Abstract
This paper describes a new modeling framework for microscopic to reservoir-scale simulations of hydraulic fracturing and production. The approach builds upon a fusion of two existing high-performance simulators for reservoir-scale behavior: the GEOS code for hydromechanical evolution during stimulation and the TOUGH+ code for multi-phase flow during production. The reservoir-scale simulations are informed by experimental and modeling studies at the laboratory scale to incorporate important micro-scale mechanical processes and chemical reactions occurring within the fractures, the shale matrix, and at the fracture-fluid interfaces. These processes include, among others, changes in stimulated fracture permeability as a result of proppant behavior rearrangement or embedment, or mineral scale precipitation within pores and microfractures, at µm to cm scales. In our new modeling framework, such micro-scale testing and modeling provides upscaled hydromechanical parameters for the reservoir scale models. We are currently testing the new modeling framework using field data and core samples from the Hydraulic Fracturing Field Test (HFTS), a recent field-based joint research experiment with intense monitoring of hydraulic fracturing and shale production in the Wolfcamp Formation in the Permian Basin (USA). Below, we present our approach coupling the reservoir simulators GEOS and TOUGH+ informed by upscaled parameters from micro-scale experiments and modeling. We provide a brief overview of the HFTS and the available field data, and then discuss the ongoing application of our new workflow to the HFTS data set.
Highlights
Production of oil and gas from unconventional reservoirs largely depends upon two main features operating at different scales: (1) the reservoir-scale stimulated fracture network providing permeability and transport from the formation to the production wells, and (2) the coupled multi-phase flow, mechanical and chemical processes affecting the migration of hydrocarbons from the low-permeability shale into the fracture network
We focus on the performance of the geomechanical code for reservoir-scale stimulation (GEOS)-TOUGH+ coupling scheme; the matrix is treated as a single continuum where secondary and natural fractures are limited and/or discontinuous, and their effects are sufficiently small to allow their incorporation into the matrix porosity and permeability, allowing matrix representation as a single continuum
We have developed a new multi-scale simulation framework for unconventional stimulation and production
Summary
Production of oil and gas from unconventional reservoirs largely depends upon two main features operating at different scales: (1) the reservoir-scale stimulated fracture network providing permeability and transport from the formation to the production wells, and (2) the coupled multi-phase flow, mechanical and chemical processes affecting the migration of hydrocarbons from the low-permeability shale into the fracture network. Several recent studies involving a variety of sophisticated imaging and testing methods have improved our fundamental understanding of such processes and have provided a basis for developing constitutive upscaling relationships that can be used in reservoir models These include, for example, the permeability evolution of propped fractures in different types of shales over a range of stress conditions [13] or the fracture aperture changes and proppant embedment in shales exposed to different types of fracturing fluids [14,15]. In addition to a full set of geophysical and other observations (such as microseismic signals, tilt, downhole pressure variations, tracer transport, and production data) which can be used to test the GEOS-TOUGH+ reservoirscale simulations, the HFTS project obtained core samples from a science observation well that was drilled through the stimulated volume after hydraulic fracturing This core provided a rare opportunity to observe and evaluate the geometry and properties of hydraulic fractures, and to compare their characteristics with pre-existing natural fractures. Details on individual modeling or experimental elements will be presented in future publications
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