Stress re-orientation occurs around fractured production wells because of (a) mechanical effects due to presence of propped fractures and (b) poroelastic effects due to production from stimulated rock volume. The in-situ stresses, which govern the propagation direction and geometry of hydraulic fractures, are thus modified not only in magnitude but also in direction. Previous field observations and modeling efforts have demonstrated the impact of stress reorientation and non-uniform pore pressure distribution on the success of refracturing and infill well fracturing operations.

In this work, we developed a compositional fluid flow model using an equationof state (EOS) which is fully coupled with reservoir geomechanics. The partial differential equations, namely displacement, pressure and component balances, are discretized using finite volume method and the coupled system is solved using either the fixed strain-split or fixed stress-split algorithms. The model can handle any number of hydrocarbon components and three phases (oil, water and gas). Thus density, fluid compressibility and viscosity are not assumed to be constant, but change with pressure. Multiphase flow with relative permeability effects, phase equilibrium and appearance of gas phase when pressure falls below bubble point due to depletion are taken into account. In order to account for mechanical stress reorientation due to propped fractures with non-zero width, uniform stress boundary condition is applied on the fracture face such that it is equal to pressure required to maintain the propped width.

Firstly, the developed model is verified against analytical and standard solutions for mechanics, fluid flow and poroelasticity coupling. The model is then used to quantify the impact of prior production from fractured production wells on the
occurrence and timing of stress changes around the well and in the infill region between two wells. We found that past production impacts not only the direction of principal horizontal stresses, but also the value of the horizontal stress contrast. For a gas reservoir, extent of stress reorientation cannot be felt much further away from the production well as compared to liquid rich reservoir due to higher compressibility of gases. For a liquid rich reservoir (mainly volatile oil), accounting the appearance of gas phase during production (due to pore pressure going below bubble point) decreases the distance to which stress reorientation can be felt away from the fracture. At any distance away from the fractured well, stress reorientation occurs at a later time if multiphase flow and relative permeability effects are taken into consideration.

This work allowed for the first time to study and quantify the effect of phase equilibrium, multiphase flow and non-constant fluid properties on stress reorientation around fractured production wells. Complex reservoir fluids have been accounted for in a rigorous way, without making assumptions of incompressible, single phase fluids with constant fluid properties. The new observations have
significant implications for design strategies in refracturing and infill well fracturing operations.