Abstract
Several techniques for hydraulically fracturing design were conducted in the liquid-rich Eagle Ford developments. This study shows that different results were observed due to the variation of geomechanical stresses of the rock across a play and reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale primarily due to the multiphase flow and higher viscosities encountered.
This paper presents a treatment workflow that has been used with liquids-rich window of the Eagle Ford Shale. Review and integration of data from multiple sets across the play were used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results were then used with production analysis and forecast, well optimization, and economic model to compare which treatment designs yield the best placement of proppant to deliver both high initial production and long term ultimate recoveries.
A key focus for this workflow was to maximize proppant transport to achieve a continuous - optimum conductive - fracture half length. Often, due to the complexity of unconventional deposition, it is difficult to maintain complete connectivity of a proppant pack back to the wellbore. As a result, much of the potential of the fracture network is lost. Understanding the interaction of a hydraulic fracture and the rock fabric helps with the design of this behavior to achieve best results. These results can then be used for determining optimum well spacing to effectively develop a selected reservoir acreage.
Currently, there are numerous wells and over two years of production history in much of the Eagle Ford. Comparison of these production results demonstrate the importance of employing a diligent workflow to integrate the sciences so that a proper understanding and application of hydraulic fracturing modeling can be achieved.
