Inferring Inter‐Well Fracture Interactions in Unconventional Reservoirs Using Fiber‐Optic Sensing and Coupled Multiphysics Modelling

ABSTRACT

Integrating distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) data with numerical simulations to analyze inter‐well interference and production responses remains challenging. This study employs a coupled thermal–hydraulic–mechanical simulation framework to model heat transfer, fluid flow, and geomechanical responses associated with the initiation and propagation of multiscale fractures. To represent fractures across different scales, the framework integrates commercial simulation capabilities with external scripts, including a new method for simulating natural‐fracture reactivation and closure and a dynamic scheme for updating matrix permeability associated with non‐Darcy gas flow. The results show that frac hits can significantly affect fracture growth, thermal behavior, and flowback performance at nearby perforation intervals, with their impacts depending on proximity, intensity, time since formation, and offset‐well production status. These findings have direct implications for fracture‐stimulation design, indicating that stimulation spacing, treatment sequencing, and offset‐well operating conditions should be considered together to manage fracture interference, maintain effective connectivity, and improve flowback performance. Low‐frequency DAS observations are used to constrain frac‐hit timing and location, while DTS responses are directly compared with simulated temperature behavior in a field example. Near‐wellbore DAS observations further provide qualitative constraints on relative flowback distribution. The simulations reproduce key features observed in the field DTS data and provide physical explanations for their complex temperature responses. Overall, this study demonstrates a practical framework for integrating fibre‐optic observations with coupled multiphysics simulations to improve fracture diagnosis, support stimulation‐design decisions, and assess treatment efficiency and stimulated reservoir volume under different frac‐hit scenarios.