Abstract Operating subsurface geological assets associated to hydrocarbons, geothermal energy or water management projects safely requires well-trained geoscientists and engineers. For this purpose, a learning platform was developed that exposes petroleum and drilling engineers to subsurface decision-making and uncertainty management. This training platform is called Digital Geology. It focuses on subsurface characterization as well as common safety critical and economic decisions across upstream E&P projects. Digital Geology blends actual geological samples embedded in a digital outcrop environment with virtual reality (VR) overlays of common business environments such as oil and gas fields or drilling platforms. This immerses engineers in a subsurface environment and facilitates project decision-making at different stages of the life cycle of hydrocarbon exploration and development. The geological ‘canvas’ of the training platform is a digital outcrop representation of the Sobrarbe deltaic complex (SDC) in Spain. This digital canvas is segmented into five scales based on the concept of hierarchical heterogeneity of geological systems. The SDC displayed at sequentially smaller scales highlights geological heterogeneities with increasing resolution. The five geological scales are conceptually linked to development stages of common E&P projects that are 1) basin scale heterogeneities that influence decisions around new business development in exploration, 2) play scale geological heterogeneities that are important for exploration of decisions during acreage evaluation, 3) depositional environment scale heterogeneities that influence appraisal and primary development decisions, 4) facies scale geological heterogeneities as derived from wellbore data that affect business decisions during infill drilling and secondary recovery stages and 5) grain scale geological heterogeneities that are important for decisions in the enhanced oil recovery (EOR) phase or in unconventional hydrocarbon developments. Digital Geology is one training module of Shell’s competence-based development program for subsurface petroleum engineers based on approved company standards. The objective of Digital Geology is to strengthen the skills of young engineers in subsurface characterization and its use for effective business decisions. Digital Geology is also a communication tool for multi-disciplinary teams developing subsurface projects together, however, often with vastly different backgrounds. Understanding the subsurface heterogeneities involved in a project is a basic requirement for all of them, not just geoscientists. It is often linked to the success of such projects and is the key input for decision-making. Digital Geology supports this via linking the five geological scales with industry workflows in exploration, development and research as well as with digital outcrop data and subsurface models. The Digital Geology set-up is part of Shell’s digitalisation efforts that are significantly influencing the ways of working also the ones of subsurface professionals. The exhibition and the data sets presented allow to get a good understanding of how geoscientists are working now and, even more so, will work in the future.

Abstract The Pyrenean orogenic system resulted from the inversion of Upper Jurassic-Lower Cretaceous extensional basins that developed along the North Iberian-Pyrenean margin connecting the Atlantic with the Alpine Tethys. These basins together with the Upper Cretaceous to Oligocene synorogenic sub-basins of the southern Pyrenean foreland basin that developed during mountain building host different source rocks and reservoirs. The different petroleum systems in these basins have provided some hydrocarbons with significant discoveries in the Aquitaine Basin. Although no commercial accumulations have been found in the South-Central Pyrenees, this is an area that has attracted the interest of industries and universities for training purposes because of the variety of depositional systems and structures as well as providing a unique opportunity for the understanding of petroleum systems and the reasons for the failure of the exploration drilling conducted until now. Within the southern Pyrenean fold and thrust belt, three main thrust sheets developed since Late Cretaceous times. They detached into the Upper Triassic evaporites and have overthrust Mesozoic and Palaeogene sediments on top of the autochthonous Palaeogene rocks of the Ebro foreland basin. The northern thrust sheet involves the Lower Cretaceous extensional basins. These basins were reactivated at the onset of contractional deformation, and upper Santonian-Maastrichtian syninversion sediments are characterized by a deep subsiding trough of slope sediments grading forwards into a carbonate platform. This Upper Cretaceous foreland basin depocentre was incorporated into the Montsec thrust sheet at Paleocene-Early Eocene times. New basins developed southwards of the previous Upper Cretaceous one. They were partitioned by the thrust salient geometry of the Montsec-Peña Montañesa thrust sheet. The Tremp-Graus Basin, characterized by fluvial to deltaic systems with subordinate carbonates, piggybacked on the Montsec thrust sheet. These depositional systems grade into the slope sediments of the Ainsa Basin and the more basinal turbiditic systems of the Jaca Basin, in the footwall of the Montsec-Peña Montañesa thrust. These turbiditic sediments graded forwards into a Lower-Middle Eocene carbonate platform, at present cropping out extensively in the Sierras Exteriores imbricates. All these sediments were subsequently deformed since Middle Eocene times as deformations progressed forwards and the Gavarnie-Sierras Marginals thrust sheets developed and all the sub-basins shallowed upwards into the Upper Eocene-Oligocene synorogenic continental sediments. The aim of this paper is to describe the geological evolution of the fold and thrust belt and related basins as a framework for the understanding of the petroleum systems.

