Operators have different production strategies based on maintaining their fracture networks to the reservoir and sand control after flowback. Aggressive production strategies in some liquids-rich producing shale reservoirs could reduce fracture lengths and limit the production life. In addition, operators are constantly trying to achieve a better understanding of the existing fracture network (i.e., to assess if a perceived fracture barrier restricts the potential SRV or if modified drawdown strategies could make up for these "restricted" wells) to determine its impact on different production strategies. This study investigates optimal drawdown strategies through a holistic workflow. The scope of this work will also investigate what are the hydrocarbon recoveries for wells that are landed near a fracture barrier as well as primary-infill well scenarios. The work considers important reservoir and fluid properties to conduct rate-transient analyses, pressure transient analyses, and later to develop the reservoir simulation model to history match and forecast future production rates and pressures. The study considers multiple scenarios of varying properties from fracture and reservoir modeling to obtain a range of recoveries and economics. Case studies will cover the Midland Basin Wolfcamp and Lower Spraberry formations to evaluate how reservoirs of different rock and fluid properties will impact the resulting optimal choke management strategies. Coupled geomechanics and reservoir simulation is a recognized industry practice used to better understand potential fracture network depletion influenced by fracture barriers and primary-infill well scenarios, ultimately providing guidance on optimal drawdown strategies for complex reservoir development scenarios.
