Estimating the geometry and sedimentary heterogeneities of carbonate platforms is a very challenging task. In recent decades, numerical stratigraphic forward models have been developed to provide a quantitative view of sedimentary processes with the resulting stratigraphic architecture. Although used in many academic and industrial studies, this numerical approach is rarely used in everyday exploration and appraisal workflows. The calibration of these models on available seismic and well data is indeed a challenging and time-consuming process. Here we use the DionisosFlow model to simulate a carbonate platform typical of the Miocene formations observed in Central Luconia, South China Sea. We build a reference simulation or virtual ground truth from literature data, using for instance the Haq et al. (1988) , Laskar et al. (2011) , and Bosscher and Schlager (1992) curves, which prove indications on sea-level variations, orbital parameters, and carbonate production as a function of water depth, respectively. We analyze the sensitivity of the simulation results to the parameters controlling the physical processes: accommodation space creation, carbonate production, and sediment transport. Results show that stratigraphic modeling makes it possible to test the concepts of sequence stratigraphy in a virtual digital world, thus opening the possibility of testing the sensitivity of the different characteristics of a sedimentary system to physical parameters. We also propose an innovative approach to using this stratigraphic modeling in operational cases. The first step is to identify a diachronous geological body such as the carbonate platform sensu stricto, which is easily identifiable using seismic data. A comparison of the geometry of this geological body with the thickness maps derived from the seismic interpretation provides a first regional metric controlling the shape of the studied sedimentary systems. The second step is to validate the simulation results with well data, and, in particular, facies from the log interpretation. The computation of vertical proportion curves (VPC) in the vicinity of wells facilitates understanding the local variability of facies in the digital world as well as in the real world. This second metric, based on a comparison of VPCs, makes it possible to assess sequences and sedimentary heterogeneities and to define much smoother cost functions, thus facilitating the use of automatic optimization algorithms. In conclusion, this work shows that numerical stratigraphic forward modeling is a tool that reproduces stratigraphic concepts using simple physical laws. Through the use of well and seismic metrics adapted to the resolution of the model, use of this numerical approach in daily exploration work to complement the interpretation of seismic and well data provides a quantitative stratigraphic view of the studied area to better access uncertainties and risk in exploration.

ABSTRACT In this chapter we present the results of a 3-D petroleum systems modeling (PSM) project of the deep-water pre-salt region in the Santos Basin. Model building has been based on a large well data set. Simulations have been calibrated against temperature, porosity, and pressure and were compared to data of petroleum properties. The input assumptions are documented in detail, with special focus on two crucial uncertainties in this petroleum province: (1) salt restoration and (2) modeling of the heat flow history, including discussion of technical aspects and workflows. Two different scenarios of the salt restoration, assuming differing amounts of mobile salt over time, were tested. The two scenarios are compared with respect to their impact on thermal modeling results. The heat flow history was modeled based on an application of crustal modeling. Results corroborate the recently published hypothesis that heat flow decline during the early drift phase of the Santos Basin was retarded because of extensive magmatic underplating. The thermal history modeling results reveal that temperatures within the pre-salt sequence have remained largely stagnant since mid-Cretaceous times until present day. Maximum temperatures were accordingly reached in mid-to-Late Cretaceous times in the majority of the area. This is because of the fact that very low burial rates have prevailed since mid-Cretaceous times in this basin, which resulted from its distal setting that could not compensate for the gradual heat flow decline during the drift phase. The temperature history of the pre-salt sequence is additionally affected by the cooling effect of the salt layer, at least on a local scale. The two different scenarios of the salt restoration demonstrate the impact of this effect and show its relevance when assessing maturity via modeling of salt basins. Only the deepest source rock system of the lower Barremian Piçarras Formation, informally called the “talc-stevensite,” shows transformation ratios above 90% (corresponding to the “gas window”). The second and most important source rock system, belonging to the Itapema Formation, informally called the “coquinas” source rock, modeled in the studied area, shows transformation ratios of up to 50%, corresponding to the “oil window.” The third and shallowest source rock system in the model, belonging to the sag mid-to-late Aptian sequence called Barra Velha Formation, is early mature to immature and is not considered to be a significant factor in the oil system of the studied area. The modeled timing of transformation, expulsion, migration, and accumulation in this petroleum system (informally summarized as “charge”) suggests that the main charge pulses from the pre-salt source rock systems took place between mid-Cretaceous and mid-Tertiary times, whereas transformation may have locally been ongoing until present day. Simulations of petroleum migration are not discussed in detail here because of the scope of this study and constraints regarding the volume of this chapter. The preliminary migration model successfully reproduces most known petroleum accumulations in the area, and yielded fair to good fits to measured GOR, and API gravity data. However, the modeled accumulated volumes of several fields, including the Tupi Field, are too small. This suggests that these accumulations possibly received charge from additional pods of source rock located to the south and east, that is, outside of the modeled area.

