The presence of reservoir quality sediments, in both carbonate and siliciclastic environments, is a direct consequence of sedimentary processes related to the depositional setting. Exploring for and developing hydrocarbon resources is therefore irrevocably linked to the understanding of these processes, which can lead to the ability to predict sediment distribution in time and space. A knowledge-driven approach, such as that used by Digital Geology AS, using well, seismic and other data, which relies on a consistent understanding of the geology at all scales and stages, can reveal those hidden reservoirs.

The Methodology

This knowledge-driven approach has a number of stages, as briefly outlined below:

• A consistent interpretation of lithology, facies, facies associations and stratigraphy is established for the entire wellbore for all wells in the study area, based on an in-depth study of all available data, including logs, core, trace fossils, biostratigraphy and biological environmental assessment;
  
• Subdivision of the rocks into genetic sedimentary packages through sequence stratigraphy enables the correlation of different facies and the logical prediction of sediment distribution in time and space. Megasequences (and sequences) are bound by regional peak transgressions (‘maiximum flooding surfaces’), which are easy to recognise on a regional (i.e seismic) scale, so the next step is to delineate these transgressions;
  

• The lithological stacking pattern is combined with seismic data and other information to map the shoreline trajectory for the various depositional units;
  

• The uneroded thickness map for each depositional sequence is used together with the well data to map the paleo-coastline;
  

• Based on this approach the depositional models for each megasequence and sequence can be established.
  

An Example from the Barents Sea

Digital Geology has used this approach on exclusive studies for clients in Colorado, North Dakota, Trinidad, Bangladesh, Azerbaijan and Kazakhstan, among others, and also have a commercially available depositional model based on studies covering the Norwegian Sea and the Barents Sea. The models are built in Roxar RMS, but are also available in Petrel. In this article we look in detail at the south-west Barents Sea and investigate how this approach can be actively used to fine-tune our understanding of the orientation of depositional systems.

Using a model of the south-west Barents Sea, extracted from the larger ‘Digital Geology megasequence 4D digital sedimentary model’ covering the Norwegian Barents Sea, we applied the methodology outlined above. Focusing on megasequences 5 to 12 (Late Jurassic to Paleogene) and combining the non-eroded (time of deposition) thickness maps with today’s structural setting, a series of 3D volumes depicting source potential was generated. The results revealed the high likelihood of several intervals containing source rock potential within Lower Cretaceous strata, as corroborated in wells and in outcrops onshore Svalbard.

Similarly, information about the possible distribution of reservoirs can be obtained through the consideration of a combination of two key elements: i) thickness maps generated for each megasequence at the time of deposition, and ii) an understanding of the shoreline trajectory derived from well facies stacking patterns and seismic interpretation indicating probable directions and angle of progradation/retrogradation. In short, outcrop data from southern Svalbard depicts a low angle to flat shoreline trajectory resulting in the depositional system prograding several hundreds of kilometres across the shallow shelf at the time, something that is corroborated with seismic across from Russian sector. The near flat angle of trajectory explains the lack of shallow marine coastal sands found in the few wells drilled, since such a low-angle system will result in sediment-bypass to the edge of the shelf at the time of deposition, as shown in the Digital Geology model below.

Further analysis of the model shows that, following a regional transgression during the late Early Cretaceous, at least two major phases of northern uplift can be observed in Svalbard, both of which caused major basinward shift of facies, again yielding reservoir potential sediments into the areas open to hydrocarbon exploration announced for the South West Barents Sea in 2016.

Following the initial opening of the Norwegian-Greenland Sea an area from Svalbard southwards to Bjørnøya was uplifted, shedding large volumes of sediments eastward into the Barents Sea in the very early Paleocene (as can be observed on Svalbard and in well 7321/19-1, the Pingvin discovery); again, our analysis of resultant Megasequence 10 suggests the possibility of reservoir quality sediments in the interval.

Successful Integrated Approach

This study clearly shows the potential for areas announced open to hydrocarbon exploration for the South West Barents Sea in 2016 and also explains the lack of success of the most recent wells made publicly available, 7212/8-1 and 7212/11-1. As such, it represents a new approach in understanding the dynamics of the depositional systems of the Norwegian Barents Sea and illustrates the much wider progradation of the sedimentary succession during the Latest Jurassic to Paleocene within the south-west Barents Sea.

It also demonstrates that this integrated approach, which we believe represents the optimal 21st century exploration and appraisal tool, which enables not only the confident mapping of the location of facies belts and their logical extensions, but provides us with a quantification of both source rock potential and reservoir rock distribution in time and space.