ABSTRACT A new model is proposed to predict porosity in organic matter for unconventional shale reservoirs. This model is based on scanning electron microscopic (SEM) observations that reveal porosity in organic matter is associated with secondary porosity developed within organic matter cement that fills void space preserved prior to oil generation. The organic matter cement is interpreted as solid bitumen resulting from the thermal alteration of residual oil retained in the source rock following oil expulsion. Pores are interpreted to develop within the solid bitumen as a result of thermal cracking and gas generation at increased levels of thermal maturity, transforming the solid bitumen to pyrobitumen. The pyrobitumen porosity model is an improvement over existing kerogen porosity models that lack petrographic validation. Organic matter porosity is predicted by first estimating the potential volume of organic matter cement by deriving the matrix porosity available at the onset of oil generation from extrapolations of lithologic specific compaction profiles. The fraction of organic matter cement converted to porosity in the gas window is then calculated by applying porosity conversion ratios derived from SEM digital image analysis of analogous shale reservoirs. Further research is required to refine and test the porosity prediction model.

Abstract The Cenomanian-Turonian Oceanic Anoxic Event 2 (OAE2) is the last major OAE of the Mesozoic and probably the best studied. In marine rocks around the Gulf of Mexico it is associated with a variety of different environments, from well-oxygenated carbonate platforms to anoxic, organic-rich outer shelf environments and un-studied basinal muds. This paper reviews the current level of knowledge about the geographic distribution and stratigraphic expression of OAE2 in the Gulf of Mexico in order to synthesize this disparate data and attempt to draw some conclusions about regional oceanography during this critical interval of the Cretaceous. A large number of localities with varying local redox states have been tied to OAE2, including the Valles-San Luis Potosí and Guerrero-Morelos platforms in southern Mexico, deep shelf sites in northern Mexico, the well-studied outcrops and cores of west Texas on the Comanche platform, cores and wells along the Barremanian-Albian shelf margin of south Texas, geophysical data in the East Texas basin, cores in the Marine Tuscaloosa Formation of Louisiana, Alabama, and Mississippi, and deep wells in the deep water Gulf of Mexico. The distribution of anoxic sediments at these sites during OAE2 appears to be determined by water depth. Shallow sites, like the Mexican carbonate platforms and the Comanche platform of Texas, are oxygenated during the event. Deeper shelf sites, like the south Texas Rio Grande submarine plateau and the noncarbonate platform parts of the Mexican shelf, are anoxic and enriched in organic carbon; it seems likely that this trend continues across the rest of the Cretaceous Gulf shelf, although data is sparse. Whether this oxygen minimum zone only impacts the deeper parts of the shelf or extends all the way to the basin floor is the most significant outstanding question about OAE2 in the Gulf of Mexico.

Abstract In the search for unconventional reservoirs, one of the geological formations most studied in the United States is the Eagle Ford (Upper Cretaceous), which extends from the state of Texas in United States to the northeastern portion of the Mexican republic. The Eagle Ford Formation consists of argillaceous limestones and calcareous siltstone deposited in a mixed environment. These lithologies have petrophysical and geochemical characteristics sufficient to be considered as producing gas and/or oil, depending on the content of organic matter and the degree of maturity thermal reached. In the northeast of the State of Coahuila, based on lithology, paleontological content, and TOC, Eagle Ford formation can be divided into three units: Biozone A: Heterohelix sigali and Helvetoglobotruncana helvética , dominated by limestone, in platform environments, thicknesses of 16 to 100m, and TOC content of 0.56% to 1.65%. Biozone B: Whiteinella archaeocretacea , limestone and calcareous shales, interbedded lithologies, deposited Biozone C: Rotalipora , black shales deposited in suboxic basin, thicknesses of 60 to 95m, and TOC content of 1.86% to 5.2. With the thickness distribution of the proposed units, it can be interpreted that the variation in the water depth depends on the topographic relief that prevailed in the Late Cretaceous (Cenomanian–Turonian) in the northeastern portion of Mexico: in a shelf and basin environment, influenced by Maverick Basin. Geochemical data analyzed and the proposed subdivision, indicates that Biozone C drive is the thickest, and has more TOC content in the northeastern part of the Burro-Picachos Basin; the predominant type of kerogen in the area is the type III. Using the Dykstra-Parson method to determine the homogeneity of the distribution of values of each proposed unit, Biozone A has a higher degree of homogeneity than Biozone C. However, based on TOC and degree of homogeneity, Biozone B has a lower degree of exploration.