Abstract The Pyrenean orogenic system resulted from the inversion of Upper Jurassic-Lower Cretaceous extensional basins that developed along the North Iberian-Pyrenean margin connecting the Atlantic with the Alpine Tethys. These basins together with the Upper Cretaceous to Oligocene synorogenic sub-basins of the southern Pyrenean foreland basin that developed during mountain building host different source rocks and reservoirs. The different petroleum systems in these basins have provided some hydrocarbons with significant discoveries in the Aquitaine Basin. Although no commercial accumulations have been found in the South-Central Pyrenees, this is an area that has attracted the interest of industries and universities for training purposes because of the variety of depositional systems and structures as well as providing a unique opportunity for the understanding of petroleum systems and the reasons for the failure of the exploration drilling conducted until now. Within the southern Pyrenean fold and thrust belt, three main thrust sheets developed since Late Cretaceous times. They detached into the Upper Triassic evaporites and have overthrust Mesozoic and Palaeogene sediments on top of the autochthonous Palaeogene rocks of the Ebro foreland basin. The northern thrust sheet involves the Lower Cretaceous extensional basins. These basins were reactivated at the onset of contractional deformation, and upper Santonian-Maastrichtian syninversion sediments are characterized by a deep subsiding trough of slope sediments grading forwards into a carbonate platform. This Upper Cretaceous foreland basin depocentre was incorporated into the Montsec thrust sheet at Paleocene-Early Eocene times. New basins developed southwards of the previous Upper Cretaceous one. They were partitioned by the thrust salient geometry of the Montsec-Peña Montañesa thrust sheet. The Tremp-Graus Basin, characterized by fluvial to deltaic systems with subordinate carbonates, piggybacked on the Montsec thrust sheet. These depositional systems grade into the slope sediments of the Ainsa Basin and the more basinal turbiditic systems of the Jaca Basin, in the footwall of the Montsec-Peña Montañesa thrust. These turbiditic sediments graded forwards into a Lower-Middle Eocene carbonate platform, at present cropping out extensively in the Sierras Exteriores imbricates. All these sediments were subsequently deformed since Middle Eocene times as deformations progressed forwards and the Gavarnie-Sierras Marginals thrust sheets developed and all the sub-basins shallowed upwards into the Upper Eocene-Oligocene synorogenic continental sediments. The aim of this paper is to describe the geological evolution of the fold and thrust belt and related basins as a framework for the understanding of the petroleum systems.

Abstract Stratigraphic forward models (SFMs) can be used to simulate sedimentary processes describing accommodation, supply and sediment transport to predict architecture, gross depositional environments and sediment partitioning. Within the frame of Shell’s Digital Geology project, and using the DIONISOS model developed by the French Petroleum Institute, SFMs were built for the lowermost composite sequences of the outcropping Middle Eocene Sobrarbe deltaic complex (Ainsa Basin, NE Spain). The deltaic complex is dominated by clastic sediments and localized carbonates, which accumulated in a foreland basin with syndepositional deformation during a greenhouse period. Initial modelling input parameters were based on outcrop and regional information. Afterwards, these were fine-tuned to ensure that the base case model approximates the large-scale architecture and gross depositional environments observed in the outcrops. Average sediment supply in the base case model is consistent with estimates from potential drainage areas. The model allows quantifying sediment partitioning through gross depositional environments in space and time. Delta plain accumulates during periods with rising base level yielding aggradation-dominated geometries (corresponding to the transgressive systems tract (TST) and highstand systems tract (HST). Delta front accumulates mostly during small rises to falls in relative base level, yielding progradation-dominated geometries (forced regressive wedge systems tract (FRW) and lowstand systems tract (LST)). Carbonates accumulate mostly arround TST/HST transitions. Analysis of the resultant stratigraphic architecture considering alternative scenarios of eustasy, sediment supply or subsidence provides insights into the main controls. In addition to Milankovitch-related base-level fluctuations, temporal variations in base level or supply are needed to successfully mimic the architecture observed in the outcrops. Progradation distance for the first sequence in the deltaic complex is strongly controlled by sediment supply and initial bathymetry, and less dependent on subsidence. However, subsidence and sediment supply control long-term stacking patterns. Input parameters used for the Sobrarbe deltaic complex provide constraints that can be adapted to model similar subsurface settings to support reservoir prediction for hydrocarbon exploration or appraisal activities in less constrained settings.

