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 In 2006, Mark Papa, CEO of EOG Resources, Inc. directed EOG divisions to focus on identifying and leasing large acreage blocks in shale oil window fairways (Mark Papa, personal communication) in basins throughout the United States while subordinating all exploration for natural gas, and in particular, dry gas. The company’s strategic change to shale oil exploration occurred during what was referred to as a “wall of disbelief” (Birger, 2011) predicated on the premise that oil molecules could not flow through shale-dominated permeability systems. The EOG Garner 1054 C#1, drilled in November 1998, encountered hydrocarbons within the Eagle Ford Formation at a pressure gradient of 0.76 psi/ft, at a subsurface true vertical depth (TVD) of 9300 ft (2834.6 m). Although a wet gas producer, this well was a critical element in the rationale to obtain leases in the oil window of the Eagle Ford Formation. Predicated upon a technical analysis of additional vertical well production within the Eagle Ford Formation indicating the existence of a dual porosity, or matrix-supported flow network, and in conjunction with the generation of fairway criteria mapping, EOG initiated a leasing strategy resulting in the acquisition of 569,000 contiguous acres within the crude oil window fairway. Regional mapping of the Eagle Ford Formation was conducted to model structure, thickness, total organic carbon (TOC), thermal maturity (R o ), oil gravity, and hydrocarbon saturation as well as lithostratigraphic continuity, postulated environments of deposition, and mineralogical variations. An identified fairway situated between the Maverick Basin and the San Marcos arch, a syn-depositional graben system on the margin of a transgressed carbonate platform, was mapped as a relatively thick and laterally continuous stratigraphic section within the targeted R o , TOC, and favorable hydrocarbon saturation windows. X-ray diffraction (XRD) analysis revealed that while the silica content within the Eagle Ford Shale was low relative to the more topical Barnett Shale and other existing shale resource plays, the mineralogical constituents were that of a brittle carbonate with variable clay content replete with a deceptive gamma log signature as a consequence of elevated levels of uranium and thorium. Distinct structural settings displaying unique structural and stratigraphic attributes were recognized and mapped, all of which had remained within the oil generation window for the last 30 million years. Net rock volume increases associated with prolonged oil generation and expulsion were believed to increase the likelihood of catagenically induced micro-fracturing resulting in enhanced system permeability. Eight strategically located vertical delineation wells were drilled across a 15 by 120 mi (24.1 by 193.1 km) fairway located from Gonzales to LaSalle Counties. Conventional coring coupled with extensive electric logging suites and petrophysical evaluations provided an integrated regional understanding of the Eagle Ford Formation. Nanometer-scale imaging with focused ion beam (FIB) and field emission scanning electron microscopy (FESEM) of Eagle Ford core samples showed interconnected porosity systems and pore sizes capable of transmitting oil molecules. Initial production rates from EOG-operated horizontal delineation drilling confirmed the viability of the Eagle Ford Formation as an overpressured carbonate resource rock with system porosity and permeability capable of long-term economic oil production. The methods defined in this chapter were appropriate for the delineation of the oil window within the Eagle Ford of South Texas; however, hydrocarbon systems are unique and these methods may not be applicable for defining other plays within other basins.

Abstract A 2,700-km high-resolution seismic-reflection data set, acquired in recent years, has helped resolve some old problems concerning the age of Quaternary formations along the east Texas coast, and has resulted in mapping of the Trinity/Sabine incised valley. The seismic data were used in conjunction with oil company platform borings and recently acquired sediment cores to examine the stratigraphy of the incised-valley fill and to map the distribution of sand bodies on the shelf. The Trinity/Sabine valley has experienced at least two episodes of incision and infilling. The earliest incision occurred during δ 18 0 substage 5d and the latest reincision occurred during δ 18 0 stage 2. The late Wisconsinan-Holocene transgressive deposits that now fill the valley include the following facies (from bottom to top): fluvial; upper estuary/bayhead delta; middle estuary; lower estuary/tidal inlet/tidal delta; and offshore marine deposits. Backstepping parasequences, indicating an episodic rise in sea level, characterize the valley fill. Sandbody formation and preservation on the shelf also has been influenced strongly by the episodic nature of the late Wisconsinan-Holocene sea-level rise. Sabine Bank, the largest of the sand bodies and the only one studied in detail, is a reworked coastal lithosome that rests on the ravinement surface. Inner-shelf muds contain few discrete storm beds. Relatively thick (<75 cm) amalgamated storm deposits are restricted to sand banks and the incised valley. The modern Sabine Lake and Galveston Bay estuaries formed initially by flooding of the Sabine and Trinity valleys approximately 8 ka. The subsequent flooding event, which inundated the broad, shallow meander portions of the valleys, occurred approximately 4 ka and appears to have been rapid. Extant coastal systems of the study area incorporate a wide range of environments, including barriers, strandplains, chenier plains, and tidal inlets. The systems formed predominantly during the stillstand of the past 3,500 years. Galveston Island and Bolivar Peninsula were derived from offshore sand sources. Progradation of the coastal barriers ceased with the exhaustion of the sand supply.