ABSTRACT The Cenomanian–Turonian Eagle Ford of South Texas is largely composed of two interbedded rock types: marls and limestones. The marls consist mainly of coccoliths with sand- and silt-size grains predominantly comprised of planktonic foraminifera with lesser amounts of inoceramid fragments and other carbonate grains. The limestones are recrystallized, and they contain calcified radiolarians and calcispheres, with almost all pore spaces having been filled with calcite cement. Most of the hydrocarbons in the Eagle Ford, regardless of thermal maturity, reside in the pore network of the marls. Economic production of hydrocarbons stored in these marls, which have nanodarcy permeabilities, can only be obtained by inducing and maintaining fractures with hydraulic stimulation. The interbedding of the marls with limestones form centimeter-scale brittle–ductile (or stiff-compliant) couplets that influence hydraulic fracturing over a range of scales, and at the smallest scale it may increase production by hosting complex near-wellbore fracture systems. Natural fractures that were already present may be open or cemented and reactivated during hydraulic stimulation and contribute to production. This can generate a hybrid fracture system with a larger drainage area and fracture surface area to allow for crossflow from the matrix to fractures. The Eagle Ford is a dual-porosity system, with the hydrocarbon stored in the marls feeds a network of progressively larger natural and induced fractures that carry those hydrocarbons to the wellbore. In most cases, the Eagle Ford will be most productive when the “right” mixture of marl and limestone are present. Too much limestone lowers the storage capacity of the system, and too much marl reduces the complexity of the fracture system. The distribution of the limestones is important: Even if the percentage of limestone in two sections is equal, hydraulic stimulation will produce a more complex fracture network when the limestone is present as a series of thin interbeds rather than as a single thick limestone. The interbedding of limestone and marl can be measured using limestone frequency—the number of limestone beds per unit thickness. Variation in production is observed in wells on the same pad completed with the same treatment but landed in zones of differing limestone frequency, with production in these wells increasing with limestone frequency. Also, in a multivariate analysis involving numerous engineering and geologic variables and over 1000 wells, all measures of interbedding reduced to a single factor, which we call limestone frequency, which positively correlated with production.

Abstract The 130-year history of study of the Cenomanian–Turonian Eagle Ford and Woodbine Groups of Texas has created a complicated and often confusing nomenclature system. Deciphering these nomenclatures has frequently been hindered by outdated biostratigraphic studies with inaccurate age interpretations. To resolve these issues, a comprehensive compilation and vetting of available biostratigraphic, geochemical, and lithologic data from Eagle Ford and Woodbine outcrops and subsurface penetrations was undertaken, which was then tied to a large network of wells in both south and east Texas. Composite sections were built for four outcrop areas of central and north Texas (Dallas, Red River, Waco, Austin), five outcrop areas from west Texas (Langtry, Del Rio, Big Bend, Chispa Summit, Quitman Mountains), four subsurface areas from south Texas (Webb County, Atascosa County, Karnes County, DeWitt/Gonzales Counties), and two cross sections from the east Texas subsurface (basin center and eastern margin). The resulting datasets were utilized to construct age models and characterize depositional environments, including paleoceanography. In agreement with previous studies, the total organic carbon (TOC)-rich Lower Eagle Ford was interpreted to have been deposited under anoxic to euxinic conditions and the Upper Eagle Ford under dysoxic to anoxic conditions. The Oceanic Anoxic Event 2 (OAE2) interval is missing at all locations north of Atascosa County; when present it is characterized as having been deposited under oxic to suboxic conditions. High abundances of radiolaria and calcispheres identified within recrystallized medial to distal limestones of the Lower Eagle Ford indicated limestone formation during periods of enhanced water-column mixing and increased primary productivity, in contrast to proximal limestones composed of planktonic foraminifera and inoceramid prisms concentrated by bottom currents. Standardized nomenclature systems and age models are proposed for each of the outcrop and subsurface areas. Proposed changes to existing nomenclatures include reassignment of the Tarrant Formation of the Eagle Ford to the Lewisville Formation of the Woodbine in the Dallas area and the Templeton Member of the Lewisville Formation to the Britton Formation of the Eagle Ford in the Red River area. The proposed term “Waller Member” of Fairbanks (2012) for the former Cloice Member of the Lake Waco Formation in the Austin area is recognized with a new stratotype proposed and described, although the Waller Member is transferred to the Pepper Shale Formation of the Woodbine. The Terrell Member is proposed for the carbonate-rich section at the base of the Boquillas Formation in the Langtry and Del Rio areas, restricting the Lozier Canyon Member to the organic-rich rocks underlying the Antonio Creek Member. The south Texas subsurface is divided into the Upper Eagle Ford and Lower Eagle Ford Formations, with the clay-rich Maness Shale Member at the base of the Lower Eagle Ford and the foraminifera grainstone dominated Langtry Member at the top of the Upper Eagle Ford. Use of the term “middle Eagle Ford” for the clay-rich facies south of the San Marcos arch is not recommended.

