A chronostratigraphic framework was developed for the subsurface Eagle Ford of South Texas in conjunction with a log-based regional study that was extended across the San Marcos Arch and into East Texas using biostratigraphic and geochemical data to constrain log correlations of 12 horizons from 1729 wells in South and East Texas. Seven regional depositional episodes were identified by the study. The clayrich 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 fall in sea-level, East Texas was dominated by the thick siliciclastics of the Woodbine Group, whereas in South Texas deposition of the organic-rich EGFD100 marls of the Lower Eagle Ford began during the subsequent Lewisville transgression. A shift in depositional style to the limestones and organic-rich shales of the Eagle Ford Group occurred in East Texas during the Middle-Late Cenomanian EGFD200 and EGFD300 episodes produced by the continued rise in sea-level. Erosion along the Sabine Uplift shifted the focus of deposition in East Texas southward to the Harris delta and deposited the “clay wedge” of northern South Texas during the EGFD400 episode. The introduction of an oxygenated bottom-water mass onto the Texas shelf produced the considerable decrease in TOC preservation that marks the Lower/Upper Eagle Ford contact. This event coincided with the onset of Oceanic Anoxic Event 2 (OAE2) and the Cenomanian-Turonian Boundary sea-level high, which starved much of the Texas shelf of sediment. The only significant source of sediment was from the south; within the study area, the EGFD500 interval is essentially absent north of the San Marcos Arch. Deposition recommenced on much of the Texas shelf during the Late Turonian EGFD600 episode with the Sub-Clarksville delta of East Texas and the carbonate-rich Langtry Member of South Texas and eastern West Texas. Bottom-waters became oxygenated at approximately 90 Ma, initiating the transition from the Eagle Ford Group to the Austin Chalk.

Abstract The Eagle Ford Group crops out in a series of spectacular cut-bank exposures within Lozier Canyon region in Terrell County (west Texas). These outcrops provide an unparalleled opportunity to examine the Eagle Ford Group and gain valuable insights into explaining and predicting the vertical and lateral variability, as well as the thickness changes that can occur regionally within an unconventional source rock play. In the subsurface of south Texas, the Eagle Ford Group is typically divided into an organic-rich Lower Eagle Formation and a carbonate-rich Upper Eagle Ford Formation. Both formations are petrophysically distinct, especially on gamma ray (GR) and sonic logs. When geochemically analyzed, the basal portion of the Upper Eagle Ford Formation also contains a unique positive carbon isotope δ 13 C excursion interpreted as the Ocean Anoxic Event 2 (OAE2). The peak of this isotope excursion is the assigned proxy for the base of the Turonian Stage. Within the Eagle Ford outcrops of west Texas a vertical succession of five informal lithostratigraphic units, referred to as units A to E from the base up, are fairly obvious. Unit A consists of interbedded grainstones and carbonate mudstones. Unit B is dominated by organic-rich black carbonate mudstones. Unit C consists of packstone beds interbedded with light gray carbonate mudstones. Unit D consists of bioturbated marls, while Unit E consists of grainstones interbedded with carbonate mudstones and bentonites. By incorporating petrophysical and geochemical data, the Lower and Upper Eagle Formations from the subsurface of south Texas can also be defined in the Eagle Ford outcrops of west Texas. Our work suggests that outcrop units A and B represent the Lower Eagle Ford Formation, while outcrop units C, D, and E represent the Upper Eagle Ford Formation. Similar to the subsurface of south Texas, a distinct positive carbon isotope δ 13 C excursion also occurs in the basal portions of the Upper Eagle Ford Formation (unit C) in outcrop. More detailed analysis of the outcrop and subsurface data from the Eagle Ford Group in west Texas indicates that the five informal lithostratigraphic units can be further divided into a vertical succession of 16 subunits. This more detailed vertical facies succession was used to define four genetically related depositional sequences each with distinctive geochemical and petrophysical characteristics which make them particularly suitable for regional subsurface mapping. For nomenclature simplicity, these four sequences are herein termed the lower and upper (allo-) members of the Lower Eagle Ford Formation and the lower and upper (allo-) members of the Upper Eagle Ford Formation. The lower member of the Lower Eagle Ford Formation is an organic-rich, high-resistivity, uranium-poor mudstone-dominated sequence. A distinctive clay-rich, low-resistivity zone also marks its base. This sequence appears to be the primary unconventional reservoir interval in the subsurface of south Texas. The upper member of the Lower Eagle Ford Formation can be characterized as a uranium- and bentonite-rich, mudstone-dominated sequence. The lower member of the Upper Eagle Ford Formation is a uranium-poor interbedded mudstone and limestone succession characterized by an overall (low) blocky GR pattern, the presence of a distinctive positive carbon isotope δ 13 C excursion, and a clay-rich, low-resistivity zone at its base. The upper member of the Upper Eagle Formation is a bentonite-bearing, low-TOC interval that is more bioturbated toward its base and interbedded toward its top. It is characterized by the presence of a high GR, low resistivity, and low velocity mudstone at its interpreted maximum flooding surface. Regional correlations of the four defined Eagle Ford depositional sequences (allomembers) reveal that the unconformities at the base of each of the four sequences, as well as the one at the base of the overlying Austin Chalk, modify the thickness and distribution of underlying strata. Thus any attempt to explain and predict the distribution and thickness variations of any of the four sequences (allomembers), especially the organic-rich lower member of the Lower Eagle Ford Formation, is highly dependent on the recognition and regional mapping of these unconformities.

Abstract The objectives of this chapter are threefold: (1) to provide a historical perspective on considerations of pervasive tight-gas accumulations, (2) to provide some observations on the present understanding of these accumulations, and (3) to anticipate where the industry is headed in the future. From 1979 to about 1987, various workers (industry, government, and academe) discussed pervasive tight-gas accumulations and established important relationships for source rock, maturity, expulsion and migration, pressures, rock quality, and fluid content. Their main conclusion was that the hydrocarbons in these reservoir systems were dynamic and not static as in conventional structural and stratigraphic traps. The paradigm shift made by 1987 concluded that these accumulations were continually adjusting to existing conditions in both time and space. In more recent years, additional examples have been documented, and questions have arisen about the validity of the original model, noting the presence of more water in some systems than the model would predict. The close proximity of the mature, gas-generating, and gas-expelling source rock to the reservoirs is critical. The amount and richness of mature source rock has to be adequate for the volume of reservoir rock being charged. The proper combination of these circumstances produces more gas than can be contained under normal pressure. The quantity of this gas charge relative to available pore space in the reservoir system will dictate the reservoir pressure. Pervasive tight-gas accumulations have now been documented in more than 20 North American basins and are the targets for major ongoing exploration and development programs. The average reservoir porosity for these producing units is in the 8–9% range, with average in-situ permeabilities of hundredths of a millidarcy. We believe the industry will likely move forward in four directions: (1) revisit older mature basins, (2) expand into new basins, (3) move into carbonate reservoirs, and (4) continue to develop tighter and tighter rock. With continuing technology improvements (especially in drilling and completing) and robust gas prices, the industry will access vast new reserves farther down into the resource pyramid.