Abstract Stratigraphic forward models (SFMs) can be used to simulate sedimentary processes describing accommodation, supply and sediment transport to predict architecture, gross depositional environments and sediment partitioning. Within the frame of Shell’s Digital Geology project, and using the DIONISOS model developed by the French Petroleum Institute, SFMs were built for the lowermost composite sequences of the outcropping Middle Eocene Sobrarbe deltaic complex (Ainsa Basin, NE Spain). The deltaic complex is dominated by clastic sediments and localized carbonates, which accumulated in a foreland basin with syndepositional deformation during a greenhouse period. Initial modelling input parameters were based on outcrop and regional information. Afterwards, these were fine-tuned to ensure that the base case model approximates the large-scale architecture and gross depositional environments observed in the outcrops. Average sediment supply in the base case model is consistent with estimates from potential drainage areas. The model allows quantifying sediment partitioning through gross depositional environments in space and time. Delta plain accumulates during periods with rising base level yielding aggradation-dominated geometries (corresponding to the transgressive systems tract (TST) and highstand systems tract (HST). Delta front accumulates mostly during small rises to falls in relative base level, yielding progradation-dominated geometries (forced regressive wedge systems tract (FRW) and lowstand systems tract (LST)). Carbonates accumulate mostly arround TST/HST transitions. Analysis of the resultant stratigraphic architecture considering alternative scenarios of eustasy, sediment supply or subsidence provides insights into the main controls. In addition to Milankovitch-related base-level fluctuations, temporal variations in base level or supply are needed to successfully mimic the architecture observed in the outcrops. Progradation distance for the first sequence in the deltaic complex is strongly controlled by sediment supply and initial bathymetry, and less dependent on subsidence. However, subsidence and sediment supply control long-term stacking patterns. Input parameters used for the Sobrarbe deltaic complex provide constraints that can be adapted to model similar subsurface settings to support reservoir prediction for hydrocarbon exploration or appraisal activities in less constrained settings.

