During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance. In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery. In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated. The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery. / text

Polymers play a key role in several EOR processes such as polymer flooding, surfactant-polymer flooding and alkaline-surfactant-polymer flooding due to their critical importance of mobility control in achieving high oil recovery from these processes. Numerical simulators are used to predict the performance of all of these processes and in particular the injection rate of the chemical solutions containing polymer; since the economics is very sensitive to the injection rates. Injection rates are governed by the injection viscosity, thus, it is very important to model the polymer viscosity accurately. For the predictions to be accurate, not only the viscosity model must be accurate, but also the calculation of equivalent shear rate in each gridblock must be accurate because the non-Newtonian viscosity models depend on this shear rate. As the size of the gridblock increases, the calculation of this velocity becomes less numerically accurate, especially close to wells. This research presents improvements in polymer viscosity model. Using the improvements in shear thinning model, the laboratory polymer rheology data was better matched. For the first time, polymer viscosity was modeled for complete range of velocity using the Unified Viscosity Model for published laboratory data. New models were developed for relaxation time, time constant and high shear viscosity during that match. These models were then used to match currently available HPAM polymer's laboratory data and predict its viscosity for various concentrations for full flow velocity range. This research presents the need for injectivity correction when large grid sizes are used. Use of large grid sizes to simulate large reservoir due to computation constraints induces errors in shear rate calculations near the wellbore and underestimate polymer solution viscosity. Underestimated polymer solution viscosities lead to incorrect injectivity calculation. In some cases, depending on the well grid block size, this difference between a fine scale and a coarse simulation could be as much as 100%. This study focuses on minimizing those errors. This methodology although needs some more work, but can be used in accurate predictions of reservoir simulation studies of chemical enhanced oil recovery processes involving polymers. / text