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.

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.

Abstract Reservoir modelling tools can be invaluable for integrating knowledge and for supporting strategic oil field decisions. The pertinent issue is the capability of the modelling toolbox to achieve the required support: does modelling generate insights into the characterization of the subsurface, does it increase or decrease our working efficiency and does it help or hinder us in decision-making? In this respect, we see two directions emerging in reservoir modelling and simulation. One surrounds software technology development and a move towards a grid-independent world. This is a current research issue but some of the components required to complete a new workflow are already in place and tools for certain specific applications may not be far away. The other involves a change in approach to model design. This involves a move away from big, detailed ‘life-cycle’ models to more nimble workflows involving multi-models (either multi-scale or multi-concept) which may or not include full-field modelling exercises. A distinction between ‘resource models’ and ‘decision models’ helps crystallize this, is a positive step towards achieving ‘fit-for-purpose’ models, and is a change of model design strategy which can be achieved immediately.

Abstract Modern subsurface exploration uses a three-dimensional (3-D) approach to interpret faults and layer boundaries on seismic reflection data. Three-dimensional seismic reflection datasets comprise a continuous volume of reflection samples with a vertical and horizontal resolution, of typically <15 m (c.50 ft). Increasing computer power has allowed the development of interpretation software that allows for direct mapping within an on-screen 3-D representation of the data. The seismic data volume can be processed to emphasize reflections from continuous layers, or to emphasize the discontinuities (e.g., faults) affecting those layers. A key workflow is to build the interpretation of horizons (layer boundaries) and faults into a consistent framework model, where all the stratigraphic and structural surfaces fit together in a geologically realistic way. Such a model is the necessary starting point for structural geological studies and for assessing trap geometry and viability. The framework model also provides the starting geometry for building an engineering model for simulating fluid flow in hydrocarbon reservoirs.

Abstract The introduction reviews topics relevant to the fundamental controls on fluid flow in carbonate reservoirs and to the prediction of reservoir performance. The review provides research and industry contexts for papers in this volume only. A discussion of global context and frameworks emphasizes the value yet to be captured from compare and contrast studies. Multidisciplinary efforts highlight the importance of greater integration of sedimentology, diagenesis and structural geology. Developments in analytical and experimental methods, stimulated by advances in the materials sciences, support new insights into fundamental (pore-scale) processes in carbonate rocks. Subsurface imaging methods relevant to the delineation of heterogeneities in carbonates highlight techniques that serve to decrease the gap between seismically resolvable features and well-scale measurements. Methods to fuse geological information across scales are advancing through multiscale integration and proxies. A surge in computational power over the last two decades has been accompanied by developments in computational methods and algorithms. Developments related to visualization and data interaction support stronger geoscience–engineering collaborations. High-resolution and real-time monitoring of the subsurface are driving novel sensing capabilities and growing interest in data mining and analytics. Together, these offer an exciting opportunity to learn more about the fundamental fluid-flow processes in carbonate reservoirs at the interwell scale.

Abstract This volume highlights key challenges for fluid-flow prediction in carbonate reservoirs, the approaches currently employed to address these challenges and developments in fundamental science and technology. The papers span methods and case studies that highlight workflows and emerging technologies in the fields of geology, geophysics, petrophysics, reservoir modelling and computer science. Topics include: detailed pore-scale studies that explore fundamental processes and applications of imaging and flow modelling at the pore scale; case studies of diagenetic processes with complementary perspectives from reactive transport modelling; novel methods for rock typing; petrophysical studies that investigate the impact of diagenesis and fault-rock properties on acoustic signatures; mechanical modelling and seismic imaging of faults in carbonate rocks; modelling geological influences on seismic anisotropy; novel approaches to geological modelling; methods to represent key geological details in reservoir simulations and advances in computer visualization, analytics and interactions for geoscience and engineering.