This study contains a workflow that attempts to predict the horizontal well performance on a regional scale based on mappable petrophysical and geologic properties that have been correlated to early time well performance from a small population of horizontal Wolfcamp B wells in the in the Midland Basin of West Texas. The ability to construct estimated well performance maps early in the life of a play is critical for high grading future well locations and defining an optimum development plan.
The key mappable geologic and petrophysical properties for well performance prediction in the Wolfcamp B resource play are: reservoir pore pressure, thermal maturity, kerogen volume, bulk volume hydrocarbon, and clay volume. Kerogen volume is referring to total organic carbon in weight percent being mathematically transformed to volume percent. Regional maps of these key properties were created from a data set consisting of a core calibrated petrophysical model applied across hundreds of vertical wells, thermal maturity information from hundreds of wells, and pore pressure information from thousands of operated wells. These key property maps were then sampled to the producing horizontal wells to define a predictive well performance correlation by using a multiple linear regression technique.
In applying the multiple linear regression technique a unique coefficient is assigned to each sampled input property that allows for the highest predictive correlation. The resulting equation is then applied to all of the vertical petrophysical control wells to generate a predictive horizontal well performance map. This workflow is being applied to the Wolfcamp B in the Midland Basin in West Texas. The resulting predictive well performance map identifies areas that are highly prospective great distances from the horizontal production control.
The Lower Permian Wolfcamp Group of the Midland Basin contains several lithologies that result from simultaneous deposition of pelagic organics, carbonate sediments, and clastic sediments in an anaerobic basin. The facies that are present within the Wolfcamp group are dependent on the depositional setting. The conventional reservoirs facies include carbonate debris flows, carbonate gravity flows, and clastic gravity flows and are inferred to have a depositional setting of proximal basin plain to medial basin plain (Montgomery 1996). The unconventional reservoir facies can be described as organic rich, oil mature, highly fractured, mixed lithology, mudstones that are inferred to have depositional setting of medial to distal basin plain. The unconventional reservoir facies of the Wolfcamp are extensive and contain thin beds of conventional facies that result in vast hybrid oil resource play.