No abstract

Partially hydrolyzed polyacrylamide (HPAM) and related polymers are widely used as mobility control agents in all chemical EOR applications, and an accurate characterization of their apparent viscosity in the reservoir rock is crucial for design and performance evaluation of these processes. Their apparent viscosity in porous media generally decreases as flow velocity increases; however, beyond a certain critical velocity, the apparent viscosity sharply increases, showing shear-thickening behavior. A procedure to predict both the shear-thinning and shear-thickening apparent viscosities, from the rheometer-measured shear and oscillatory viscosities, has been developed earlier and validated with corefloods (Delshad et al., 2008). In addition to the shear viscosity database developed earlier (Lee et al., 2009), a database of the oscillatory viscosities of the EOR polymers was therefore developed for wide ranges of polymer concentration, NaCl salinity and calcium content, and temperature. The generalized Maxwell model (GMM) is employed to estimate the relaxation time of the polymer solution, by making non-linear fitting of the measured G' and G" data to GMM. Empirical correlations were developed to predict the relaxation time, which is subsequently used to quantify the shear-thickening portion of the apparent polymer viscosity under different process conditions. The apparent viscosity estimated matches reasonably with the available coreflood data.

The most effective method for stimulating unconventional reservoirs is using properly designed and successfully implemented hydraulic fracture treatments. The interaction between pre-existing natural fractures and the engineered propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical simulators use simplified model to either ignore or not fully consider the significant impact of pre-existing fractures on hydraulic fracture propagation. Pursuing development of numerical models that can accurately characterize propagation of hydraulic fractures in naturally fractured formations is important to better understand their behavior and optimize their performance.In this paper, an innovative and efficient modeling approach was developed and implemented which enabled integrated simulation of hydraulic fracture network propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leakoff and fluid flow in reservoir. This improves stability and convergence, and increases accuracy, and computational speed. Computing time of one stage treatment with a personal computer is now reduced to 2.2 minutes from 12.5 minutes than using single porosity model.Parametric studies were then conducted to quantify the effect of horizontal differential stress, natural fracture spacing (the density of pre-existing fractures), matrix permeability and fracture fluid viscosity on the geometry of the hydraulic fracture network. Using the knowledge learned from the parametric studies, the fracture-reservoir contact area is investigated and the method to increase this factor is suggested. This new knowledge helps us understand and improve the stimulation of naturally fractured unconventional reservoirs.

A three-dimensional, two-phase, dual-continuum hydraulic fracture (HF) propagation simulator was developed and implemented. This paper presents a detailed method for efficient and effective modeling of the fluid flow within fracture and matrix as well as fluid leakoff, fracture height growth, and the fracture network propagation. Both a method for solving the system of coupled equations, and a verification of the developed model are presented herein.