Identification of Volcanic Ash Beds Using In-Situ Rock Mechanical Properties – A Comparison With Core Data in the Lower Austin Chalk and Eagle Ford Reservoirs

Abstract

Volcanic ash beds were successfully identified in the Eagle Ford Formation utilizing drilling vibration monitoring to obtain in-situ rock mechanical data. Continuous, high-resolution measurements of near-bit drilling induced vibrations were obtained in a cored interval from the Lower Austin Chalk through the Eagle Ford Shale. The collection of this data was used to provide stiffness coefficients and determine relative values of mechanical properties including Youngs Modulus and Poisson’s Ratio. Bentonite ash beds are important stratigraphic markers, but present challenges for completion and production of horizontal wells. Differences in mineralogy, in-situ water content, temperature and pressure determine the mechanical properties of each bentonite layer. In general, the Eagle Ford Shale section is differentiated from the overlying Austin Chalk and underlying Buda formations by a lower compressional as well as shear velocity. However, the bentonite layers can be difficult to identify and differentiate without extensive and costly data acquisition. Fine-scale laminae characterization is nearly impossible with standard logging tools due to their inherent resolution capability. This study focuses on the use of mechanical rock properties alone to differentiate bentonite ash beds from other fine-grained beds.

Elastic properties of rocks determine hydraulic fracture geometry and are essential to optimizing production. These properties can strongly influence economic efficiency of completion operations, yet, potential tools for calculating these properties are rarely acquired due to high cost and risk. Though the extent to which clay-rich ash beds affect hydraulic fractures is not fully understood, it is widely recognized that they inhibit fracture height growth. The mechanical rock properties of the bentonite beds measured within the cored interval was markedly different than those of the organic shale and mudstones. By identifying these beds at centimeter-scale resolution, a more detailed well placement and completion strategy can be implemented. When properly calibrated to other petrophysical parameters, vibration monitoring can provide a technical advantage. It has the potential to greatly improve our understanding of lateral variability of both mechanical behavior and reservoir quality while alleviating much of the typical economic and operational burden associated with these types of analyses.

AAPG Datapages/Search and Discovery Article #90323 ©2018 AAPG Annual Convention and Exhibition, Salt Lake City, Utah, May 20-23, 2018