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Abstract

Shale reservoirs are continuous accumulations in which the same formation commonly serves as the source, reservoir, and seal for commercial accumulations of natural gas. Intrabasinal differences within continuous accumulations account for the indistinctly bound areas of better gas production termed sweet spots by operators. Generally similar sets of facies have been recognized in the Barnett Shale in the Fort Worth Basin by all recent workers. Dark mudstone to claystone with a matrix of clay minerals and cryptocrystalline quartz is the most common depositional facies in the Barnett Shale. Two predominantly calcareous depositional facies are next in abundance: argillaceous lime mudstone and skeletal argillaceous lime packstone. A variety of minor depositional and diagenetic facies are also present. The abundance and distribution of facies change with geographic location within the basin and stratigraphic position within the Barnett Shale. The most obvious example of this is the relative abundance of calcareous depositional facies in the northern part of the basin compared with their relative scarcity in the central part of the basin. All of the major facies recognized in the Barnett Shale have high concentrations of organic matter. The variation in facies is greater than the variation in organic matter content. The location of sweet spots with higher production rates within the Barnett Shale may ultimately be explained by the distribution of facies that respond differently to various completion procedures. As the play matures, it is likely that a detailed understanding of the geology, especially the distribution of facies, will become increasingly important in selecting well locations, intervals in which to land laterals, and which fracture stimulation techniques to use.

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