Rock physics of the Wolfcamp Formation, Delaware Basin

Abstract

Production from wells in organic-rich shales often shows considerable lateral variation. Reliable predrill methods to characterize the lateral heterogeneity of such reservoirs are required to optimize the trajectory of lateral wells in these low-permeability reservoirs. Petrophysical interpretation of measured well logs provides information on mineral, porosity, and kerogen content. Combining the results of petrophysical analysis with P-wave, S-wave, and density logs allows generation of a probability density function (PDF) for each of the different significant lithofacies. The PDFs are applied to the P- and S-impedance from prestack seismic amplitude variation with offset inversion to predict the spatial variation in the distribution of lithofacies and associated probability for the Wolfcamp Formation in an area covered by a 3D seismic survey in the Delaware Basin, West Texas. An anisotropic rock-physics model for the Wolfcamp Formation allows the effect of complex mineralogy, organic carbon concentration, and porosity on the P- and S-impedance to be investigated. Kerogen inclusions and pores act to increase Thomsen’s anisotropy parameter [Formula: see text] relative to [Formula: see text], and there is a competition between clay matrix anisotropy and inclusion shape anisotropy in determining the anisotropy of the rock. Inclusions with isotropic elastic properties act to decrease the anisotropy due to the dilution effect, but this decrease is partially offset by the increase in anisotropy due to the anisotropic shape of the inclusions. Application of the model to the determination of minimum horizontal stress indicates that kerogen-rich siliceous shales have the lowest value of minimum horizontal stress, whereas silica-rich calcareous shales, mixed siliceous shales, and clay-rich siliceous shales have higher values and may therefore act as barriers for the vertical growth of hydraulic fractures.

Quantitative Characterization of Elastic Parameters and Its Implications for Reservoir Evaluation: A Case Study on High Clay-rich Continental Shale

“…To investigate the impact of anisotropy on geostress, this study also considered the widely adopted and successful porous elastic models. , These models are classified as isotropic and do not account for variations in vertical and horizontal Young’s moduli or Poisson’s ratio. The mathematical representation can be found in eqs and , while eqs and represent the isotropic Young’s modulus and Poisson’s ratio, respectively. σ h = μ iso 1 − μ iso false( σ normalv − α p normalP false) + E iso 1 − μ iso 2 ε h + E iso μ iso 1 − μ iso 2 ε H + α p P σ H = μ iso 1 − μ iso false( σ normalv − α ...…”