damage caused by depletion, fracture interference, and fracture hits.