Seismic Stratigraphic Analysis of the Barnett Shale and Ellenburger Unconformity Southwest of the Core Area of the Newark East Field, Fort Worth Basin, Texas
Elizabeth T. Baruch, Roger M. Slatt, Kurt J. Marfurt, 2012. "Seismic Stratigraphic Analysis of the Barnett Shale and Ellenburger Unconformity Southwest of the Core Area of the Newark East Field, Fort Worth Basin, Texas", Shale Reservoirs—Giant Resources for the 21st Century, J. A. Breyer
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The sequence-stratigraphic framework established for the subsurface Barnett Shale in the northern part of the Fort Worth Basin is helping to resolve the age, nature, and fill of karst features under the Barnett Shale in the southwestern part of the basin. The southwestern Fort Worth Basin is characterized by the absence of the Upper Ordovician Viola Limestone and Simpson Group, which separate the lower Barnett Shale from the underlying Ordovician Ellenburger Group, as well as the Forestburg Limestone, which separates the upper and lower Barnett Shale to the north. Consequently, the undifferentiated Barnett Shale unconformably overlies the water-bearing Ellenburger Group and results in a higher risk of water encroachment during stimulation and production of Barnett gas wells.
Recent work indicates that Barnett Shale parasequence sets dominated by phosphatic and siliceous shale lithofacies are more organic rich and possibly more gas prone than other Barnett lithofacies. Moreover, the quartz- and carbonate-rich lithofacies are brittle and appear to respond more favorably to hydrofracture stimulation and the facies with high amounts of clay may serve as a possible barrier for fracture propagation because of ductile behavior. Thus, the ability to locate and map these parasequence sets was a particularly important part of this study for aiding in reservoir characterization.
Analysis of three-dimensional seismic data southwest of the core area of the Newark East field demonstrates the ability to identify and map Barnett parasequence sets previously defined from core and logs in the more northerly part of the basin. In addition, high-resolution seismic images of the karsted Ellenburger Group unconformity surface reveal a series of elongate, rectilinear, collapsed paleocave systems resulting from subaerial exposure and carbonate dissolution. These features appear to have shaped the unconformity surface and to have had a direct influence on the deposition and distribution of the overlying Barnett Shale parasequence sets. The parasequence sets are thicker over these collapsed features than in areas flanking the karst. The difference in thickness diminishes with each stratigraphically younger parasequence set, indicating focused infilling over the collapsed features caused by progressive reduction in accommodation space.
Seismic analysis also reveals that the karst topography on the unconformity surface is related not only to local faulting caused by the paleocave collapse, but also to deep-seated northwest–southeast-trending faults that extend upward to the Ellenburger surface and sometimes into the overlying Barnett Shale, suggesting post-karst fault movement. Magnetic surveys over the area support the deeper origin of the fault pattern observed in the study area.
In the Newark East field, the Viola Limestone and Simpson Group form a fracture barrier for the overlying Barnett Shale. Their absence to the southwest presents a dilemma—whereas the Barnett Shale is thicker over this area, the lack of a fracture barrier risks water encroachment from the underlying Ellenburger Group.
Understanding Ellenburger karst development and behavior and how fault and fracture systems are associated with these structures is critical for comprehending the distribution and depositional pattern of the Barnett Shale parasequence sets. Moreover, the seismic mapping and characterization of the different parasequence sets (ranging in lithofacies and rock property) would allow improvement in selecting horizontal targets and fracture stimulation of Barnett gas 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.