First Break - Volume 23, Issue 9, 2005

Chris Soufleris and Christof Stork, WesternGeco, discuss a new generation of advanced depth imaging algorithms, wavefield extrapolation migrations.

Steve Pharez, Jon Beard, Mohsen Selim, Paul Lecocq and Carl Fiduk of CGG describe the acquisition and processing challenge of meeting the deadline for seismic survey projects as Libya opens up its offshore to international exploration.

Using tailored solutions Dr Alexandre Bertrand and Dr David Bannister, Geotrace Technologies UK, offer some hope that quantitative 4D analysis is by no means impossible when using legacy data with examples from the Norwegian sector Troll field.

Tony Rebec, Paradigm Geophysical; Patrick T. Gordon and Joseph Samuels, Atlas Petroleum Exploration Worldwide; and George Marion, Seisborg Geophysical, describe the application of an amplitude-friendly technique to attenuate noise and multiples for processing seismic in problematic structures such as the Gulf of Gabes, offshore Tunisia.

Neil Hargreaves and Richard Wombell, Veritas DGC, Crawley, UK focus attention on the obstinate problem of removing multiple diffractions found in marine seismic data.

Dag O Larsen, Geysir Petroleum, offered this comment on the article entitled ‘Seeing through a glass, darkly: strategies for imaging through basalt’ by Jennifer Maresh and Robert S. White published in First Break, 23, 5, 27, 32, 2005. The authors’ response is published below.

The main goal of reflection seismology is to obtain a reliable image of the subsurface. The method widely used to accomplish this task is NMO and CMP stacking. In areas with relatively simple geological structures this robust technique produces a reasonably good image of a zero-offset time section. However, in areas with complex geology, the central problem of reflection data processing becomes to produce a reliable image of zero-offset section, i.e. to obtain a stacked time section which is as close as possible to the true zero-offset section. This image should include all the reflected events that may be related to different geological features. The reflections may come from various depths and have various dips. In complex geological media, more than one dipping reflector can exist at the same reflection time. The NMO-based CMP stacking fails to resolve conflicting dips, because it acts as a dip filter selecting one predominant dip, thus deteriorating the quality of the stacked section. The usual way to overcome the problem is to apply dip moveout (DMO) correction (Hale, 1984; Deregowski, 1986; Yilmaz, 2001). The DMO is able to preserve all the dips existing in the data and thus to produce a much better image of zero-offset section. The DMO is usually implemented as a part of a processing sequence including velocity analysis, NMO, DMO, inverse NMO, velocity analysis, and NMO with new velocities and stack. However, applying the DMO sequence can be time-consuming and not always effective. We propose an alternative way for imaging zero-offset sections. We show that using the multipath summation approach implemented as a single, simple, quick and efficient process (Keydar, 2004; Shtivelman and Keydar, 2004; Landa, 2004), one can achieve the results equivalent to those obtained by the above DMO sequence. The proposed method does not require information on velocities, since the multipath summation is performed for all possible velocity values within a wide specified range. Furthermore, the method is stretch free, since no explicit dynamic correction is involved. An additional feature of the method is that it preserves the signature of the waves for which the summation is performed. Application of the method is illustrated by a synthetic example. The example demonstrates that the section obtained by the multipath summation is very close to the true zero-offset section.

Cost effective 2D (or 3D) data collection may require sparse sampling and can lead to spatial aliasing of seismic data. There are two distinct causes of spatial aliasing that need to be distinguished. Firstly, aliasing may occur due to sparse collection geometry. Secondly, aliasing occurs in seismic data processing by trace sorting to form common midpoint (CMP) and common offset gathers. This type of aliasing arises due to the ‘sampling paradox’ (Vermeer, 1990) and we will refer to it as CMP aliasing. Both types of spatial aliasing pose problems for prestack and poststack processes such as migration, DMO, Radon transform, and f-k filtering. Spatial aliasing also leads to undesirable effects (see, for example, ‘The checkerboard effect’ in Vermeer, 1990) on stacked seismic sections. Hence dealiasing procedures are desirable. Using Petersen and Middleton’s (1962) sampling theorem, which is presented for the 2D case by Bardan (1997), we describe an efficient exact trace interpolation algorithm for the removal of CMP aliasing and discuss aspects of its use.

Although the specific flow behaviour of fractured reservoirs was identified and modelled a relatively long time ago (Barenblatt et al., 1960; Warren and Root, 1963), until recently no consistent methodology and software really enabled the integration of field information about natural fracturing in reservoir engineering studies. The availability of direct information about fractures, in particular borehole images, was an incentive for such integration. The unexpected production behaviour of many fields arising from an insufficient consideration of fracture effects on flow also emphasized the need for better characterizing the distribution of fractures at various scales and transferring the meaningful part of this information to field simulation models. A recent example concerns a giant Middle East Carbonate field where sub-seismic fracture swarms and stratiform super-K intervals were found to establish preferential flow paths between injection and production wells (Cosentino et al., 2001). Therefore, the present trend in fractured field studies is toward the use of methodologies and software platforms to integrate all information about fractures into flow simulation models. The main features of those methodologies are described here, on the basis of fracture modelling examples set up using our own workflow (Bourbiaux et al., 2002). The latter involves the following steps: ■ constrained modelling of the geological fracture network based on the analysis, interpolation, and extrapolation of fracture information acquired in wells and derived from seismic data, sometime completed by outcrop analogue data; ■ characterizing the hydrodynamic properties of this natural network from flow-related data; ■ choosing a flow simulation model suited to the role played by fractures and faults at various scales and assigning to this model upscaled parameters derived from the flow-calibrated geological fracture model; ■ simulating the reservoir flow behaviour on the basis of a physical assessment of multiphase flow mechanisms acting in transfers between matrix and fractures. In the following, those four steps are reviewed and illustrated from a representative synthetic field case. Emerging techniques to further capture the complexity and flow behaviour of fractured reservoirs are also identified.