Abstract Geometries of reservoir bodies are commonly derived from well-exposed outcrops. The architecture of delta-front mouth-bar deposits (Sobrarbe Formation) was mapped in Northern Spain. Mouth-bar sands were walked out in outcrops, leaving uncertainty of its lateral distribution and reservoir geometries. Two conceptual models (fluvial-dominated and wave-dominated mouth bars) were established to honour lateral and vertical connectivity uncertainties. Rarely, however, models constructed from outcrops are simulated to test the impact of reservoir architecture on flow. Both models closely represent the reservoir architecture mapped in outcrops. An integrated reservoir modelling workflow (4D close-the-loop) was applied resembling the methodology to outcrop-based subsurface reservoirs. It includes model realizations and subsequent flow simulations. To better understand implications on fluid flow like water cut development and initial production rate, the two plausible alternative digital model realizations were simulated and subsequently turned into synthetic seismic models to establish differences between alternative connectivity realizations. Simulations show that the wave-dominated well-connected scenario resulted in a 12% increase in oil production. However, water injection significantly increased ultimate oil recovery for the fluvial-dominated, poorly connected scenario. The work suggests economically relevant uncertainty cannot be eliminated even in well-constrained data sets that can be walked out in outcrop. Thus, the construction of alternative plausible realizations is a robust workflow to approximate reservoir geology leading to sound economic decision-making on a subsurface project. Abstract The Sobrarbe deltaic complex (SDC), located in the Ainsa Basin in the southern Pyrenean foreland basin, constitutes a world-class outcrop analogue for mixed siliciclastic and carbonate deltaic deposits. Generating a seismic model from these outcrops helps to assess the sensitivity of seismic data to sedimentological and stratigraphic variations in mixed deltaic systems. To develop a synthetic seismic model, the Sobrarbe Formation was analysed petrographically and divided into nine facies types. Samples from outcrops were examined to determine the petrophysical characteristics of each facies. The petrophysical characteristics and facies types were incorporated in a two-dimensional digital outcrop model, which allowed for the construction of a synthetic seismic profile. The reflection patterns observed in the seismic profile can be perfectly correlated to the digital outcrop model for frequencies ranging between 200 and 400 Hz. However, at lower frequencies (25 to 100 Hz), and hence longer seismic wave length, only the major depositional changes appear. Although each of the facies has a unique seismic expression, a direct correlation between the digital outcrop model and the synthetic seismic model remains challenging. At lower frequencies (15– 50 Hz) and hence longer seismic wavelength, only large-scale depositional changes can be resolved. In addition, the mixed nature of the sediment supply complicates the visualization of the facies in the synthetic seismic profile. The petrophysical models based on single frequencies clearly show that the minimum seismic resolution needed to reveal depositional changes varies between 50 and 100 Hz within this mixed siliciclastic and carbonate deltaic system. This is below the 10 kHz frequencies used during geotechnical and engineering acquisition aiming at the first 100 m below the sea floor, shallow geohazard characterization of the upper 500 m deploying frequencies within the 1 kHz range, but above the typical hydrocarbon exploration for deeper targets with frequencies above 100 kHz, typically with most of the energy around 10 kHz.

Abstract Geometries of reservoir bodies are commonly derived from well-exposed outcrops. The architecture of delta-front mouth-bar deposits (Sobrarbe Formation) was mapped in Northern Spain. Mouth-bar sands were walked out in outcrops, leaving uncertainty of its lateral distribution and reservoir geometries. Two conceptual models (fluvial-dominated and wave-dominated mouth bars) were established to honour lateral and vertical connectivity uncertainties. Rarely, however, models constructed from outcrops are simulated to test the impact of reservoir architecture on flow. Both models closely represent the reservoir architecture mapped in outcrops. An integrated reservoir modelling workflow (4D close-the-loop) was applied resembling the methodology to outcrop-based subsurface reservoirs. It includes model realizations and subsequent flow simulations. To better understand implications on fluid flow like water cut development and initial production rate, the two plausible alternative digital model realizations were simulated and subsequently turned into synthetic seismic models to establish differences between alternative connectivity realizations. Simulations show that the wave-dominated well-connected scenario resulted in a 12% increase in oil production. However, water injection significantly increased ultimate oil recovery for the fluvial-dominated, poorly connected scenario. The work suggests economically relevant uncertainty cannot be eliminated even in well-constrained data sets that can be walked out in outcrop. Thus, the construction of alternative plausible realizations is a robust workflow to approximate reservoir geology leading to sound economic decision-making on a subsurface project.

Abstract The Sobrarbe deltaic complex (SDC), located in the Ainsa Basin in the southern Pyrenean foreland basin, constitutes a world-class outcrop analogue for mixed siliciclastic and carbonate deltaic deposits. Generating a seismic model from these outcrops helps to assess the sensitivity of seismic data to sedimentological and stratigraphic variations in mixed deltaic systems. To develop a synthetic seismic model, the Sobrarbe Formation was analysed petrographically and divided into nine facies types. Samples from outcrops were examined to determine the petrophysical characteristics of each facies. The petrophysical characteristics and facies types were incorporated in a two-dimensional digital outcrop model, which allowed for the construction of a synthetic seismic profile. The reflection patterns observed in the seismic profile can be perfectly correlated to the digital outcrop model for frequencies ranging between 200 and 400 Hz. However, at lower frequencies (25 to 100 Hz), and hence longer seismic wave length, only the major depositional changes appear. Although each of the facies has a unique seismic expression, a direct correlation between the digital outcrop model and the synthetic seismic model remains challenging. At lower frequencies (15– 50 Hz) and hence longer seismic wavelength, only large-scale depositional changes can be resolved. In addition, the mixed nature of the sediment supply complicates the visualization of the facies in the synthetic seismic profile. The petrophysical models based on single frequencies clearly show that the minimum seismic resolution needed to reveal depositional changes varies between 50 and 100 Hz within this mixed siliciclastic and carbonate deltaic system. This is below the 10 kHz frequencies used during geotechnical and engineering acquisition aiming at the first 100 m below the sea floor, shallow geohazard characterization of the upper 500 m deploying frequencies within the 1 kHz range, but above the typical hydrocarbon exploration for deeper targets with frequencies above 100 kHz, typically with most of the energy around 10 kHz.

