The orientation and size of fractures created during hydraulic stimulation is governed by the in-situ stress state. Reservoir production changes both the magnitude and the direction of the principal stresses, and these stress changes can be calculated using a geomechanical model. In this study, we employ a 4D geomechanical model calibrated with time-lapse seismic time shift data to understand the direction of fracture growth during hydraulic stimulation of a horizontal injector well. The horizontal well was drilled in the (expected) direction of the maximum horizontal stress, such that the strike direction of the fractures is aligned with the wellbore axis. Our study shows that production from a nearby well has rotated the directions of horizontal stresses, and some of the hydraulic fractures now grow perpendicular to the wellbore axis. The stress-field calculations and predicted directions of hydraulic fractures are substantiated by the observed time-lapse seismic amplitude signal. This signal shows increased fluid flow in the predicted fracture direction for individual stimulated zones.

Cold Heavy Oil Production with Sand (CHOPS) has been widely and successfully applied for the last three decades in the Heavy Oil Belt region that straddles the provinces of Alberta and Saskatchewan in Canada. As its name suggests, the method relies on continuous production of sand to improve the recovery of oil from the reservoir. In CHOPS, a significant pressure drawdown around the wellbore is created by using progressive cavity pumps, which causes the loosely consolidated formation to fail, creating increased permeability channels, usually called wormholes, through which, a slurry-like mixture of sand, oil and water flows. Many attempts have been made to use conventional numerical reservoir simulators to model the CHOPS process. However, many of the commercial finite-difference reservoir simulators do not incorporate capabilities to model the complex geomechanical processes responsible for the failure of poorly consolidated formations in CHOPS. To circumvent these limitations, several approaches have been proposed. The most common relies on explicitly defining high permeability channels that radiate from the producing wells in an attempt to mimic wormholes created during CHOPS production. In this paper, we present a different, more rigorous approach that relies on the coupling of a finite-element geomechanical simulator with a finite-difference reservoir simulator. In the coupling process, the geomechanical simulator uses the pressure gradients calculated by the reservoir simulator to determine changes in the stress regime of the reservoir. In the case of CHOPS, these changes cause failure in the loosely consolidated formation, which in turn induces sand production with a corresponding increase in porosity and permeability. The new porosity and permeability values in the affected gridblocks are then fed back to the reservoir simulator, which is now capable of incorporating the effects of formation failure into fluid flow calculations. This process is then repeated at user-controlled intervals during the course of the simulation. The methodology has been validated by successfully history matching the production data from a section of a heavy oil field operated by Husky Energy in Western Canada. In this paper we compile the data integration efforts to create a coupled geomechanical model and the results of the history match.

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