Interpretation of regional two-dimensional seismic surveys and three-dimensional seismic surveys in the central North Sea has demonstrated the existence of a pervasive polygonal network of normal faults affecting Tertiary shale-dominated slope and basin-floor depositional systems. The area affected by the faulting encompasses most areas of hydrocarbon production from Tertiary sandstone reservoirs. The polygonal fault networks were active during sedimentation and early burial. Throws measured on individual faults range from 8 to 100m, with average fault plane dips of 45°. Lengths of individual fault segments range from 80 to 1400m, and average fault spacings range from 100 to 500m. The high density and the polygonal geometry of the faults make seismic interpretation of the Lower Tertiary interval problematic, and can lead to misinterpretation of faults as apparent seismic-stratigraphic features. The recognition of this fault system has consequences for the development of of fields in Tertiary reservoirs. The remaining hydrocarbon potential in the Lower Tertiary could be considered predominantly to be stratigraphic plays, but the presence of faults active during sedimentation and early burial implies that this play concept is too simplistic, particularly for Eocene reservoirs. The role of both syn-depositional and early-burial normal faulting on original reservoir distribution and post-depositional modification should be considered further. The presence of this fault system may also be important for secondary migration into Lower Tertiary reservoirs from Kimmeridge Clay Formation source rocks. The existence of an interconnected fault and fracture network in the low-permeability mudrocks may have provided an efficient vertical migration pathway for charging isolated lower Tertiary sandstone reservoirs. Finally, the maximum fault throws of between 50 and 100m are large enough to represent potential barriers for lateral communication in sandstone reservoirs where individual sand bodies are commonly 25–100m thick.

Exploitation of shale plays is viewed by many as a major resource for future economies of many countries. To date, most exploitation of this resource has centered on North America where the existing high onshore well count previously drilled for conventional resources guides pursuit of unconventional plays. The situation is, for example, very different across onshore Europe, which has a low existing well count for conventional resources and notable socio-political and infrastructure challenges, such as high-population densities. To be successful, the delineation of European shale plays must use existing data for exploration and drill a reduced number of wells during exploration. During the exploration phase, the ability to manage uncertainty and make informed decisions across the potential shale plays is vital. An optimal approach is proposed, whereby all possible surface and subsurface sources of data are integrated and exploration screening is done based on advanced petroleum systems modeling. To illustrate the approach, data from onshore Netherlands has been selected. The West Netherlands Basin and Roer Valley Graben contain organic-rich Jurassic sequences within the Altena Group, including the well-known Posidonia Shale Formation. This formation is currently being targeted as a potential unconventional resource. A fully integrated 3D geological model – including an advanced 3D petroleum systems model – is presented, which includes critical spatial information, such as geographical terrains and surface constraints. Results from this approach clearly demonstrate areas of higher prospectivity, and, importantly, their associated uncertainty. This allows E&P companies to select areas that have the best chance of success.

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Once considered a dangerous nuisance in the mining industry, coal seam gas (CSG), or coalbed methane, is now seen as an abundant clean energy supply that will help replace other diminishing hydrocarbon reserves. The nature of the coal-bearing sequences, however, makes them difficult to drill and produce profitably. Major challenges include multiple thin-bedded zones, strong variations in quality of coals, and large volumes of formation water that must be removed before the gas can flow to the surface. This paper describes a new technology- and knowledge-driven approach to address these challenges in the exploration and development stages of a CSG field. During exploration, combining multiple data types in a single model reduces dramatically the uncertainty around coal seam distribution and gas-in-place estimation. In field development planning, the unification integrates static and dynamic data to enable a better understanding of the field's producibility. The exploitation of CSG requires analyses of many scenarios and uncertainties. In addition, it requires hundreds of wells to be drilled in a short period of time. Consideration of the high levels of uncertainty and the integration of large volumes of newly acquired data can be achieved efficiently only in a unified software environment that is associated with a strong knowledge management system. In fact, one of the key benefits of this new unified approach includes the ability to update models and test multiple scenarios at any stage of the field life cycle, and track the processes with a strong audit trail. Data used for demonstration in this paper are from the Surat basin in Central Queensland, Australia.

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