A quantitative framework for relative rock physics includes a definition of relative elastic property that is rooted in inverse theory and that can be used practically to compute the properties. The framework also includes a set of rules that quantify how operations on absolute properties affect their relative counterparts. From these rules, a comprehensive table of relative elastic properties can be generated, all of which are expressed in terms of relative P-velocity, S-velocity, and density. Finally, the framework includes empirical and model-based rock-physics rules that can be applied directly to the relative properties without reverting to their absolute counterparts. That provides a practical route to such interpretation techniques as direct-to-seismic fluid substitution. The framework offers a quantitative alternative to workflows centered on absolute seismic inversion. In some cases, relative rock-physics workflows are preferable to absolute flows because they avoid statistical complications associated with the nonstationarity of the mean of absolute elastic properties.

The estimation of reservoir properties from seismic amplitude is, generally, an underdetermined problem, which can result in ambiguous estimation of the sought-for properties. Although seismic reflectivity is dependent upon formation P- and S-wave velocities and density, it is common practice to estimate only two attributes from prestack P-wave data because of data limitations at far offsets and instabilities of inversion. On the other hand, the number of petrophysical properties that determine reservoir storability and production are four, in the simplest of cases: porosity, lithology, pore fluids (type and amount), and permeability. Ambiguity and risk reduction require the inclusion of additional, robust information into the estimation of reservoir properties. This is particularly true in formations where reservoir storability and production depend on additional petrophysical properties, as would be the case of unconventional plays where brittleness and vertical fracture density and orientation are factors that determine reservoir performance. In this study, rock properties are estimated through PP-PS joint inversion and estimation of S-wave anisotropy. Data from the Marcellus Shale in Pennsylvania are used to illustrate risk reduction in qualitative estimation of total organic content (TOC) and fractures characterization.

Pseudo S-wave broadband response of C-waves after domain change T ransforming multicomponent data from one domain to another has long been an important tool for interpretation, V P /V S analysis and joint amplitude versus offset/angle AVO/AVA inversion. Recent interest in the dynamics of these domain changes has led to investigations in wavelet distortion and correction methods for improved inversion and bandwidth for well ties (Bansal and Matheney, 2010;Gaiser, 2011;and Ursenbach et al., 2012). In this article, we derive corrections for converted P-to S-waves (C-waves), to match their effective wavelengths with the physical wavelengths of S-waves, in P-wave time or depth. We call this a pseudo S-wave response. Although bandwidth is broadened, these corrections do not completely retrieve the resolution benefits of shorter wavelength S-waves.Implementation of these corrections has several key elements similar to Bansal and Matheney (2010): estimation of an interval V P /V S function, performing zero phase corrections and applying wavelet corrections using nonstationary wavelet filters (Margrave, 1998). Application of our technique to a 3D multicomponent data set acquired over the Marcellus shale provides broader bandwidth C-waves that match P-wave data and reveal improved well ties in the reservoir.

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