Previous petrographic work has shown that shale petroleum reservoirs at discovery are characterized by multiple porosities. In addition there is a porosity that is generated during hydraulic fracturing jobs. Thus a quintuple porosity system might be at work when shale wells go on production.
In this work a petrophysical model is built that allows quantification of storage capabilities in shales through determination of adsorbed porosity (φads_c), organic porosity (φorg), inorganic porosity (φm), fracture porosity (φ2) and hydraulic fracture porosity (φhf). These data are important as they provide reasonable input to physics-based numerical simulators for shale petroleum reservoirs and thus more realistic projections of reservoir performance and recoveries.
Pattern recognition is used in a modified Pickett plot for distinguishing key shale components such as total organic carbon (TOC), level of organic metamorphism (LOM) and to distinguish between viscous and diffusion-like flow. Results from the model compare well against laboratory data.
The petrophysical model is robust as it can handle at the same time the 5 porosities mentioned above, but it can also handle simultaneously 4, 3, 2 or only 1 of those porosities depending on the characteristics of the reservoir at a given depth.
It is concluded that the petrophysical model presented in this paper constitutes a valuable tool for physics-based characterization of shale petroleum reservoirs. The model is developed in such a way that it can still be used even in those cases where laboratory data are not available and well log suites are not complete.