Abstract Behind-outcrop research drilling through a tongue of the Sobrarbe deltaic complex of the Ainsa thrust-top basin, southern Spanish Pyrenees, yielded 185.5 m of high-quality core. Detailed lithologic and textural description of the core slabs allowed a detailed understanding of sedimentation processes of a fluvially dominated prograding delta. Prodelta sedimentation covered a mid-Eocene carbonate platform by pulsed carbonate-siliciclastic shaly and silty debris flows that grade upsection into high-density “slurry flow” deposits. These grade into variably bioturbated, thick- to thin-bedded sand-dominated sediments of the distal delta front. An erosive contact marks the base of overlying proximal delta-front sandstone, composed of bioturbated, matrix-poor, cross-bedded sandstones, in turn overlain by sandy-gravelly fluvial-channel and sandy-silty delta plain facies associations. Thin-section petrography documents a dominant carbonate provenance of the sandstone framework grains, initially by matrix-rich marly sediments, later by far-travelled carbonate grains. Moderate siliciclastic contributions, common rip-up clasts and various types of organic matter modify the composition. The core is fully carbonate cemented; porosity and permeability are low throughout. The core compares well to the adjacent outcrop section although differences in unit thicknesses suggest a highly localized sedimentation pattern.

Abstract Behind-outcrop research drilling through a tongue of the Sobrarbe deltaic complex of the Ainsa thrust-top basin, southern Spanish Pyrenees, yielded 185.5 m of high-quality core. Detailed lithologic and textural description of the core slabs allowed a detailed understanding of sedimentation processes of a fluvially dominated prograding delta. Prodelta sedimentation covered a mid-Eocene carbonate platform by pulsed carbonate-siliciclastic shaly and silty debris flows that grade upsection into high-density “slurry flow” deposits. These grade into variably bioturbated, thick- to thin-bedded sand-dominated sediments of the distal delta front. An erosive contact marks the base of overlying proximal delta-front sandstone, composed of bioturbated, matrix-poor, cross-bedded sandstones, in turn overlain by sandy-gravelly fluvial-channel and sandy-silty delta plain facies associations. Thin-section petrography documents a dominant carbonate provenance of the sandstone framework grains, initially by matrix-rich marly sediments, later by far-travelled carbonate grains. Moderate siliciclastic contributions, common rip-up clasts and various types of organic matter modify the composition. The core is fully carbonate cemented; porosity and permeability are low throughout. The core compares well to the adjacent outcrop section although differences in unit thicknesses suggest a highly localized sedimentation pattern.

