Abstract

Over the last two decades, the driver behind the boom in unconventional reservoirs has been the development of horizontal drilling and hydraulic fracturing. More recently, the fall in oil prices has resulted in the industry refocusing on the shale market and its most profitable plays, a notable example being the Permian Basin. We argue that this refocusing should also take place in the technology domain and that seismic and its derivatives should provide reservoir and completion engineers with the means to optimize well planning. This is illustrated with a case study of an advanced quantitative interpretation workflow tailored for a seismic multiclient program in the Wolfberry Play of the Midland Basin. Seismic imaging begins by providing a structural interpretation basis, then quantitative interpretation provides 3D elastic and geomechanical attributes through prestack inversion and azimuthal inversion, respectively. This 3D canvas of elastic attributes is combined with petrophysical, mineralogical, geomechanical, and geochemical properties measured at the wells. The challenge of reconciling such data sets with different scales and spatial sampling is overcome using physical, empirical, or statistical relationships within the data. The adjunction of rock data to the 3D elastic attributes provides calibration and validation of the inversion results. More interestingly, it allows for quantitative prediction of lithology, facies, porosity, and geochemical properties away from the wells. The purpose of the resulting calibrated reservoir model is to assist in optimizing drilling plans and executing completion designs.

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