A subtle, sophisticated class of opportunities for which uncertainties must be reduced, drives today's exploitation of oil and gas in Deepwater. Today's explorer is often faced with the issues of seismic imaging, non-amplitude supported oils, stratigraphic uncertainty, and uncertain hydrocarbon kitchens, all in an environment dominated by rising deepwater costs and still-maturing technology. However, many of the fundamental Exploration processes that drove the industry before the advent of the amplitude play in the Gulf of Mexico, still apply. Although success rates associated with those early techniques alone are not acceptable in today's industry, explicit integration of these historically proven processes with each other and with new technologies, driven by a growing body of knowledge within the GOM Deepwater, has provided a significant new methodology for wildcat and near-field Exploration. Even in mature fields, additional opportunities are seldom characterized by unambiguous attributes of direct hydrocarbon indicators or amplitude support.

Shell's "Quantitative Integrated Evaluation" process relies upon visualization of integrated volume-based models of texture derived geologic stratigraphy and of predicted rock and fluid properties. These models also represent the corresponding full, 3-D, elastic seismic responses, explicitly compared and calibrated to measured elastic seismic attributes. A "Differential Generalized Attribute", which summarizes the differences between multiple scenario response predictions and actual measured data, can then be used to estimate the subsurface scenario's likelihood of occurrence and detectability. This ethodology allows competing scenarios to be rapidly tested against the data, and is built upon proprietary knowledge of the physical processes and relationships that likely drive vertical and lateral variation in the earth. As a demonstration of this methodology, we will show a portion of the Ursa Basin and describe the integrated capability that is emplaced at the Exploration phase, and matured throughout the Appraisal, Development and Production life cycle of a basin discovery.


Many under-compacted sedimentary reservoirs respond to seismic waves with a correlative response to the soft impedances that most oils and gas provide at those temperatures and pressures. Within Shell, this provided an early, quantitative risking framework that resulted in significant Exploration advantage and success, particularly in the Deepwater Gulf of Mexico. As the search for large, deepwater opportunities was extended into older compacted sediments, and expanded into poorer imaged, more complex settings, the impact of stack seismic amplitude analysis for hydrocarbons was significantly reduced, and was no longer a sufficient condition for evaluating the risk of an opportunity, see (Fig. 1).

Fig. 1 - Typical reduced fluid resolution with depth at Ursa Field. Both quartz sand bulk density and rock compressional velocity increase with depth, but the differentiation between brine and oil, and oil and gas significantly decreases. (Available in full paper)

Without a strong, direct indicator of hydrocarbons, issues related to seismic response imaging, non-amplitude supported oil properties, reservoir identification and stratigraphic uncertainty, and uncertain hydrocarbon kitchens become key focus areas requiring a method for balanced and explicit integration into the evaluation.

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