Abstract The geochemistry of oils and gases, as well as sediments from which they are derived, is fundamental knowledge. The current study produces a subregional to regional characterization of the geochemistry of Eagle Ford oils and sediments in the context of a meaningful stratigraphic framework. The study area includes the main and most important producing areas of the Eagle Ford shale oil play. The lower part of the Eagle Ford is shown to be the organically richest part of the group. This is demonstrated by the general literature, reference to work completed by colleagues of this volume, and presentation of data for a core from an important Eagle Ford producing area. This interval is lower-middle Cenomanian in age. It depositionally predates the Oceanic Anoxic Event 2 (OAE2) that occurs at the Cenomanian–Turonian boundary. Elevated organic richness in the lower Eagle Ford that varies along strike suggests organic accumulation is partly controlled by localized, semipermanent circulatory patterns. Multivariate statistical classification using biomarkers and carbon isotopes from a large number of oils in Cretaceous reservoirs closely related to the Eagle Ford resulted in the identification of eight compositionally distinct families, three of which occur in the main part of the Eagle Ford shale oil-producing area: Family 2, Family 3, and Family 7. Average data for each family are compared to a large set of global oils representing a variety of depositional environments and depositional times. Comparison of the south Texas oils to the cosmopolitan dataset indicates that Family 3 oils were derived from shales deposited in distal marine settings. Family 7 oils compare favorably with oils derived from carbonate-rich source rocks and Family 2 oils from compositionally intermediate marl-rich sediments. Maturity-sensitive data from the oil families were submitted to principal component analysis. Seventy-five to ninety-four percent of the variability in these datasets was contained in the first or primary principal component (Factor 1). The level of correlation suggested these Factor 1 values could be converted to equivalent vitrinite reflectance values (%VRE). This was accomplished and the VRE for the oils mapped. Oil maturities obtained by this process are consistent with maturity trends obtained from regional considerations. When assessing source rock thermal maturity using pyrolysis techniques (e.g., Rock-Eval), it is useful to measure pyrolysis parameters both before and after solvent extraction, especially at or near peak oil maturity levels. The certitude that oils in this study are derived from the Eagle Ford, as opposed to the Austin Chalk or some third source, comes from several observations. Some Family 2 oils come directly from completions in the Eagle Ford. Family 7 oils come from the First Shot field area and Family 3 oils from Giddings are derived from Eagle Ford/Boquillas Shales based on positive oil-source correlations. Several source scenarios can be imagined given two proven Eagle Ford sources (lower-middle Cenomanian and Turonian) and three organic facies represented by oils. It is possible that one or more organofacies are active sources within each chronostratigraphic interval.

Abstract Our petroleum systems interpretation followed two lines of evidence, considering both tectonic-structural evolution and hydrocarbon geochemistry. Our structural mapping was based on compilations of geophysical data and a review of both published literature and oil company public presentations. Geochemically, we accessed regional nonexclusive oils studies of the conjugate margins of Africa and South America, plus considerable published material. The nonexclusive oils data was refined, with multiple passes, to a group of 286 oils, of which 48 were key to our understanding of the West African Transform (WAT) Margin. Although multiple lacustrine-sourced oil families are seen around the South Atlantic margins, a rich, oil-prone lacustrine source would be a surprise offshore Ivory Coast and Ghana. There is minor evidence of mixed source, possibly lacustrine stringers within an alluvial to marine setting, but the predominant source is marine Cretaceous (Cenomanian–Turonian and possibly Albian). Opening asymmetry of the Equatorial Margin (A) biased the location of lacustrine (early to mid-Cretaceous prerift to early synrift) source rocks to the northeast Brazil margin and (B) locally narrowed the width of the optimal marine (well known mid to Late Cretaceous postrift) WAT margin source kitchens. Burial of the latter, offshore Ivory Coast and Ghana, aggravated the risk of late charge of light (condensate and gas) hydrocarbons.

Abstract The authors have developed a technique for defining source rock sub-basins, particularly those with lacustrine source rocks, and the limits of the related petroleum systems, determining the risk of the petroleum system processes and elements, particularly for charge and to some extent for seal and reservoir. The key was learning how to integrate geophysical (especially gravity and magnetic data) and geochemical data with geologic understanding. This paper presents the development of the tools, techniques, and data sets assembled by our team with examples from prolific hydrocarbon provinces of Brazil and West Africa. The initial work used regional gravity and magnetic data sets ( Barritt, 1993 , Fairhead et al. , 1997 , Dickson et al. , 2003a ,b) to define controlling structural/tectonic features, which influenced basin and source rock development and reservoir emplacement. Sedimentary basins were re-defined from gravity data. Correlations between sediment pathways and gravity signatures indicated redefined depocenters, largely controlled by the coast-parallel, syn-rift fault trend. Transfer faults, trending roughly orthogonally to the coasts of West Africa and Brazil resulted in “piano-keylike” segmentation of the margins. These were seen first on gravity imagery and later, along the Brazil margin, interpreted from magnetic attributes. Adding geochemical data, we plotted oil families and noticed clear separation of these families across some of the coast-orthogonal transfer faults segmenting and dividing the source rock containing sub-basins. Oils tended strongly to stay within the compartments defined by the transfer faults and the coast-parallel, syn-rift fault trend and other lineations. These compartments were first matched to published interpretations of paleo-lakes. The correlation was then carried along the studied margins. Sub-basins correlated with clear differences in oil geochemistry, defining several petroleum meso-systems ( Schiefelbein et al. , 2003 ). More detailed analyses, using additional data (such as piston cores and surface slicks), within each basin revealed probable generative sub-basins, hydrocarbon migration pathways and barriers. Pass-fail tests were established for various criteria, especially burial depth and adequacy of top seal for hydrocarbon generation and retention, respectively. For example, offshore Brazil, depth of burial for oil generation from each source unit was correlated to sediment thickness mapping. The maps were based on magnetics, using multiple depth constraints including published cross-sections, surface geology, wells, and Euler deconvolution of gravity. Resulting depth accuracies of 500 m were sufficient to determine adequacy of present-day burial for the main lacustrine and marine source rocks. Top seal was risked by correlating gravity attributes to published salt mapping and interpreted profiles to determine areas of near-surface disruption of top seal. We then compared those attributes to oil gravities, piston core gas anomalies, and sea surface seep locations. Areas of diapir concentrations tended to correlate with the presence of oil slicks (from RadarSat) and seepage anomalies demonstrating leakage. The outcome was a robust understanding of key prospect risks in this region. In addition, our methodology is transportable with application to other areas, including convergent margin basins in Southeast Asia.