The objective of this paper was to determine the variation in estimated ultimate gas and oil recoveries (EUR) from the Wolfcamp B formation (WC-B) due to variations in the initial conditions such as pressure, temperature, and fluid PVT properties. The study focused on the University Lands within the Midland Basin, which have significant acreage in the southern part and the northwestern edge of the basin. These two areas are separated by roughly 90 miles, and the WC-B depths vary by thousands of feet across this expanse.
To date, very little has been published on the pore pressure and fluid PVT properties in the Midland Basin, and while operators have been reporting variable well results, no study has identified the variations due to the initial conditions and varying fluid properties. Fortunately, the University Lands has access to these varying conditions at both ends of the basin, providing a useful dataset for determining the effects on well performance.
A review of all available PVT reports show the WC-B formation to be an undersaturated oil reservoir. The initial solution GOR varies from 600 to 1500 Scf/STB, within the range for a black oil PVT model. Given these conditions, the actual fluid PVT properties largely depend on well location and depth within the basin that affects the initial formation pressure and temperature.
A dual-porosity simulation model was successfully history-matched to a WC-B horizontal well located in the Northwest area of the Midland Basin (Andrews County). This model was then used as a proxy representation of the formation properties. This proxy model was then used to examine variations in estimated ultimate recoveries using the observed ranges of reservoir depths, initial pressures and temperatures, and fluid PVT properties. The predicted simulation results show that the initial conditions and fluid PVT properties can account for a 20% difference in recovery between a WC-B well located in the north (University Block 7 in Andrews County) and the south (University Block 3 in Upton County).
The model was extrapolated to forecast results for the Lower Spraberry Shale (LSS), Wolfcamp A, and Wolfcamp D. Assuming a similar geological and completion model, the deepest reservoirs provide the highest recoveries due to higher initial pressures and solution gas-oil ratios. However, in the University Block 7 area where the Lower Spraberry Shale (LSS) is the currently preferred target, these results suggest that the formation properties in the LSS are roughly three times better than the Wolfcamp B in this area.