Abstract Quantitative lithofacies characterization and prediction of reservoir properties is challenging on the scale of individual grid blocks (voxels) of geocellular models. To better understand variability of petrophysical properties on this scale, this study links geological features and petrophysical properties based on high-resolution characterization and innovative analysis methods on grain and bed scale. Samples from two commonly occurring clastic depositional systems were investigated: i) a siliciclastic fluvial channel and ii) a carbonate ramp. Of these 2 depositional systems, a total of 7 subenvironments were sampled. The fluvial channel system is stratigraphically part of the Triassic Lower Bunter Formation in SW-Germany. The formation consists of sandstone interbedded with shale. Three rock slabs, each representing a subenvironment, were investigated: 1. channel base, 2. midchannel bar and 3. marginal sand bar. The carbonate ramp samples belong stratigraphically to the Triassic Upper Muschelkalk Formation, also in SW-Germany. The formation consists of limestone, dolomite, and marl. Carbonate samples represent the following subenvironments: 4. lagoon, 5. tidal flat, 6. shoal and 7. foreshoal. Investigated were rock slabs measuring 50x50 cm (sandstone) and 100x30 cm (carbonates). Up to 145 core plugs measuring 2,45x4 cm were drilled out of each slab. Geological properties measured in detail include grain size and sorting as well as sedimentological attributes of individual lithofacies as indicator for hydrodynamic flow conditions during time of deposition. Pore systems of sediment samples were investigated using thin sections and scanning electron microscope (SEM). Petrophysical properties analysed include effective He-porosity, apparent permeability measured in 3D, intrinsic permeability, ultrasonic p-wave and s-wave velocity, as well as resistivity. The resulting database contains almost 1,000 samples and over 10,000 measurements. The data were used to construct uni- as well as multivariate geostatistics. These include distribution analyses, experimental variogram and principal component analyses. Data were visualized as scatter-, bar-, bi- and box-whisker plots to investigate relationships between geological and petrophysical properties. Moreover, petrophysical core plug measurements were superimposed as “bubble plots” on to each slab with its interpreted lithofacies to avoid statistical data bias. At least simple kriging is introduced to spatially interpolate the readings. Results show that petrophysical properties show large variability between slabs (= dm to m scale) that represent distinct subenvironments. However, a large variability is also observed on the scale of individual plug measurements (= cm scale) within each slab composed of distinct lithofacies. Spatial heterogeneities do not exclusively coincide with depositional surfaces (bedding planes, erosive surfaces) but with the textural framework. Both reflect changes in energy conditions during time of deposition. Hence, the definition of a depositional subenvironment of a rock slab (grid block) or a lithofacies type for similar beds may only partially capture the heterogeneities observed. In general, it is crucial to map major bounding surfaces as well as trends within them to serve as proxy for hydrodynamic energy during deposition. With that information, it is possible to partition rocks into areas of similar petrophysical properties and better understand variability as an input to enhance interpolation at grid block scale.

Abstract Quantitative lithofacies characterization and prediction of reservoir properties is challenging on the scale of individual grid blocks (voxels) of geocellular models. To better understand variability of petrophysical properties on this scale, this study links geological features and petrophysical properties based on high-resolution characterization and innovative analysis methods on grain and bed scale. Samples from two commonly occurring clastic depositional systems were investigated: i) a siliciclastic fluvial channel and ii) a carbonate ramp. Of these 2 depositional systems, a total of 7 subenvironments were sampled. The fluvial channel system is stratigraphically part of the Triassic Lower Bunter Formation in SW-Germany. The formation consists of sandstone interbedded with shale. Three rock slabs, each representing a subenvironment, were investigated: 1. channel base, 2. midchannel bar and 3. marginal sand bar. The carbonate ramp samples belong stratigraphically to the Triassic Upper Muschelkalk Formation, also in SW-Germany. The formation consists of limestone, dolomite, and marl. Carbonate samples represent the following subenvironments: 4. lagoon, 5. tidal flat, 6. shoal and 7. foreshoal. Investigated were rock slabs measuring 50x50 cm (sandstone) and 100x30 cm (carbonates). Up to 145 core plugs measuring 2,45x4 cm were drilled out of each slab. Geological properties measured in detail include grain size and sorting as well as sedimentological attributes of individual lithofacies as indicator for hydrodynamic flow conditions during time of deposition. Pore systems of sediment samples were investigated using thin sections and scanning electron microscope (SEM). Petrophysical properties analysed include effective He-porosity, apparent permeability measured in 3D, intrinsic permeability, ultrasonic p-wave and s-wave velocity, as well as resistivity. The resulting database contains almost 1,000 samples and over 10,000 measurements. The data were used to construct uni- as well as multivariate geostatistics. These include distribution analyses, experimental variogram and principal component analyses. Data were visualized as scatter-, bar-, bi- and box-whisker plots to investigate relationships between geological and petrophysical properties. Moreover, petrophysical core plug measurements were superimposed as “bubble plots” on to each slab with its interpreted lithofacies to avoid statistical data bias. At least simple kriging is introduced to spatially interpolate the readings. Results show that petrophysical properties show large variability between slabs (= dm to m scale) that represent distinct subenvironments. However, a large variability is also observed on the scale of individual plug measurements (= cm scale) within each slab composed of distinct lithofacies. Spatial heterogeneities do not exclusively coincide with depositional surfaces (bedding planes, erosive surfaces) but with the textural framework. Both reflect changes in energy conditions during time of deposition. Hence, the definition of a depositional subenvironment of a rock slab (grid block) or a lithofacies type for similar beds may only partially capture the heterogeneities observed. In general, it is crucial to map major bounding surfaces as well as trends within them to serve as proxy for hydrodynamic energy during deposition. With that information, it is possible to partition rocks into areas of similar petrophysical properties and better understand variability as an input to enhance interpolation at grid block scale.

