The Shape of Water: How Devon Energy Solved for Fracture Geometry Across Several Major Shale Plays

_ Shale producers have long sought to understand how fractures propagate underground, a fundamental question that shapes well spacing, completion strategies, and overall economics. A new study from Devon Energy (SPE 223547) aims to provide answers. It introduces the concept of fracture growth rate, which can “vary drastically” between formations, and examines the key geological and geomechanical factors driving those differences. Devon defines fracture growth rate by the area increased per the volume injected (ft2/bbl) to create the fracture. “We noticed that the Eagle Ford has much slower growth rates than in the Anadarko, and it could be up to a four- or five-times difference,” said Brendan Elliott, subsurface engineering manager at Devon Energy, speaking at the SPE Hydraulic Fracturing Technology Conference and Exhibition (HFTC) in Houston. According to the Oklahoma City-based firm, the variations in growth rate observed across thousands of fracture stages not only impact per-well economics but also dictate how many wells an operator can drill per section. “If you think about a barrel injected as a proxy for volume or frac size, in some areas of the world, you’re getting much less area per barrel,” Elliott said. “That’s important to understand, especially as we contextualize the differences across our plays.” He then presented data comparing fracture growth rates across Devon’s operating areas, emphasizing a key trend: “If you look at the plays with some of the fastest growth rates, those tend to be the ones with the least dense well spacing.” Elliott pointed to the Turner Sands formation in Wyoming’s Powder River Basin, where most 640-acre drilling sections today support only two to three wells. By comparison, in the Eagle Ford Shale, well spacing of 330 ft often allows for as many as 14 wells per section. Devon’s findings are the result of more than 5 years of diagnostic work using its proprietary technology, sealed wellbore pressure monitoring (SWPM), along with other corroborating methods such as fiber optics. Stress and Barriers What’s behind the striking differences reported by Devon? The firm’s extensive data-gathering effort shows that the two primary factors driving difference in fracture growth rate are the rock’s stress state and geomechanical barriers which represent the boundary between two distinct benches or formations. Horizontal stress magnitudes affect the extent to which fractures open. Additionally, the stress barriers between zones will influence vertical height and whether fractures propagate through different formations too quickly. Secondary natural fractures further affect fluid movement by controlling leakoff, as do the properties of in-situ fluids. Other important rock properties to consider include Young’s modulus. At HFTC, Elliott explained that in rocks with a high Young’s modulus, like those found in the Anadarko Basin, fractures tend to have very narrow apertures causing them to extend far more laterally than vertically. In contrast, the Delaware Basin in the Permian Basin has a lower Young’s modulus, which is one reason Devon has determined that fractures there can extend up to 4,000 ft laterally—or fracture tip to fracture tip—and up to 2,000 ft vertically in a 2:1 ratio.