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 Permeability measurements made using innovative techniques on 36 intact samples from five wells in south Texas provide the basis for a dual-porosity reservoir simulation model for the Eagle Ford Shale (Upper Cretaceous). In the model, matrix storage feeds a network of progressively larger natural and induced fractures that carry hydrocarbons to the wellbore. The Eagle Ford consists almost entirely of interbedded marl and limestone. Across these rock types, permeability increases with increasing calcite content. The limestones are more permeable than the marls due to the presence of fractures. Permeability also increases with the degree of lamination but the mechanism is unclear. Finely laminated marls are more permeable than marls without any lamination. Scanning electron microscope microscopy shows that all of the intergranular pores in the Eagle Ford are lined or filled with solid hydrocarbon identified as both bitumen and pyrobitumen by visual kerogen analysis and solvent extraction. The bitumen is porous, but permeability is not related directly to the total organic carbon content.