Abstract The Middle Triassic Upper Muschelkalk deposits of Central Europe form an excellent, laboratory-scale outcrop analogue for subsurface carbonate reservoirs. Due to the burial history of the Muschelkalk Basin, that is, low subsidence rate and lack of significant overburden, it is one of the few areas where close to original reservoir properties, similar to ones observed in conventional subsurface hydrocarbon reservoirs, can be studied in outcrop. This study provides a detailed sedimentological analysis at basin to microscale within a well-constrained bio- and sequence-stratigraphic framework. It aims at extracting hierarchical, multiscale analysis of epicontinental carbonates based on detailed facies and 1D sequence-stratigraphic analysis and integrated 3D facies models. Investigations cover outcrops and cores drilled in the southern part of the Germanic Basin of Luxembourg, eastern France, northern Switzerland and south-western Germany. The Upper Muschelkalk consists of twenty-one lithofacies types (LFTs), which in turn are grouped into eight distinct lithofacies associations (LFAs) encompassing coastal sabkha, peritidal, moderate and low energy backshoal, shoal, shoal fringe, foreshoal to offshoal environments. Reservoir characterization of the Upper Muschelkalk data using MICP measurements and calculated capillary entry pressures of their pore systems suggest that there is no direct link between depositional facies and reservoir quality, that is, pore-throat size and porosity/permeability measurements, a fact that makes the analysis of many subsurface carbonate reservoirs challenging. This is due to the fact that simple poroperm transforms often used in clastic reservoirs for 3D prediction and modelling purposes cannot be applied in the same way to model permeability in carbonates because of additional features such as a complex diagenesis or fracturing. The fact that in the subsurface permeability can only be reliably measured on sparsely available core data increases the challenge of predicting the spatial distribution of permeability. To overcome this challenge, a reservoir rock-type scheme based on capillary entry pressure is presented. Best reservoir properties are identified in barrier shoals, peritidal beach ridges or channels and peritidal algal boundstones LFTs. Integrated 3D facies models of the eastern basin margin show land-stepping facies (retrogradation) with patchy isolated shoal bodies in the transgressive hemisequence and basin-stepping facies (progradation) with well-connected large shoals within the regressive hemisequence.

Abstract The Middle Triassic Upper Muschelkalk deposits of Central Europe form an excellent, laboratory-scale outcrop analogue for subsurface carbonate reservoirs. Due to the burial history of the Muschelkalk Basin, that is, low subsidence rate and lack of significant overburden, it is one of the few areas where close to original reservoir properties, similar to ones observed in conventional subsurface hydrocarbon reservoirs, can be studied in outcrop. This study provides a detailed sedimentological analysis at basin to microscale within a well-constrained bio- and sequence-stratigraphic framework. It aims at extracting hierarchical, multiscale analysis of epicontinental carbonates based on detailed facies and 1D sequence-stratigraphic analysis and integrated 3D facies models. Investigations cover outcrops and cores drilled in the southern part of the Germanic Basin of Luxembourg, eastern France, northern Switzerland and south-western Germany. The Upper Muschelkalk consists of twenty-one lithofacies types (LFTs), which in turn are grouped into eight distinct lithofacies associations (LFAs) encompassing coastal sabkha, peritidal, moderate and low energy backshoal, shoal, shoal fringe, foreshoal to offshoal environments. Reservoir characterization of the Upper Muschelkalk data using MICP measurements and calculated capillary entry pressures of their pore systems suggest that there is no direct link between depositional facies and reservoir quality, that is, pore-throat size and porosity/permeability measurements, a fact that makes the analysis of many subsurface carbonate reservoirs challenging. This is due to the fact that simple poroperm transforms often used in clastic reservoirs for 3D prediction and modelling purposes cannot be applied in the same way to model permeability in carbonates because of additional features such as a complex diagenesis or fracturing. The fact that in the subsurface permeability can only be reliably measured on sparsely available core data increases the challenge of predicting the spatial distribution of permeability. To overcome this challenge, a reservoir rock-type scheme based on capillary entry pressure is presented. Best reservoir properties are identified in barrier shoals, peritidal beach ridges or channels and peritidal algal boundstones LFTs. Integrated 3D facies models of the eastern basin margin show land-stepping facies (retrogradation) with patchy isolated shoal bodies in the transgressive hemisequence and basin-stepping facies (progradation) with well-connected large shoals within the regressive hemisequence.

