Modelagem multiescala de reservatórios não convencionais de gás contendo redes de fraturas naturais e hidráulicas

• Autor(a) principal: Rocha, Aline Cristina da
• Data de Publicação: 2017
• Tipo de documento: Tese
• Idioma: por
• Título da fonte: Biblioteca Digital de Teses e Dissertações do LNCC
• Texto Completo: https://tede.lncc.br/handle/tede/263
• topic: Reservatórios de gás; Modelagem multiescala; Termodinâmica de gases confinados; Gas reservoirs; Multiscale modeling; CNPQ::ENGENHARIAS::ENGENHARIA QUIMICA::TECNOLOGIA QUIMICA::PETROLEO E PETROQUIMICA

In this work we construct a new multiscale computational model to describe the flow of gases in unconventional reservoirs (shale gas) containing distinct levels of fractures (natural and hydraulic). Such reservoirs exhibit peculiar characteristics that make an accurate description of the physical phenomenon involved a hard task. Among the characteristics we can highlight the low permeability (order of nanodarcys) and the multiple levels of porosity related to the multiple scales involved. In the present work the multiscale modeling of the gas flow is built with the formal homogenization procedure. The geological formation is characterized by four distinct length scales. The finest one, the nanoscopic, is related to the nanopores in the organic matter (kerogen) where gas is adsorbed. In order to accurately describe the gas adsorption in kerogen we pursue in the context of the Thermodynamics of Inhomogeneous Fluids. More precisely, the isotherms that describe the gas adsorption in nanopores are built based on the Density Functional Theory (DFT). The upscaling to the microscale is reached through the homogenization procedure. The window of observation related to this scale is composed of kerogen aggregates and inorganic matter (clay, quartz, calcite). Such phases are separated by the network of interparticle pores exibting characteristic length between 10^{-4} and 10^{-9} meters. The micropores are partially-saturated, filled with a free gas phase in thermodynamic equilibrium with the dissolved gas in the aqueous phase. The model considers immobile water phase with the equation of fickian diffusion of the dissolved gas coupled to the Darcyan flow of the free gas. At the mesoscale the shale matrix (where interparticle pores, kerogen aggregates and inorganic matter are envisioned as an homogenized media) is intertwined by the network of natural fractures exhibiting preferred paths for the flow of gas. The upscaling of this coupled system of partial differential equations gives rise to a macroscopic model of double porosity in the sense of Arbogast and coworkers (ARBOGAST; DOUGLAS JR.; HORNUNG, 1990). Within this context the shale matrix behaves as a microstructural distributed mass source term in the mass balance equation that describes the gas movement in the homogenized network of natural fractures. Finally we establish the coupling between the hydrodynamics in the networks of natural and hydraulic fractures, where single phase gas flow takes place. Such coupling is accomplished by reduced dimension techniques where induced fractures are treated as (n-1), n = 2,3 lower dimensional geological objects. The resulting model is composed of three partial differential nonlinear equations governing the gas hydrodynamics in the shale matrix and networks of natural and hydraulic fractures. In order to decouple the system we proceed within the context proposed by Arbogast (ARBOGAST,1997) which adopts a variable decomposition leading to the numerical solution of independent subsystems. This strategy allows the solution of the system mentioned above to be made in a sequential form avoiding additional iterations between the subsystems. The resultant governing equations are discretized by the finite element method with the introduction of submeshes to threat the gas transport in shale matrix and compute the source term in the pressure equation of the natural fractures network. The discretized model is used to simulate gas production as well as transient well tests. Promising numerical results are obtained which can be used to improve the description of the involved phenomena giving rise to new diagnostic curves to the characterization of unconventional reservoirs.