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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Over the last decade, there have been several discoveries of significant oil accumulations in deepwater reservoirs. With advances in research and the availability of high-resolution seismic data, their variability and complexity have been well documented. For hydrocarbon exploitation purposes, however, the industry lacks an integrated approach to interpret these reservoirs, using multiple domains, and efficiently consume the available data. This paper describes a series of innovative interrelated techniques, plus observations to help improve the understanding of these reservoir types at three scales:Basin scale: Stratigraphic forward modeling is a useful method to simulate regional geological processes. Using this technique a paleo-basin floor surface reconstructed from seismic can be used to set a series of simulations. By varying several parameters, such as water level and water/sediments coefficients, within a reasonable range of values and comparing results to observed data, plausible models are created. These, considered jointly, provide an integrated understanding of the uncertainty of the occurrence of observed features and sediment properties.Sequence scale: Sinuosity and stacking configurations are critical factors that control local channel-fill patterns. By using seismic sections along channels, coupled with seismic reconstruction, complex paleo-sequence geometries can be resolved. In our case a low-sinuosity channel was identified and a backstepping-fill pattern defined.Reservoir scale: The quantification of net-to-gross is critical in hydrocarbon exploitation. By using training grids and multipoint statistical methods a comprehensive facies model can be built. Training grids, based on fill patterns and channel geometry, are combined with probability properties to condition the overall stochastic distribution of facies. Additionally, uncertainties associated with this process are captured in an uncertainty workflow. Integrating these three techniques leads to a better understanding of reservoir-critical factors. The above approach is proven by using a seismic dataset from Campos Basin, Brazil, which contains well-documented reservoirs originally deposited in a deepwater setting. Introduction Deepwater clastic sediments form important hydrocarbon reservoirs globally, for example the Atlantic margins of West Africa and Brazil (Weimer et al., 2000), and over the last decade there have been several significant discoveries in these provinces. However, with increasing insight into these deepwater reservoirs as a result of high-resolution seismic data and borehole imaging techniques, more complexities are being revealed than previously anticipated. Furthermore, with higher data volumes there is a growing need to integrate, both across data types and geoscience domains.

Different oil operators have faced technical and economic challenges while drilling in Neuquén basin. Drilling in a tectonic active setting creates problems ranging from influxes and stuck pipe incidents to circulation losses. The presence of natural fractures with an abnormally high pore pressure environment in Quintuco formation increases the gas kicks risks during drilling. Drilling nearby wells has evidenced many severe events, like many days to control a hydrocarbon influx with simultaneous losses. Stuck pipe is the responsible for lost BHAs and considerable NPT spent on freeing the pipe, performing additional wiper trips and hole cleaning. Minimizing non-productive time associated with wellbore instability reduces the risk of dangerous accidents at the wellbore site and it is required to complete the well on time and within the budget. This article describes a methodology to reduce drilling risks, in complex pore pressure conditions at Quintuco formation in Neuquén Basin. The proposed method is based on two main assumptions: the 3D pore pressure characterization based on elastic wave velocities on two different levels in Quintuco formation; and the intensity of the influx events is characterized by the presence of fracture corridors. The value added by the integrated team's efforts was demonstrated by drilling the next two wells with significant reductions in costs and nonproductive time.

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