Abstract Getting exposure to a large variety of geological outcrops via fieldtrips is an essential part of training for geoscientists and petroleum engineers in the upstream industry and beyond. However, increasing cost pressure and associated safety exposure related to such learning events, often in remote areas, require a fresh look into possible new ways of working. Digitalization and visualization technologies create such new opportunities providing virtual access to geological fieldtrips for large communities of subsurface professionals. The main objective of these fieldtrips remains to offer the participants required geological insights into petroleum systems and reservoir architecture. The virtual access to geological outcrops allows to do this where and when the learners need it. Moreover, relevant geological outcrops from different geographical areas can easily be combined further upgrading the quality of the (virtual) geological field trip. In Shell, the virtualization of geological fieldtrips links to a broader digitalization drive. Significant progress has been made in the last few years in the digitalization of learning material and, more importantly, in the way learning is offered. A large part of the face-to-face subsurface learning portfolio has been migrated into virtual equivalents. The concept of learning nuggets, which are bite-sized learning activities, has been introduced and integrated into a knowledge management (KM) set-up, which is connected to a network of technical experts within the company. Learning nuggets are searchable within the knowledge management environment and shareable, enabling effective access when and where needed. This paper presents a summary of current activities around virtual geological outcrops and fieldtrips, as well as ideas on how this may further develop in the future. Key roles are assigned to evolving technologies like augmented and mixed reality techniques, as well as artificial intelligence technologies.

This volume documents part of the Shell Digital Geology project that has demonstrated how you can use digitalisation and its many flavours to your benefit for subsurface characterisation. Conveying complex geological concepts, business workflows used in Exploration, Development and Production and their links to decision-making has never been more transparent and easier to explain than via the Digital Geology exhibition and its associated learning nuggets. The novel set-up allows communicating to a wide range of audiences in an interactive and exciting way how geoscientists and engineers are dealing with developing an understanding of the subsurface and how such knowledge is used in the life cycle of subsurface projects. Therefore, the concepts behind Digital Geology can be applied in many ways, be it for hydrocarbon exploration and development, carbon capture and sequestration, geothermal energy or water resource management. A deep knowledge of the subsurface geology is key for the success of our societies. To communicate this within them and within the geoscience and engineering communities will be equally important when it comes to providing future solutions for the energy transition. This transition will only work if we manage to translate workflows initially developed for hydrocarbons, and presented in this book, seamlessly into next-generation, decentralized energy solutions. Such will involve hydrogen storage, sequestration of green house gases as well as shallow and deep geothermal resources – our next challenge.

Hydrocarbons (petroleum and gas) result from the transformation of organic matter within sedimentary rocks. Three conditions are necessary for an hydrocarbon accumulation to be formed: the presence of a source rock in which, if present, the organic matter will be transformed; the existence of reservoir rocks in which hydrocarbons will migrate and evolve; the presence of traps in which oil and gas will be accumulated and concentrated. This book covers the spectrum of petroleum geology from the initial sedimentology to the economic aspects of estimations of resources and reserves on a planetary scale. It includes the study of the migration of fluids in the sediment through exploration methods, the exploitation of the accumulations and the typology of oil fields. The book is addressed to master’s degree students, petroleum exploration professionals wanting to update their know-how and knowledge skills.