First Break - Volume 31, Issue 4, 2013

Ivan Guerra, Federico Ceci, Fabio Miotti, Andrea Lovatini, Graham Milne, Mehdi Paydayesh, Margaret Leathard and Ajai Sharma describe the acquisition, processing, and modelling of 3D CSEM data, and the petrophysical joint inversion of the results with high resolution 3D seismic data for exploration prospect evaluation in the Barents Sea.

Stefan L. Helwig, Abdul Wahab El Kaffas, Terje Holten, Øyvind Frafjord and Kjetil Eide present the ‘vertical–vertical’ approach to marine controlled source electromagnetic surveys and discuss its potential benefits compared with conventional horizontal dipole methods.

S. Garina, S. Ivanov, E. Kudryavceva, P. Legeydo, P. Veeken and V. Vladimirov, discuss geochemical alteration zones above hydrocarbon accumulations, identified by differentially normalized electromagnetic surveying, and how they may give rise to induced polarization (IP) anomalies.

José Antonio Escalera Alcocer, Marco Vázquez García, and Humberto Salazar Soto, Daniel Baltar, Valente Ricoy Paramo, Pål T. Gabrielsen and Friedrich Roth show with four case studies how the inclusion of 3D CSEM resistivity data with seismic and other data provided more confidence in Pemex reservoir evaluations and so positively impacted the company's exploration programme.

Michael S. Zhdanov, Leif Cox, and Jonathan Rudd demonstrate with a case study of oil sands exploration near Fort McMurray, Alberta how the 3D inversion of airborne electromagnetic survey data can be used to improve near-surface imaging, in their view a potential paradigm change particularly with regard to hydrocarbon exploration.

Joseph Barraud discusses practical ways to analyze the results provided by curvature-based depth estimation from gravity gradient data which allow the interpreter to discriminate between reliable and spurious estimates.

A solution for automated salt body extraction from seismic data has been developed. The solution is based on a level set algorithm, used in combination with seismic attributes that discriminate between salt and sediments and highlight top and base salt reflections and terminations of sediments against salt. In an automated process, steps to obtain the gross volume of salt are combined with local adjustments to place the salt boundary at the appropriate attribute extrema. The process also includes a local stop criterion based on a salt boundary confidence measure. The ability to separate completed salt boundary parts from uncertain regions where the salt boundary has not been identified enables the interpreter to focus on the parts where manual interpretation is required. User constraints, including manual interpretations, are honoured by the algorithm. The methodology is demonstrated on a multi-client seismic data set from the Gulf of Mexico.

Interpretation of geological features in seismic data is a subjective process, relying on one’s visual perception and experience built up over several years. Based on these human factors, financial decisions are made that may have serious consequences to a petroleum company. The aim of this study is to review the role of one key visual cue in this interpretative process: colour. Colour is a powerful cue that can have a significant impact on the interpretation of seismic data. However, compensation mechanisms within the human perceptual system can sometimes lead to unexpected visual effects, such as luminance sensitivity and simultaneous contrast, which have the potential to bias the interpretation of geoscientific information and therefore increase interpretation uncertainty and risk. Here we examine these visual effects, and present the findings of an experiment aiming to illustrate bias dependent on the use of colour. Both inter- and intra-operator differences were found in the manual delineation of a sedimentary geobody from seismic data. The results clearly suggest that measurements from seismic data based on manual delineation of imaged object boundaries can be associated with uncertainties that are usually unquantified.

The principal source rocks in the Danish and southern Norwegian Central Graben in the North Sea are the Upper Jurassic to lowermost Cretaceous marine shales of the Mandal and Farsund formations. The distribution of generation potential and thermal maturity is quite complex. Biomarkers of crude oils from the northern Danish Central Graben indicate correlation to the Bo Member of the upper Farsund Formation or to the lower part of the formation. Biomarker ratios of oils from the Danish Chalk reservoirs show a maturity gradation from south to north, with oils in the northern part being more mature. Vitrinite reflectance gradients show differences in depth of the ‘top oil window’. In areas characterized by HPHT conditions and thick overlying Chalk, petroleum generation is retarded and the oil window is displaced downwards by 200–350 m. Source rock quality varies. The upper part of the shales is generally considered the most oil-prone. However, analyses indicate that the lower part of the Farsund Formation may contain intervals with rich oil-prone shales. Furthermore, the petroleum generation of the Upper Jurassic shales below the Farsund Formation is often overlooked, but source rock data indicate that gas/oil-prone, and to some extent oil-prone, shales are present.