--> An Integrated Study of Facies, Depositional Context, and Porosity Development in the Eagle Ford Shale of Southwest Texas

AAPG ACE 2018

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An Integrated Study of Facies, Depositional Context, and Porosity Development in the Eagle Ford Shale of Southwest Texas

Abstract

Although of key importance for production out of shale reservoirs, shale porosity is best considered in the context of depositional and burial history, rather than a stand-alone petrographic or rock physical issue. Shale porosity is the outcome of a long succession of processes and events that span the continuum from deposition through burial, compaction, and late diagenesis. For the Eagle Ford Shale this journey began with accumulation in intra-shelf basins at relatively low latitudes on a southeast facing margin during early parts of the late Cretaceous. Several drill cores were described and sampled, and facies and facies associations were defined and organized in a sequence stratigraphic model. Facies types and petrographic features were investigated through thin section petrography, and building on that data set a scanning electron microscope study on ion-milled samples was conducted to understand development and preservation of porosity in a broader context.

Core descriptions yielded distal, medial, and proximal facies associations, distinguished by differences in occurrence and abundance of sedimentary structures (scours, graded beds, wave vs current ripples) bioturbation, and fossil debris (shell fragments, forams, coccoliths). Pore types are heterogeneously distributed between facies associations, with organic-hosted pores more abundant distal, and inter- and intra-granular pores most common proximal. Cementation and pore occlusion by calcite is commonly observed proximal, likely a reflection of preferential cementation due to association with flooding surfaces.

Facies association is an important factor that determines bulk porosity and influences reservoir performance. Variability in the attributes of the described distal, medial, and proximal facies associations translates into significant variability of rock properties such as TOC and porosity. In turn, this variability likely exerts control over the quality and distribution of intervals that are optimum source and reservoir of hydrocarbons in the Eagle Ford Shale. The medial facies association most likely has the best porosity development when a favorable combination of more commonly abundant calcareous fecal pellets and organic material versus clay content is present. The systematic arrangement of facies associations into parasequences is the basis for testing and predicting the best development of optimal reservoir facies within a sequence-stratigraphic framework in the Eagle Ford Shale.