Abstract A regional network of five interlocking stratigraphic cross-sections compiling the published work of many geologists throughout central and southwest Texas demonstrates the true stratigraphic relationships among formations of the Lower Cretaceous Fredericksburg and lower Washita subcycles. Strongly supported by a long-established ammonite zonation, these detailed stratigraphic cross-sections show lateral relations between Edwards Group formations (Kainer, Person, Fort Terrett, Segovia, Fort Lancaster, and Devils River) of the Central Texas Platform with equivalent formations of the East Texas Basin (Walnut, Comanche Peak, Goodland, Georgetown) and the Maverick Basin of South Texas (West Nueces, McKnight, Salmon Peak). These cross-sections document the following regional stratigraphic relationships: The Burt Ranch Member (basal Segovia Formation), the Regional Dense Member (basal Person Formation), and the Kiamichi Member (basal Georgetown Formation) are stratigraphic equivalents, all three being in the Adkinsites bravoensis Ammonite Zone (lowermost Washita) The peritidal Person Formation is the shelf-interior equivalent of the pelagic-shelf Georgetown Formation, except for its uppermost member, the Main Street, which forms the thin remnant Georgetown Formation on the distal Central Texas Platform. Thus the Person Formation is properly assigned to the lower Washita subcycle, not the Fredericksburg.

Abstract Although typically considered with a focus on high-resolution petrography, shale porosity should not be thought of as a stand-alone petrographic feature. Shale and mudstone porosity is the outcome of a long succession of processes and events that span the continuum from deposition through burial, compaction, and late diagenesis. For the Eagle Ford Shale this journey began with accumulation in intra-shelf basins at relatively low latitudes on a southeast-facing margin during early parts of the late Cretaceous. To understand the factors that generated and preserved porosity in this economically important interval, a scanning electron microscope study on ion-milled drill-core samples from southern Texas was conducted to understand the development of petrographic features and porosity and place them in stratigraphic context. The studied samples show multiple pore types, including pores defined by mineral frameworks (clay and calcite), shelter pores in foraminifer tests and other hollow fossil debris, and pores in organic material (OM). In many instances, framework and shelter pores are filled with OM that has developed pores due to maturation. Large bubble pores in OM suggest that hydrocarbon liquids were left behind in or migrated into these rocks following petroleum generation and that the bubbles developed as these rocks experienced additional thermal stress. These larger OM pores indicate deeper seated interconnection on ion-milled surfaces and in three-dimensional image stacks. The largest pores occur in the infills of foraminifer tests. The framework of crushed carbonate debris in planktonic fecal pellets shows intermediate levels of porosity, and the silicate-rich matrix that encloses framework components has the smallest average porosity. The distribution of pore types is not uniform. Our hypothesis is that facies association is an important factor that determines bulk porosity and influences reservoir performance. The observed variability in the attributes of the described distal, medial, and proximal facies associations is thought to translate into significant variability of rock properties such as total organic carbon and porosity. In turn, this variability should control the quality and distribution of the intervals that are optimum sources and reservoirs of hydrocarbons in the Eagle Ford Shale. The medial facies association most likely has the best porosity development when a favorable combination of more commonly abundant calcareous fecal pellets and organic material versus clay content is present. The systematic arrangement of facies associations into parasequences provides the basis for testing and predicting the best development of optimal reservoir facies within a sequence-stratigraphic framework in the Eagle Ford Shale.

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.