Microporosity in carbonate reservoirs is globally pervasive and commonly used to explain high-porosity, low-permeability reservoirs, higher than expected water saturations, low resistivity pay zones and poor sweep efficiency. The potential for micropores to store and produce hydrocarbons has long been recognized, yet limitations on tools to evaluate microporosity has prevented rigorous evaluation. Here we demonstrate a workflow for evaluating microporosity through a combination of laser scanning confocal microscopy (LSCM) and pore network modelling. Specific values for microporosity and permeability calculated in our study should not be applied explicitly, as these are simulated values, but they demonstrate the viability of micropore networks to store and flow hydrocarbons. Carbonate reservoir assessment is critical not only in the petroleum industry, but also for applications in hydrothermal and mineral resources, carbon capture and storage, and groundwater supply. This approach can be applied to understand the potential for any reservoir to hold and transmit fluids.

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Three-dimensional (3-D) printing provides a fast, cost-effective way to produce and replicate complicated designs with minimal flaws and little material waste. Early use of 3-D printing for engineering applications in the petroleum industry has stimulated further adoption by geoscience researchers and educators. Recent progress in geoscience is signified by capabilities that translate digital rock models into 3-D printed rock proxies. With a variety of material and geometric scaling options, 3-D printing of nearidentical rock proxies provides a method to conduct repeatable laboratory experiments without destroying natural rock samples. Rock proxy experiments can potentially validate numerical simulations and complement existing laboratory measurements on changes of rock properties over geologic time scales. A review of published research from academic, government, and industry contributions indicates a growing community of rock proxy experimentalists. Three-dimensional printing techniques are being applied to fundamental research in the areas of multiphase fluid flow and reactive transport, geomechanics, physical properties, geomorphology, and paleontology. Further opportunities for geoscience research are discussed. Applications in education include teaching models of terrains, fossils, and crystals. The integration of digital data sets with 3-D printed geomorphologies supports communication for both societal and technical objectives. Broad benefits that could be realized from centralized 3-D printing facilities are also discussed.

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The relationship between flow properties and chemical reactions is the key to modeling subsurface reactive transport. This study develops closed-form equations to describe the effects of mineral precipitation and dissolution on multi-phase flow properties (capillary pressure and relative permeabilities) of porous media. The model accounts for the fact that precipitation/dissolution only takes place in the water-filled part of pore space. The capillary tube concept was used to connect pore-scale changes to macroscopic hydraulic properties. Precipitation/dissolution induces changes in the pore radii of water-filled pores and consequently in the pore size distribution. The updated pore size distribution is converted back to a new capillary pressure–water saturation relation from which the new relative permeabilities are calculated. Pore network modeling is conducted on a Berea sandstone to validate the new continuum-scale relations. The pore network modeling results are satisfactorily predicted by the new closed-form equations.@en

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.

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A high-resolution three-dimensional (3D) outcrop model of a Jurassic carbonate ramp was used in order to perform a series of detailed and systematic flow simulations. The aim of this study was to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The digital outcrop model contains a wide range of sedimentological, diagenetic and structural features, including discontinuity surfaces, shoal bodies, mud mounds, oyster bioherms and fractures. Flow simulations are performed for numerical well testing and secondary oil recovery. Numerical well testing enables synthetic but systematic pressure responses to be generated for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, owing to the realistic representation of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by subseismic faults and oyster bioherms acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers as the primary control for oil recovery. However, appropriate reservoir-engineering solutions, such as optimizing well placement and injection fluid, can reduce channelling and increase oil recovery.@en

Carbonate reservoirs contain a significant portion of the world's proven hydrocarbon reserves but are challenging to produce due to their complex lithologies, structural heterogeneities, and neutral to oil-wet nature. Increasing recovery requires a better understanding of how different recovery processes respond to the heterogeneities inherent to these reservoirs. This will contribute to the design of appropriate engineering solutions which extend the life of mature fields and develop green fields more effectively. We use a high-resolution 3D outcrop model of a Jurassic carbonate ramp in order to perform a series of detailed and systematic flow simulations. The aim is to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The outcrop analogue model is of excellent quality comprising a wide range of diagenetic and structural features, including discontinuity surfaces, mud mounds, mollusc banks and fractures. Flow simulations are performed for numerical well-testing and secondary oil recovery. Numerical well-testing allows us to generate synthetic but systematic pressure responses for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, due to the high level of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by sub-seismic faults and mollusc banks acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers. This is the primary control for oil recovery. However, appropriate reservoir engineering solutions such as optimising well placement and injection fluid can reduce channelling and increase oil recovery.@en

A joint AAPG-Society of Petroleum Engineers-Society of Exploration Geophysicists Hedberg Research Conference was held in Saint-Cyr sur Mer, France, on July 8 to 13, 2012, to review current research and explore future research directions related to improved production from carbonate reservoirs. Eighty-seven scientists from academia and industry (split roughly equally) attended for five days. A primary objective for the conference was to explore novel connections among different disciplines (primarily within geoscience and reservoir engineering) as a way to define new research opportunities. Research areas represented included carbonate sedimentology and stratigraphy, structural geology, geomechanics, hydrology, reactive transport modeling, seismic imaging (including four-dimensional seismic, tomography, and seismic forward modeling), geologic modeling and forward modeling of geologic processes, petrophysics, statistical methods, numerical methods for simulation, reservoir engineering, pore-scale processes, in-situ flow experiments (e.g., x-ray computed tomography), visualization, and methods for data interaction.@en

Hydrocarbon reservoirs commonly contain an array of fine-scale structures that are below the resolution of seismic images. These features may impact flow behavior and recovery, but their specific impacts may be obscured by the upscaling process for sector and field-scale reservoir simulations. It is therefore important to identify those situations in which subseismic structures can introduce significant departures from full-field flow predictions. Using exposures of Jurassic carbonate outcrops near the village of Amellago in the High Atlas Mountains of Morocco, we have developed a series of flow simulations to explore the interactions of a hierarchical fracture network with the rock matrix of carbonate ramp strata. Model geometries were constructed in CAD software using field interpretations and LiDAR1 data of an outcrop area that is 350 m long by 100 m high. The impact of water injection on oil recovery between an injector and producer pair was investigated. Simulations were performed by a single medium reservoir simulator using a single mesh to represent fracture planes as well as rock-matrix volumes. The effects of changing scenarios for rock permeability and porosity as well as facture permeability distributions were investigated. First-order results show that the best recovery was achieved by a model with a high permeability, homogeneous matrix combined with a heterogeneous fracture network. The worst recovery scenario was given by a model with low, homogeneous permeability and high fracture permeabilities. The results highlight the importance of the permeability contrasts between the matrix and the fractures for overall recovery and the very significant impact that fractures can have on recovery by creating shadow zones and providing critical connections between permeable layers. The presence of the hierarchical fracture network developed strong fingering even in homogeneous matrix cases and evolving velocity patterns reveal competing fluid pathways among matrix and fracture routes. Insights from these models can help to develop production strategies to improve recovery from fractured carbonate reservoirs and provide an initial platform from which to extend further evaluations of different populations of conductive and baffling structures, spatial variations in wettability and capillary pressures and well positions.@en