Unconventional reservoir production in the Midland Basin heavily depends on successful hydraulic fracturing treatments. Operators have been demonstrating that better wells have been completed with longer laterals, tighter stage and cluster spacing, and that the long-term well performance depends on completion effectiveness and well spacing. In this paper, we used reservoir simulation to examine optimal cluster spacing and well spacing with four adjacent Lower Spraberry horizontal wells located on the University Lands. Finding the best practice of cluster spacing and well spacing throughout the University Lands is one of the current priorities for the newly formed Texas Oil and Gas Institute (TOGI), which is part of the University of Texas System.
The industry has employed different approaches to represent unconventional horizontal wells in reservoir simulation models. In this paper, we built a dual porosity model to represent the naturally-fractured reservoir with planar hydraulic fractures and associated enhanced zones. Prior to using reservoir simulation, we conducted rate-transient analyses to examine flow regimes, well interference, completion size, and cluster efficiency, and then estimated initial values such as fracture half-length, matrix permeability, and initial dual-porosity model properties.
Two adjacent well pads with four horizontal wells were selected for this study. The basic production data indicated that the second set of wells interfered with the first two older/parent wells during their hydraulic fracture treatments with communication between the wells observed at a distance of roughly 1700 feet. This offset well interference affected the parent wells’ oil and water production rates. Although the rates recovered to their original trend, one of the well's productivity indexes did not recover.
Using these data, the reservoir simulation model was calibrated with the observed bottomhole pressures and daily oil, gas, and water production rates. After achieving a successful history match, the model was varied to include varying cluster and well spacing, and production forecasts were developed. Then, the simulation results were evaluated using a relatively simple economic model to determine net present values.
The paper provides suggestions to maximize estimated ultimate recovery (EUR) with optimized cluster spacing and well spacing to benefit both the operator and the landholder. Tighter cluster spacing maximizes well productivity and enhances well economics, and may improve ultimate recoveries. Operators have ongoing field tests to determine the apparent limit of cluster spacing based on production, operational feasibility, and the additional costs and benefits. The optimal well spacing is essentially dependent on the fracture half-length, which is an uncertainty. Accurate determination of hydraulic fracture half-length is the key to optimize the well spacing and requires additional analyses such as microseismic monitoring, fiber-optic sensing to determine cluster efficiency, and modeling of hydraulic fracture dimensions.