The inherent nonuniqueness of geophysical analysis can mean that interpretations based only on a single geophysical measurement can be ambiguous or uncertain. We have developed a case study from the Hoop area of the Barents Sea, in which prestack seismic, well-log, and controlled-source electromagnetic (CSEM) data were integrated within a rock-physics framework to provide a more robust assessment of the prospectivity of the area than could be obtained by seismic analysis alone. In this example, although quantitative seismic interpretation identified potentially hydrocarbon-bearing sands, the saturation was uncertain. In this area and at shallow depths, the main focus is on (very) high oil saturations. Adding the CSEM data in this setting allows us to distinguish between high saturations ([Formula: see text]) and low and medium saturations ([Formula: see text]): It is clear that saturations similar to those observed at the nearby Wisting well ([Formula: see text]) are not present in this area. However, because of limitations on the sensitivity of the CSEM data in this high-resistivity environment, it is not possible to distinguish between low and medium saturations. This remains an uncertainty in the analysis. Based on the resulting downgrade of the main prospect Maya and the limited additional high-risk prospectivity at other stratigraphic levels, the partnership agreed to surrender the license.
This paper is the third part in a reservoir characterization series. Its objective is to demonstrate the necessity of understanding the rock property responses of a reservoir so that the project results can correctly interpreted. The first step is to check and correct acoustic and density well log curves. For the current study a combination of Raymer for density and Greenburg-Castagna for Vs were applied in the shallow zone above the reservoir. Within the turbidite reservoir section a laminated sand fluid substitution was used to understand its behavior as fluid content varies, and a matrix substitution to understand its behavior as sand content varies. Synthetic gathers were calculated for all models using both ray traced and full waveform algorithms. These exercises showed that AVO analysis could be used to detect fluid changes in the seismic data but not for detecting sand content changes. Rock physics crossplots, however, could make this distinction. The seismic inversion was calibrated to acoustic impedance (AI), shear impedance (SI), and Poisson's Ratio (PR) well log curves and clearly revealed that acoustic anomalies seen in this prospect were the result of sand content changes and not the result of fluid saturation changes.
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