Identification of favorable production zones in hydrocarbon-bearing shale often requires the quantification of in-situ mechanical properties. These properties are also necessary for the optimal design of hydro-fracturing operations. Rock elastic properties are affected by volumetric concentrations of mineral constituents, porosity, fluid saturations, and total organic carbon (TOC). Rapid depth variations of rock properties often encountered in shale gas formations make conventional petrophysical interpretation methods inadequate to estimate volumetric concentration of mineral constituents. We introduce a new method to assess elastic properties of organic shale based on the combined quantitative interpretation of sonic, nuclear, and resistivity logs. In-situ elastic properties of organic shale are estimated by (a) improving the assessment of volumetric concentrations of mineral constituents, (b) implementing reliable rock physics models and mixing laws for organic shale, and (c) numerically reproducing wideband frequency dispersions of Stoneley and flexural waves. An example of the application of the method is described in the Haynesville shale gas formation. Estimates of mineral concentrations, porosity, and fluid saturations are in agreement with available laboratory core measurements and X-Ray Diffraction (XRD) data. Calculated layer-by-layer P- and S-wave velocities differ by less than 15% from measured velocities thus confirming the reliability of the method. Finally, based on the new interpretation method developed in this thesis, correlations are found between mineral concentrations, TOC, porosity, and rock elastic properties, which can be used in the selection of optimal production zones. / text

The main objective of this dissertation is to quantify petrophysical properties of conventional and unconventional reservoirs using a mechanistic approach. Unconventional transport mechanisms are described from the pore to the reservoir scale to examine their effects on macroscopic petrophysical properties in hydrocarbon-bearing organic shale. Petrophysical properties at the pore level are quantified with a new finite-difference method. A geometrical approximation is invoked to describe the interstitial space of grid-based images of porous media. Subsequently, a generalized Laplace equation is derived and solved numerically to calculate fluid pressure and velocity distributions in the interstitial space. The resulting macroscopic permeability values are within 6% of results obtained with the Lattice-Boltzmann method after performing grid refinements. The finite-difference method is on average six times faster than the Lattice-Boltzmann method. In the next step, slip flow and Knudsen diffusion are added to the pore-scale method to take into account unconventional flow mechanisms in hydrocarbon-bearing shale. The effect of these mechanisms is appraised with a pore-scale image of Eagle Ford shale as well as with several grain packs. It is shown that neglecting slip flow in samples with pore-throat sizes in the nanometer range could result in errors as high as 2000% when estimating permeability in unconventional reservoirs. A new fluid percolation model is proposed for hydrocarbon-bearing shale. Electrical conductivity is quantified in the presence of kerogen, clay, hydrocarbon, water, and the Stern-diffuse layer in grain packs as well as in the Eagle Ford shale pore-scale image. The pore-scale model enables a critical study of the [delta]LogR evaluation method commonly used with gas-bearing shale to assess kerogen concentration. A parallel conductor model is introduced based on Archie's equation for water conductivity in pores and a parallel conductive path for the Stern-diffuse layer. Additionally, a non-destructive core analysis method is proposed for estimating input parameters of the parallel conductor model in shale formations. A modified reservoir model of single-phase, compressible fluid is also developed to take into account the following unconventional transport mechanisms: (a) slip flow and Knudsen diffusion enhancement in apparent permeability, (b) Langmuir desorption as a source of gas generation at kerogen surfaces, and (c) the diffusion mechanism in kerogen as a gas supply to adsorbed layers. The model includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. Gas desorption from kerogen surfaces and gas diffusion in kerogen are the main mechanisms responsible for higher-than-expected production velocities commonly observed in shale-gas reservoirs. Slip flow and Knudsen diffusion marginally enhance production rates by increasing permeability during production. / text