Fine-scale, reservoir models are necessary for locating high performance zones in unconventional reservoirs. The reservoir in the Woodford play is a naturally fractured, heterogeneous mudrock. The most common technique for characterizing the natural fracture system in such a reservoir is use of a DFN (discrete fracture network) model. However, such models are data intensive, time consuming to build and may provide non-unique solutions. We propose a workflow that estimates the contribution from fractures through a continuum model using well performance and static attributes derived from well observations and seismic data. The utility of the workflow is demonstrated by a blind test against a local sector model history match that shows excellent agreement with production history.
The integrated workflow includes a purpose-built stratigraphic framework for the Woodford. The Woodford was divided into five intervals using facies changes, biostratigraphic information, and log signatures. Core descriptions and x-ray diffraction data indicate total organic carbon and clay can be used to discriminate distinct depositional facies and intrinsic reservoir properties within the Woodford. Correlations that relate total organic carbon and clay volumes to seismic information, such as acoustic impedance and bulk density, enable the construction of petro-elastic models. Using petro-elastic models, a petrophysical seismic inversion is used to derive density, total organic carbon, and clay volumes. Structural seismic attributes such as dip, curvature, and coherence are also incorporated into the model. Finally, correlations obtained from multivariate statistics of well performance data and static model properties are applied to create spatial distributions of natural fracture drivers including: effective permeability and shape factor distributions across the field.
