The Eagle Ford shale in south Texas is the one of the most recent developments in unconventional reservoir exploration. Numerous existing completion methods have been applied in this nano-darcy formation with various degrees of success. The horizontal Eagle Ford wells in the northeast area of the current Eagle Ford play (DeWitt County) require a completion strategy that is reservoir specific. The production in this area has a high liquid/gas ratio and presents different challenges for commercial development than those in the typical “high-rate water frac” completions associated with dry-gas shale stimulation theory. Previous high-rate water frac completions in this area typically associated with the “Barnett-style shale stimulation” achieved poor results. Core analysis shows that a low Young's Modulus (YM) (soft rock), high clay content, and the potential for high liquid-hydrocarbon production require the need for a different completion strategy. Swelling formation clays and proppant embedment were formation issues to consider along with the multiphase hydrocarbon production. Higher conductivity fractures would be required, but various unknowns existed:
How many frac stages should be pumped?
How much proppant should be pumped on each frac stage?
What type of proppant should be used?
What mesh proppant should be used?
What perforation scheme was needed?
What type of completion fluids should be used?
What injection rate was needed?
How would fracture-injection issues be handled?
This paper discusses how a collaborative, engineered approach was applied to the completion of the Eagle Ford shale to deliver a commercial asset. To address the unknowns, the methodology included geologic and reservoir understanding applied to the stimulation design and execution. The stimulation resulted in hydrocarbon production that exceeded expectations. Comparative well results will be discussed.