We present a workflow to estimate recovery in unconventional reservoirs that uses flow simulation models constrained by seismic data, geomechanical parameters, and hydraulic stages properties. The goal of the workflow is the rapid testing of different hydraulic stage scenarios in the presence of natural fractures and other hypotheses that can be compared to select the one that yields optimal recovery. All the parameters of interest are generated directly into a flow simulation grid centered on the horizontal well. Thickness of hydraulic stages equals that of one cell of the simulation grid and therefore, details of individual hydraulic fractures are not explicitly considered allowing modeling of larger reservoir scale effects on recovery. The first step is the estimation of natural fracture orientations using seismic data calibrated with independent fracture information. Then, the flow grid is also populated with geomechanical parameters such as stress field and stress orientations, pore pressure, and friction coefficient. After defining locations and geometry of hydraulic stages along the well path and assuming fluid pressure decay functions away from the hydraulic stages, we use Mohr-Coulomb faulting theory to estimate which natural fractures are more prone to reactivation after hydraulic stimulation. This volume of reactivated natural factures is then upscaled to effective fracture permeability that serves as input to an ultra-fast dual-permeability flow simulator. Finally, once the model is in the flow simulator, we use fluid properties and other dynamic parameters for calibrating with production information, changing the simulation model if needed, and performing long term forecast. We illustrate the application of the workflow in the Eagle Ford formation (South Texas) using a data set that consists of 3D seismic, outcrop descriptions, geomechanics measurements, and production information.
Unconventional reservoirs are characterized by extremely low permeabilities that hinder fluid communication between the reservoir and the borehole. These permeabilities are enhanced by the generation of hydraulic fractures after high-pressure fluid is injected into the formations of interest. Even though hydraulic fractures are the main source of permeability enhancement near the wellbore, reactivation of existing natural fractures in the vicinity of the hydraulic fractures is also an important mechanism of self-propped permeability enhancement in the stimulated reservoir volume (SRV) (Gutierrez et al., 2000; Zhang and Li, 2016; Rutledge and Phillips, 2003) and the hydraulic fractures regions (Jeffrey, 2010; Maxwell, 2011).
Reactivation of existing natural fractures depends on the current state of stress, orientation and intensity of existing natural fractures relative to the stress field, injected fluid pressures, rock properties, and geometry of hydraulic stages. In this paper, we consider all these parameters in an integrated fashion that uses Mohr-Coulomb faulting theory to estimate the likelihood of slip of existing natural fractures. Then, we use simple aperture versus fluid pressure assumptions to generate effective permeability volumes of reactivated fractures.