The petroleum industry is increasingly looking for methods to reduce uncertainty in field development. It is important to have a quantitative understanding of the 3-D geometry, spatial distribution and petrophysical properties of genetic sedimentary units, in order to reliably appraise reservoir potential. Core and log data, while detailed, are insufficient for lateral interpretation over inter-well volumes, whilst seismic data typically have insufficient resolution to capture all the relevant sedimentary architecture.

Geologists assess the flow properties of petroleum reservoirs by studying analogous, large-scale sedimentary outcrops. One method of obtaining geometric information of sedimentary architecture is to acquire ground-based photomosaics of well exposed outcrop sections which, when combined with conventional sedimentary logs, are interpreted both sedimentologically and stratigraphically. This technique can be used on outcrops with little rugosity to acquire quantitative geometric data from sections tens of metres thick (Arnot et al. 1997). However, large-scale planar exposures are uncommon and photo-geological interpretations can suffer from distortions and parallax effects. Additionally, interpreted measurements taken from 2-D exposures may be influenced by the size, shape and orientation of the exposure, rather than by the dimensions and shape of original geological features (Geehan and Underwood 1993). Comparison studies generating synthetic seismic sections from 2-D photomosaic interpretations show the difficulty in resolving sedimentary bodies from seismic data in enough detail for successful characterisation (Figure 1).

Figure 1. Sand-rich turbidite channels

Exceptionally well exposed, sand-rich turbidite channels of the Upper Campodarbe Group, at Ainsa II, Southern Pyrenees, Spain have been interpreted and 2-D synthetic seismic sections have been constructed, with parameters honouring Tertiary reservoir rock properties in the UKCS. Seismic central frequency was set at 52 Hz.