Abstract Twelve stratigraphic intervals originally defined in the Eagle Ford of south Texas were mapped across the San Marcos arch into the Maness Shale, Woodbine, and Eagle Ford of east Texas. The maps are based on well log correlations of 1729 wells across 22 counties in south and east Texas using biostratigraphic, geochemical, and lithologic data from 99 wells as seed points for the correlations. These mapped intervals were tied to a regional chronostratigraphic framework developed using data from the outcrops of west, central, and north Texas and cores from the subsurface of south and east Texas. Seven regional depositional episodes were identified across the Texas shelf for the Woodbine and Eagle Ford Groups based on the isopach maps, outcrop data, and paleoenvironmental interpretations. The clay-rich Maness Shale was deposited during the Early Cenomanian in east Texas and northern south Texas where it correlates to the base of the Lower Eagle Ford. After a relative fall in sea level, east Texas was dominated by the thick siliciclastics of the Woodbine, whereas in south Texas deposition of the organic-rich EGFD100 marls began during the subsequent transgression. A shift in depositional style to the limestones and organic-rich shales of the Eagle Ford occurred in east Texas during the Middle Cenomanian produced by the continued rise in sea level, correlating to the EGFD200 marls of south Texas and the carbonates of the Lozier Canyon Member (restricted) of the Eagle Ford Group in west Texas. During the EGFD300 interval deposition transitioned to the organic-rich marls and limestones of the Lozier Canyon and Antonio Creek Members of the Eagle Ford Group in west Texas and the Templeton delta became active in northern east Texas. Erosion along the Sabine uplift shifted the focus of deposition in east Texas southward to the Harris delta and deposited the “clay wedge” of the EGFD400 in northern south Texas. Although the lower part of the EGFD500 episode was deposited during OAE2, it is characterized by low total organic carbon (TOC) due to the presence of oxygenated bottom waters, and the Cenomanian–Turonian boundary sea-level high produced a regional hiatus. Deposition recommenced on much of the Texas shelf during the Late Turonian EGFD600 interval with the Sub-Clarksville delta of east Texas and the carbonate-rich Langtry of south Texas and eastern west Texas. Bottom waters became oxygenated at approximately 90 Ma, initiating the transition from the Eagle Ford to the Austin Chalk.

