Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin

Abstract

Abstract Tight formations are being developed by drilling in the Midland Basin. Target intervals include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet true vertical depth (TVD). Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the expected pay intervals and are produced commingled. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data pose challenges to making the best decisions. Numerical models can yield insights about drainage patterns and potential interference. This paper reports a case study using a geologic model, hydraulic stimulation models, and a reservoir simulation model to evaluate reduced well spacing impacts on recovered oil and economics. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to data constraints. A reservoir simulation model was then utilized on a sector area of the full model. The sector model was history-matched to early production data and historical type curves. Each well had 10–12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. The paper presents history-matched simulation models that were executed to predict production and economics for 40-acre and 20-acre well spacing cases.