Completion Optimization in the Wamsutter Field, SW Wyoming

Abstract

Abstract This paper describes the successful application of a rigorous optimization process to new well completions in the Wamsutter area of SW Wyoming. High well costs and relatively low netback product prices require that all new well completions be rigorously optimized for maximum value. Excellence in stimulation design, execution, and evaluation is absolutely critical to economic success in this heterogeneous, stacked, tight formation gas play. Flawless, Safe Execution is the most critical part of the completion process. QA/QC standards require rigorous prejob and day-of-job fluid and proppant testing, the ability of all chemical add pumps to accurately deliver specified rates, and rigorous material balance tracking throughout the job. The job must not be pumped if all personnel, equipment, and materials are not fully prepared and up to spec. Rigorous Engineering of completion designs is performed by a geographically dispersed, multi-disciplinary team, using petrophysical, reservoir, and frac design models to assure the most optimum design based on all available data and knowledge. The petrophysical model uses standard log data to estimate reservoir properties and mechanical rock properties. Log data is seamlessly converted into layer data for input into frac and reservoir models. Designs are optimized for each well based on predicted fracture characteristics and reservoir performance. Data is exchanged via a secure interactive web-based system. Data flow and work processes are well mapped and highly efficient. Systematic Learning is pursued through comprehensive postcompletion well reviews. Frac design and reservoir models are re-run on every completion to help explain actual well performance versus pre-completion estimates. Production logs and frac diagnostic data also aid in understanding well results. The petrophysical, fracture stimulation, and reservoir models are periodically updated to incorporate learnings. Precompletion predictability has improved substantially. The application of this model on 99 wells completed in 2002 has resulted in a 20% improvement in production and estimated ultimate recovery. Additionally, drilling costs have been reduced by 5%. Cost per unit gas volume produced has improved by 27%. Continued improvement in reservoir predictability will allow better optimization of top-quartile wells by focusing strongly on frac length and conductivity optimization, and of lower-quartile wells by minimizing the completion to only those few contributing sands.