Abstract A small aetosaur skull and skeleton and referred material from the Chinle Formation, Eagle Basin of Colorado, USA, is described as a new taxon, Stenomyti huangae gen. et sp. nov, distinguished from other aetosaurs by the following autapomorphies: three premaxillary teeth; four palpebrals; pronounced midline ridge on frontals and parietals; paired ridges flanking midline ridge on parietal and frontal; exclusion of quadratojugal from ventral margin of skull by contact between jugal and quadrate; exclusion of postorbital from infratemporal fenestra; infratemporal fenestra a horizontally oriented oval that embays the posterior edge of the jugal; retroarticular process longer than distance between articular glenoid and posterior edge of external mandibular fenestra; oval to irregularly shaped ventral osteoderms that do not contact each other. Paramedian and lateral osteoderms of S . huangae are nearly identical to those of Aetosaurus ferratus , and other shared cranial characters suggest that these taxa are closely related and lie outside the clade Typothoracisinae + Desmatosuchinae. This discovery indicates that other reports of Aetosaurus across Laurasia based on osteoderms should be reassessed. Similar confusion with the osteoderms of other non-typothoracisine/desmatosuchine aetosaurs such as Aetosauroides , Stagonolepis and Calyptosuchus suggests that osteoderms are not always reliable taxonomic indicators.

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Abstract Reliable evaluation of shale-play potential requires robust geological models that can simulate the generation and retention of petroleum, porosity and permeability in source rocks from first principles, and that can be implemented in basin modelling software. To be predictive, such basin models need to be calibrated against observations from real shale plays. A key control on the amount of retained petroleum is the porosity in the shale and the abundance of organic matter. Scanning electron microscopy of argon-ion milled shale samples can potentially reveal systematic variations in the amount of porosity, pore types and distributions across a range of thermal maturities. These observed variations in porosity can be used to calibrate basin modelling outputs and refine predictive models. For these reasons BP has conducted scanning electron microscopy studies of shale plays including the Eagle Ford Shale, a carbonate-rich mudstone sequence of Cenomanian to Turonian age. The results clearly show that the mean pore size decreases as thermal maturity increases and that organic matter-hosted pores are absent in low thermal maturity samples (where vitrinite random reflectance R o <0.7) and become increasingly more abundant as thermal maturity increases). In moderately mature samples there are organic matter hosted pores that range in pore size from 5 to 500 nm. In highly mature samples, small (<50 nm) organic matter-hosted pores predominate. Our studies reveal that porosity evolution in this organic-rich, fine-grained, carbonate mudrock shows a strong correlation with increasing thermal maturity.

ABSTRACT The Eagle Ford shale Formation (Upper Cretaceous) in the Gulf Coast basin of south Texas was first commercially produced in 2008 and has since achieved production and reserve growth that is virtually unprecedented in the history of onshore North American oil and gas development. Through December 2014, the field had cumulative production of approximately 1.1 billion bbl of oil and condensate and 4.8 trillion cubic ft of natural gas (TCFG). Average daily production during 2014 was approximately 1.3 million bbl of oil and condensate per day and 4.9 billion cubic ft per day of natural gas (BCFGD). The horizontal rig count in October 2014 was approximately 200, resulting in approximately 300 wells drilled per month (RigData). While the entire resource potential of the Eagle Ford is still quite subjective, it has been estimated to be as high 25 to 30 billion bbl of oil equivalent (BBOE). The Eagle Ford shale covers a vast area that spans approximately 7 million ac (2,832,799 ha) of continuous prospective reservoir and therefore should be considered as one oil and gas accumulation, or field. As a result of the aerial extent of the field occurring at depths ranging from approximately 5000 ft (1524 m) to the north to approximately 13,000 ft (3962 m) to the south, the product mix covers the entire spectrum from low gravity–low gas oil-ratio oil to dry gas, and everything in between. The Eagle Ford Formation lies above the Buda limestone and beneath the Austin chalk over the entire field area. The formation varies in thickness from approximately 250 ft (76 m) to as much as 600 ft (183 m) and is composed of a variety of facies. The primary reservoir facies, herein referred to as the Hawkville facies, is the primary reservoir and is located near the base of the formation. The Hawkville facies, named for the field area located in LaSalle and McMullen Counties where the net reservoir thickness is found to be in excess of 300 ft (91 m), is a calcareous mudstone that was deposited in an anoxic environment as part of the Cretaceous seaway that traversed north to south through west-central United States and Canada. Long known as a source for oil and gas production from other Cretaceous reservoirs such as the Buda, Austin chalk, Olmos, and others, the Eagle Ford has moderate to high total organic content (TOC) ranging from 3 to 5% and thermal maturities based on vitronite reflectance ranging from approximately 0.7 to 1.3. Operationally, the field has proven to be one that has been relatively benign from a drilling perspective. The Tertiary is at the surface and is a sand-dominated section extending to as deep as approximately 8000 ft (2438 m) near the down dip limits of the field and results in excellent rates of penetration. The Cretaceous Midway, Taylor, and Austin formations also provide consistent drilling conditions. Wells in the field that are in the measured depth range of 15,000 to 18,000 ft (4572 to 5486 m) are commonly drilled from spud to total depth in 8 to 12 days or less. Completion operations are similarly advantaged. The reservoir is extremely brittle and is very receptive to the high-rate hydraulic fracturing processes that are necessary to establish commercial production, with a very low percentage of screened out fracture stimulation stages. Production operations vary widely based on product type, gas-to-oil ratio, and the volatility of the liquid. However, to date, there have not been material changes in the gas-to-oil ratio of the producing wells that would suggest degradation of ultimate recoveries based on bubble point or dew point effects. The regulatory and community effects have also been relatively benign in terms of impediments to the development of the field. The state of Texas and the oil and gas industry have a long history of working in a collaborative manner. Very early in the field’s history, the Eagle Task Force, led by railroad commissioner David Porter, was organized with members from the state bureaucracy, industry, and community with the intent of promoting economic activity, establishing best practices across the play, and reacting to issues that affected the constituencies within the group. One of the most significant issues is water usage, which is a common issue in all unconventional development that utilizes isolated multistage hydraulic fracturing. One of the benefits to the field is the presence of the Carrizo aquifer, which underlies a vast majority of the field. The Carrizo is a fresh-water aquifer that has proven to be an excellent source of water without experiencing material depletion, primarily because of its extremely large amount of available water and because it is actively replenished except in times of severe drought.

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.