3-D Petrogeological Modeling of the Bakken Tight Oil Play, Southeastern Saskatchewan, Canada: Adoption of Conventional Workflows to Unconventional Reservoirs
Three-dimensional (3D) geological modeling of petroleum reservoirs is a long established practice in oil and gas exploration and prodction (E&P). Several decades of E&P focus on exploiting conventional plays has resulted in an arguably honed science of 3D earth modeling where the approach of integrating dataset from seismic to well logs and production data are well established, or at least well enough to create representative subsurface models, despite constraints sometimes imposed by modeling software limitations. With unconventional reservoirs however, it is common that the 3D modeling methodologies applied are in many instances inherited from static modeling workflows of conventional reservoirs. These workflows are in many cases not designed to capture pore scale heterogeneities and subtle changes in reservoir properties that affect well performance and expected ultimate recoveries in unconventional and tight plays. When hydraulic fracturing is implemented, actual field response is controlled not just by the induced fracture properties but also pore scale variations in matrix properties and subtle changes in facies. Many of these changes are smaller than the typical uncertainty of a parameter (for example matrix porosity/permeability) that is considered by conventional modeling workflows and yet can lead to a field scale change in fluid flow behavior and rock mechanical characteristics. It is therefore imperative that these geological characteristics are reasonably captured during geocellular modeling of unconventional plays. This novel study aims to address the problem by systematically assessing and integrating seismic, well logs, core, fractures and well production data into structural framework definition, stratigraphic, fracture and petrophysical modeling of the Bakken Formation in Viewfield Southeastern Saskatchewan. Modifications made to a conventional petrogeological modeling workflow highlight an improved methodology for taking into account pore scale matrix and natural fracture properties while constructing 3D models for tight plays. This adapted workflow facilitates a better full-field prediction of reservoir quality and matrix-natural fracture petrophysical relationships beyond the near-wellbore region. Model results have been validated with production performance and well connectivity analyses.
AAPG Datapages/Search and Discovery Article #90291 ©2017 AAPG Annual Convention and Exhibition, Houston, Texas, April 2-5, 2017