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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.

Interpretation of sand injectite reservoirs from conventional reflection seismic data is a complicated exercise. The complex geometries of injectites are challenging to detect and resolve by using conventional seismic processing due to their lateral and vertical variability in thickness and dip. Steeply dipping injection dikes tend to appear blurred or distorted on reflection images, and interpretation of their positioning and thickness carries an important level of uncertainty. Structural attributes derived from reflection images are used to support interpretation, but they suffer from a lack of spatial resolution and vertical continuity. We introduce a novel interpretation workflow that includes a diffraction image in addition to the conventional reflection image to improve the detectability and resolution of steep injection dikes and small-scale features. The diffraction image is generated in a migrated dip-angle domain where diffracted and reflected energy can be separated. A case study from a large injection complex in the Norwegian North Sea illustrates the superiority of the diffraction image over conventional structural attributes to support the interpretation and characterization of thin and steeply dipping injectites. The complementarity of the reflection and diffraction images is exploited by visualization techniques (e.g., corendering) or by combining interpretations from separate images, providing a complete picture of the injection complex geometries. Diffraction imaging proved to be a valuable tool to improve the level of detail and confidence in the interpreted injectites, both for modeling and well-planning purposes.

GDF-SUEZ and Sonatrach will develop in partnership the main fields of the prolific Sbaa basin, SW Algeria. In this basin, the main gas levels comprise the Cambrian and Upper-Ordovician reservoirs, sealed and sourced by the Silurian "Hot Shales" Formation. During the exploration and appraisal phases of the project, an intensive drilling program, including coring, standard logging and imaging (FMI), following a 3D seismic campaign was performed. Integrated study was done to investigate the suspected impact of natural fractures on the reservoir performances, to suggest potential geological drivers on fracture type (such as diffuse fractures and fracture swarms, if any) and on fracture distribution. The hydraulic properties of the fractures, based on available dynamic data were also evaluated. Indeed, accurate information on fault network and on fracture properties is essential to improve strategies for maximising hydrocarbon recovery, by optimising well location or directional drilling.Various seismic anisotropy "fracture relevant" attributes (RMS, Coherence and Dip) were selected and jointly used in a multivariable statistical process called Seismic Facies Analysis (SFA). This gave a preliminary interpretation of the seismic facies in terms of fracture density that was completed and validated with well data and curvature analysis. The curvature pointed out various scale lineaments fully consistent with previous work. It concludes on predominance of fault-related fractures. According to dynamic data, well productivity may be enhanced by fracturation by a factor up to 12. The resulting fracture probability map was used to build a 3D fracture model with IFP and FracaFlow® software dedicated for fracture analysis and fracture modelling. For each well, a local discrete fracturation model was built. The length and intrinsic permeability of fractures were then calibrated using KH determined by well test interpretation and production log analysis. The final result consisted in computing the equivalent properties of the fracture network in each cell of the reservoir grid in order to perform the reservoir simulation. In this study, we present the results of production log (PLT) matched with success. The same fracture parameters were also used to match consistently the production log of the other wells . The integration of a wide type of data to analyse the natural fractures of this Algerian gas field leads to a fully consistent and well-constrained fracture model.

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