| Production from oil and shale gas-condensate reservoirs in the United States and Canada has increased during the past few years. However, an understanding of shale rocks and fluid flow through them is still limited. Thus, the objective of this research is to develop methodologies for characterizing multi-porosities in shale petroleum reservoirs and for simulating fluid flow of oil and condensates through these types of rocks.;The characterization part is carried out with the use of (1) an original petrophysical model built for quantification of total organic carbon (TOC), Knudsen number, water saturation, and multiple porosities in shales, (2) measurement of gas permeability from shale samples in the laboratory using commercial equipment, and (3) an original laboratory-based correlation for estimating stress-dependent permeability, porosity and compressibility of tight rocks.;The simulation part is carried out with the use of (1) an original radial numerical model developed for calculating sorption-dependent permeability of shales, (2) a commercial 3D model for investigating pore size-dependency of pressure-temperature envelopes in shale gas-condensate reservoirs, and (3) an original fully-implicit 3D-3phase pseudo-compositional model for oil and condensate shale reservoirs developed with capabilities to handle multiple porosities and stress-dependent properties of natural and hydraulic fractures.;Key challenges include the handling of (1) adsorbed porosity, (2) organic porosity, (3) inorganic porosity, (4) natural fracture porosity, (5) hydraulic fracture porosity, (6) diffusion from solid kerogen, and (7) fluid transport in the small pores of shales, which deviate significantly from the behavior in conventional reservoirs.;It is concluded that the methods developed in this thesis provide important foundation for the characterization and simulation of shale petroleum reservoirs. |
