Lithology of the Barnett Shale (Mississippian), Southern Fort Worth Basin, Texas
Published:January 01, 2012
Philip J. Bunting, John A. Breyer, 2012. "Lithology of the Barnett Shale (Mississippian), Southern Fort Worth Basin, Texas", Shale Reservoirs—Giant Resources for the 21st Century, J. A. Breyer
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Five lithologies are present in the Barnett Shale (Mississippian) in a core taken in Johnson County, Texas, in the southern part of the Fort Worth Basin. Dark claystone to mudstone makes up 86% of the cored interval. Sponge spicules are the most common silt-size grain in this lithology. The clay-size material comprising the matrix is a mixture of cryptocrystalline quartz, probably derived from radiolarian tests, and clay minerals. The rock is highly siliceous, hard, dense, and brittle. Three calcareous lithologies are present in the core: limy layers, shell layers, and concretions. Together, these lithologies make up only 7% of the cored interval. The limy layers and concretions consist almost entirely of micrite. The shell layers contain gravel-size fragments of brachiopods, pelecypods, and cephalopods. The calcareous lithologies are found as thin interbeds in the dark claystone to mudstone throughout the core. A laminated siltstone to mudstone containing abundant sponge spicules is found only at the top of the cored interval. Glauconite and phosphatic material are conspicuous components of this lithology. The phosphatic material includes phosphate-coated grains of glauconite, quartz, and fossil fragments. The lithologies in the core resemble those described in the core from the northern part of the basin. However, the relative abundance of the various lithologies changes greatly from the northern part to the southern part of the basin. Understanding lithologic variation within the Barnett Shale is key to locating sweet spots within the play and then selecting intervals within the reservoir in which to land horizontals wells.
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Shale Reservoirs—Giant Resources for the 21st Century
In the early 1970s, most exploration geologists in the United States considered subeconomic or marginally economic petroleum resources such as coalbed methane, shale gas, and tight-gas sands as unconventional resources (Law and Curtis, 2002). Tax incentives and federally funded research beginning in the late 1970s helped make these resources economically viable in the last two decades of the 20th century. Economics aside, two important geologic attributes characterize most unconventional petroleum resources (Law and Curtis, 2002). Conventional petroleum systems are buoyancy-driven accumulations found in structural or stratigraphic traps, whereas most unconventional systems exist independent of a water column and are generally not found in structural or stratigraphic traps.
Shale reservoirs are not new. The first commercial hydrocarbon production in the United States was from a well drilled in 1821 in a shale gas reservoir. By 2000, more than 28,000 wells had been drilled in shale gas reservoirs. Rising gas prices and technological advancements in horizontal drilling and hydraulic fracturing associated with the development of the Barnett Shale led to a boom in shale gas development in the early years of the 21st century. Now the exploitation of shale reservoirs is turning to natural gas liquids, condensate, and oil. Far from being isotropic and homogeneous, as once naively envisioned, shale reservoirs are complexly layered accumulations of fine-grained sediment. Geologic variation on scales ranging from that of stratal architecture to that of lamination within individual beds must be understood in order to locate and exploid areas of higher production within shale reservoirs. Shale reservoirs remain largely geologic plays - notmerely lease plays or strictly engineering plays made possible by improvements in drilling and completion technology.