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

Horizontal drilling and hydraulic stimulation make hydrocarbon production from organic-rich shales economically viable. Identification of suitable zones to drill a horizontal well and to initiate or contain hydraulic fractures requires detection and quantification of many factors, including elastic mechanical properties. Elastic behavior of rocks is affected by rock composition and fabric, pore pressure, confining stress, and other factors. Rock fabric refers to the arrangement of the rock’s solid and fluid constituents. The objective of this thesis is to quantify rock fabric properties of hydrocarbon-bearing shales affecting elastic properties, including load-bearing matrix, anisotropic cracks, and shape of rock components. Once rock fabric is validated with sonic logs, results can be used to identify suitable zones to drill a horizontal well, initiate hydraulic stimulation, and contain fracture propagation. We develop a method to estimate elastic properties based on rock composition. The differential effective medium (DEM) theory is invoked to model rock elastic properties with a load-bearing component in which remaining minerals and pores are added as spheres or ellipsoids. The method can be combined with the self-consistent approximation (SCA) to construct a load-bearing matrix made of two solid phases. Anisotropic inclusions are added via Hudson’s model. Subsequently, Gassmann’s theory is invoked to saturate the rock with fluids and determine low-frequency elastic properties for comparison to sonic logs. Rock fabric properties remain constant in a vertically homogeneous formation. In vertically heterogeneous strata, the depth interval of interest is divided into rock types, based on rock solid composition, and each rock type is associated with a specific fabric. Quantification of rock fabric properties is a non-unique process, and one should take into account as much petrophysical and geological information as possible to ensure physically viable results. Our simulation and interpretation method is implemented in two wells in both the Haynesville and Barnett shales. Averages of relative errors between estimated velocities and sonic logs are less than 4% in the four wells. Simulations in the Haynesville shale are isotropic, and therefore indicate that rock fabric may not be the main cause of mechanical anisotropy in cases where such behavior is inferred from field data. Rock fabric properties are constant with depth in both wells. Consequently, identification of suitable zones to drill a horizontal well or to contain fracture propagation is not based on rock fabric; it is deduced from Young’s modulus. Simulated Poisson’s ratio is shown to be more sensitive to errors in velocities than Young’s modulus and is therefore not used in the interpretation. Favorable depth intervals for gas production exhibit sizeable volumes of gas and organic content. In the Barnett shale, the two wells exhibit different rock fabrics. Such a behavior indicates that the formation is laterally heterogeneous. Rock physics models should therefore be extrapolated from one well to another with caution. Simulations assume anisotropic elastic behavior and suggest the presence of compliant horizontal pores in one case. Natural vertical fractures are observed on electric image logs in the remaining case and are modeled with Hudson’s theory. This behavior suggests that rock fabric causes mechanical anisotropy in the formation. Heterogeneity of the Barnett shale rock fabric is inferred from the necessary use of rock typing to adequately reproduce sonic logs in both wells. Intervals with large porosity and high gas saturation identify suitable zones to perform hydraulic stimulation. Among such zones, rock types that exhibit stiff load-bearing matrices (comprising mostly calcite, for example) indicate suitable depths to drill horizontal wells or to contain hydraulic fractures. Intervals with dense layering of different rock types are unsuitable for fracture propagation and should be avoided during hydraulic-fracturing operations. / 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