Well Spacing Optimization in Eagle Ford

Abstract

Abstract Due to the ultra-low permeability in shale reservoirs, hydraulic fractures are developed to provide secondary permeability to increase production in horizontal wells. Well spacing is a key factor in maximizing the net present value (NPV) of a shale reservoir utilizing horizontally fractured wells. The dilemma is that the wells should be spaced close enough together to maximize the total stimulated area and drain the entire section in a timely manner, yet on the other hand, far enough from each other to minimize the chance of fracture hits by offset wells or overlapping the drainage area of a nearby well to avoid over-capitalization. The Eagle Ford shale has become a major resource play in North America and has become the focus of exploration and drilling activity for several oil and gas operators. Numerous studies have been performed to optimize well placement in shale gas reservoirs but unfortunately few have been conducted in reservoirs with multi-phase flow of oil and gas. The purpose of this paper is to find a balance between maximizing the stimulated area without over-capitalizing the play. Three distinctively different, real scenarios have been selected to study the effect of well spacing on estimated ultimate recovery (EUR) and ultimately on NPV. Also, a sensitivity study has been performed to analyze the effect of reservoir permeability and fracture half-length on optimal well spacing. The dimensionless metric, discounted profitability index (DPI), is also used in conjunction with NPV to ensure that while trying to maximize the NPV of the asset, the incremental investment decision still meets corporate economic thresholds and competes for capital within the portfolio. Based on the reservoir simulation and economic analysis, well spacing of 330 ft and 400 ft maximizes the NPV of a black oil Eagle Ford reservoir by assuming 50 nD reservoir permeability and fracture half-length of 100 and 150 ft, respectively. Well spacing of between 400ft and 450 ft maximizes the NPV in the retrograde gas case study. Detailed results are also provided to illustrate the effect of fracture half-length, reservoir permeability as well as oil price variation.