The reorientation of local principal stresses largely depends on the drainage range and extent associated with complex hydraulic and natural fractures. In this regard, an iteratively coupled three-dimensional (3D) fluid flow and geomechanics model is adopted to simulate the local principal stress responses caused by stochastic hydraulic fracture properties at two prospective infill locations. The hydraulic fracture parameters including fracture half-length, width and height are varied stochastically within a set range of different ‘small-to-large’ ratios. Numerical results show that fracture half-length has the biggest impact on stress changes in the producing-layer infill location. Longer hydraulic fractures significantly advance the occurrence of stress reversal. On the other hand, stress reorientation is less sensitive to changes in fracture width and height in our located parameter range. Natural fractures of different lengths have also been investigated, and the results show that longer natural fractures accelerate stress reversal. Valuable insights on infill-well fracturing timing are provided for different fracture distributions based on the altered stress fields.

1. Introduction

The development of unconventional shale reservoirs typically entails hydraulic fracturing. Production from the hydraulically induced fractures triggers changes in the in-situ stress field. Such poroelastic stress changes have long been acknowledged in literature (Mack and Elbel, 1994; Berchenko and Detournay, 1996). The local reduction in pore pressure gradient leads to stress redistribution or even stress reversal within an elliptical region around the initial fracture defined by isotropic points; as a result, hydraulic fracture propagation will be altered (Siebrits and Elbel, 1998). Thus, a comprehensive understanding of the in-situ stress changes is crucial in reservoir management and can aid in infill planning.

Typically, infill wells are part of the field development plan as the operators need to secure land leases (Miller et al., 2016). Afterwards, infill drilling and fracturing will start near the parent wells to produce the less-depleted regions of the reservoir. Utilizing learnings from production-induced poroelastic stress changes, Safari et al. (2017) suggest performing infill fracturing at the time of stress reversal with higher viscosity fracturing fluid to maximize the effectiveness of child fractures. However, they did not consider stress-dependent permeability during production, and their model was limited to reservoirs free of natural fractures. Later, Jin and Zoback (2018) used a fully coupled fracture-poromechanical numerical model to study the stress evolution around one stage of hydraulic fractures in a naturally fractured reservoir. They proposed the novel idea that natural fractures can arrest frac-hits and redirect child fractures. They also indicated that if stress reversal has occurred surrounding the parent well, hydraulic fractures from the infill well could propagate parallel to the parent well. Aside from hypothetical numerical experiments, a field case study has been done by Pei et al. (2021) that uses an integrated reservoir-geomechanics-fracture model to investigate the infill timing and locations in the upside target of the Permian Basin. They observed that larger horizontal or vertical offset between parent and child wells leads to better fracturing efficacy and well production. In addition, an earlier infill time is recommended to avoid significant overlapping between parent-well and child-well fractures. In summary, in-situ stress changes provide significant implications for further infill operations and require a detailed investigation under complex reservoir conditions.

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