Numerical simulation of poroelasticity and multiphase flow in matrix-fracture system: application to Niobrara Formation, DJ Basin

Abstract

Production performance of unconventional reservoirs is affected by the coupled interaction between fluid depressurization and rock deformation. These reservoirs consist of a matrix, macro- and micro-fractures of which accurate representation of this dual-porosity system is needed to model fluid flow. The governing equations for fluid flow transport and rock deformation depend on the effects of elastic rock properties and stress-dependent rock parameters such as porosity and permeability. Thus, there is a need for determining proper rock frame modulus affected by the interconnected fractures. Similarly, there is a need for knowing rock matrix modulus for modeling the long-term production performance of unconventional shale reservoirs. This dissertation presents a new formulation for a numerical model that utilizes linear poroelastic theory and three-phase flow in the dual-porosity setting. Changes in pore pressure during production causes decrease in porosity, permeability, and reduction in the pore volume which, in turn, is reflected by an increase in pore compressibility. However, most of the coupled geomechanics and flow simulation models assume constant pore compressibility in their formulations and include only the updated porosity and permeability values. The new model presented in this dissertation addresses this issue and include the changes in pore compressibility with updated porosity and permeability. The numerical model is discretized using finite difference approach with Implicit Pressure and Explicit Saturation (IMPES) in the Eulerian stationary coordinate frame. However, rock deformation is accounted in each cell and used to calculate the correct porosity values. To use the model in applications, an integrated reservoir characterization of Niobrara shale formation is performed using microseismic, core, well log, fluid properties, and the production/pressure data which are provided by Reservoir Characterization Project (RCP) and Anadarko Petroleum Corporation. The results from production analysis using rate transient, decline curve, and an analytical hydraulic fracture propagation model for each well are used as input parameters for the simulation model. The reservoir model provides an accurate representation of driving mechanisms and its applications to long-term production trend. Moreover, the effect of elastic rock properties, such as bulk rock modulus, and reservoir heterogeneity on reservoir performance is investigated. The results showed that higher cumulative hydrocarbon production is obtained if the bulk rock modulus of the dual-continua system has a smaller value. It is also observed that the energy provided by the reservoir compaction increases cumulative fluid production, and numerical simulation models that have constant compressibility values in their transport equations underestimate the cumulative production.