Quantitative Interpretation Workflow for Unconventional Reservoir Characterization in the Delaware Basin
In recent years, the integration of multiple disciplines in the characterization of unconventional reservoirs in the Delaware Basin has increased in the aggregated value of these plays. From data collection and enhancement to the analysis and interpretation, the pace of resource exploitation in local fields has been so accelerated that to date not enough time has been spent to establish an optimal workflow for quantitative interpretation. Despite the complexity of its geological evolution, the Delaware Basin has been one of the most productive basins in North America and focus of the most important plays of reexploration and development. The rapid Early Permian subsidence of the basin and the several juxtaposed periods of deformation make the Delaware Basin a real challenge in understanding, modeling and characterization of its plays. The complex basin has both conventional and unconventional plays; the latter is our main focus. The petrophysical analysis of unconventional plays needs detailed data QC and preparation to optimize the results to obtain accurate mineral volume and total porosity computations. The total organic carbon (TOC) estimation that aids the process of determining the best pay zones for development can be calculated as an average of the modified Passey and the TOC from bulk density theoretical methods. This TOC log is used as an input to calibrate rock physics models which are needed to understand the rocks’ elastic properties and their contribution to the amplitude versus offset (AVO) signal of the seismic data. Computed anisotropic logs from modeled and empirical relationships are also taken into account in the rock properties characterization process since their effect can be seen in the reflectivity models used for well tie and wavelet estimation. To further this analysis, TOC substitution is performed in order to account for variability of elastic properties and their corresponding seismic amplitudes. As velocity is commonly used as a pore pressure indicator, understanding the kerogen effect is crucial in making accurate pore pressure predictions. This rock physics modeling can be related to seismic inversion results for the extrapolation of the 1D domain into a 3D reservoir characterization that provides a better idea of the distribution of TOC to constrain the landing zone and trajectories of the horizontal wells. The final interpretation may be used to rank targets, optimize drilling campaigns and ultimately improve production.
AAPG Datapages/Search and Discovery Article #90350 © 2019 AAPG Annual Convention and Exhibition, San Antonio, Texas, May 19-22, 2019