This paper provides an approach to model water injection and production performance observed in horizontal multi-fractured wells using a commercial finite difference (FD) model. Stress dependent permeability is used to ensure that injected rates and volumes during hydraulic fracturing are predicted by the FD model. Varying degrees of water retention observed in shale wells is modeled using gas-water imbibition capillary pressure.Hydraulic fracturing is used to stimulate shale and other ultra-tight reservoirs. During the treatment tens of thousands barrels of water are injected into a single well, distributed between many (5-30 + ) fractures. Field experience shows that a significant fraction of injected water never flows back, and the amount depends somewhat on how long the well is shut-in prior to production start.This study was conducted using a commercial black-oil reservoir simulator. A horizontal well with multiple transverse fractures is modeled. A simple stress dependent permeability model (without hysteresis) has been found to provide sufficient permeability increase during injection to ensure the magnitude of injected water rates and volumes achieved during actual fracturing operations.Inclusion of water imbibition capillary pressures helps control the amount of water retained by the rock after injection. Capillary forces redistribute injected water further into the rock than if capillarity is ignored. When a well is shut-in prior to flowback, imbibition draws injected water yet further into the rock, reducing water mobility and total recovery of injected volumes when the well starts producing. We study water flowback behavior as a function of water imbibition capillary pressure curves: their magnitude and shape (pore size distribution and wettability).The mobility of water, as given by relative permeability curves, has an impact on water imbibition and distribution of water in the shale formation near the fracture. It affects the rate of water flowback, but it has a limited effect on total water recovery. We also considered situations with the shale formation initially void of water ("dry" shales), where we find that water recovery is reduced.Modeling the flow of water in horizontal multi-fractured wells is important to estimate water loss and recovery and the impact on flow performance of hydrocarbons.

This paper describes the development of a comprehensive 2D near wellbore reservoir model to history match and predict the not yet fully understood production performance and deliverability of horizontal wells producing a heavy viscous oil (~300 cp). This in the presence of water conning from an active aquifer. The target application is heavy oil reservoirs (e.g. Rubiales field, Colombia) with rapidly increasing or high producing water cut (~90%), constant reservoir pressure maintained by an active aquifer, and high horizontal pay zone permeability (~15 D).The methodology employs a simplified 2D horizontal wellbore reservoir model with enough flexibility (i.e. tuning parameters) to match the measured wells production profile (i.e. water production and producing water cut). One well with full production record was analyzed.The following modeling strategies were tried out: providing an adequate pressure support from the aquifer, increasing artificially the oil mobility in the porous media as the water saturation increases and hindering the vertical water migration from the aquifer towards the well. These modeling strategies added additional tuning variables besides the conventional formation parameters.Model parameters were varied automatically using an optimization engine minimizing the difference between the simulated and the measured data.Several modeling approaches were tried out in the simulator: standalone variation of the oil viscosity, oil viscosity variation with water saturation, oil-water emulsion behavior using inversion point and Richardson model, Fetkovich type numerical aquifer, water injector with constant bottom-hole pressure and tunable injectivity index, initial water saturation variation with depth within oil zone.Almost all the modeling approaches yielded an acceptable history match (Ͻ6%) for water production profiles. The match of the bottomhole pressure is more challenging, as satisfactory residuals are only obtained in certain production periods. It was not possible to reproduce the bottomhole pressure trend considering simple aquifer volumetric expansion and emulsion behavior throughout the entire reservoir domain.The present paper proposes the utilization of a simplified 2D near wellbore reservoir model to successfully represent the performance of viscous oil high water cut producing wells with complex physics. The results show that it is possible to overlook the complexity of such reservoirs by Љwrapping them upЉ in a few macro parameters and still keeping physical consistency.