Abstract The Eagle Ford play in south Texas extends along strike from the San Marcos arch in the northeast into the Maverick Basin along the international border with Mexico. The highest initial oil production is in a strike-parallel belt between the Karnes trough and the Cretaceous shelf margin. Three lithologies comprise the bulk of the Eagle Ford Shale in this area: argillaceous mudrock (shale), calcareous mudrock (marl), and limestone. The marls consist mainly of coccoliths and contain more total organic carbon (TOC) and have higher porosities than the other lithologies. The sand- and silt-sized grains in the marls and limestones consist predominantly of planktonic foraminifera, radiolarians, and calcispheres, with lesser amounts of inoceramid fragments and other carbonate grains. The limestones may be partly to entirely recrystallized. The strength and rigidity of the rocks increase with calcite content—the limestones are stronger and more rigid than the marls. Argillaceous mudrock (shale) comprises only a small portion of the Eagle Ford between the San Marcos arch and the Maverick Basin, but is more common in the lower part of the formation along strike to the northeast. Six unconformity-bounded stratigraphic intervals (depositional sequences) can be recognized and mapped within the Eagle Ford Shale between the San Marcos arch and the Maverick Basin. Significant changes in biostratigraphy and chemostratigraphy within the Eagle Ford take place at these sequence boundaries. The Cenomanian–Turonian boundary occurs within the lower part of the Upper Eagle Ford. Typically, the Upper Eagle Ford contains less vanadium, molybdenum, uranium, and TOC than the Lower Eagle Ford, indicating bottom-water oxygen levels were oxic rather than dysoxic or anoxic during deposition. The Eagle Ford as a whole and each of its major subdivisions thin across an area in southwestern Karnes County coinciding with a structural high on the underlying Buda Limestone. The percentage of limestone within the Eagle Ford and each of its major subdivisions increases over this area. Changes in thickness and facies within the Eagle Ford suggest the area above the high on the time-structure map was a topographic high on the seafloor. Furthermore, changes in bathymetry influenced facies distribution and ultimately production from the Eagle Ford Shale. However, changes in pore pressure and fracture intensity also occur across the high, confounding the effect of facies on production.

Abstract 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.

Abstract A thick shale section cored in the EOG Resources Gordon saltwater disposal (SWD) well in the southern Fort Worth Basin contains six different lithologies. Gamma-ray readings on well logs can be used to distinguish the Barnett Shale (Mississippian) from the overlying Pennsylvanian shales and to divide the Barnett Shale into upper and lower units referred to informally as the Barnett A and Barnett B. Laminated silty claystone to mudstone is the dominant lithology in the Pennsylvanian shales above the Barnett Shale. The relative abundance of this lithology decreases downward in the core. It makes up a significant part of the Barnett A, but only a minor part of the Barnett B. A dark claystone shows the opposite trend, decreasing in relative abundance upward in the core. Sponge spicules are the most common silt- and sand-size grains in both the laminated claystone to mudstone and the dark claystone. Thin shell layers and phosphatic intervals are also found throughout the core. Shell layers are more common in the Pennsylvanian shales. Phosphatic material is most abundant in the Barnett B at the base of the core. Claystones and mudstones, lacking sponge spicules, but containing significant amounts of silt-size quartz are found only in the Barnett B. Isopach maps show that the Barnett B is part of a large shale wedge that prograded into the central and southern parts of the Fort Worth Basin from the northeast and that the Barnett A is part of a smaller shale wedge that prograded from east to west across Johnson County. The upper wedge onlaps and dies out against the flank of the lower wedge. The distribution of lithologies in the Gordon SWD well can be related to the position of the well site on the shale wedges. The site was far removed from areas of active sedimentation during the deposition of the Barnett B and closer to the main sources of sediment and areas of sedimentation during deposition of the Barnett A.

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.

Abstract The Paleocene and Eocene Series of the Gulf Coast contain lignite reserves equivalent to almost 50 billion barrels of crude oil. Preliminary estimates by Phillips Coal Company place lignite reserves at 22.5 billion short tons (Luppens, 1982). This figure includes lignite in seams at least 0.9 m thick and at depths of less than 61m, the general limit of present surface mining practice in the Gulf Coast. Substantial lignite deposits also occur at greater depth. Texas alone has 34.8 billion short tons of lignite in seams at least 1.5 m thick at depths between 61 and 610 m (Kaiser and others, 1980). Rising energy costs in the 1970s made in situ gasification of this lignite seem viable, but declining energy costs in the 1980s have removed the impetus for developing deep lignite resources. Power plants tied to nearby surface mining facilities seem likely to remain the only way in which to utilize the energy in Gulf Coast lignite on a commercial scale. The world energy situation precludes deep lignite resources from becoming reserves at any time in the immediate future. Texas has the largest reserves in the Gulf Coast, 11.5 billion short tons of lignite, followed by Mississippi, 5.0; Arkansas, 2.5; Alabama, 1.4; Louisiana, 1.1; and Tennessee, 1.0 (Luppens, 1982). Texas is also the leading producer, producing 39.8 million short tons of lignite in 1984 to rank sixth in the nation in coal production (Friedman and others, 1985). Almost all of this lignite fuels mine-mouth power plants, which now