The fossiliferous Eocene carbonate reservoir interval of the offshore Hasdrubal Field has a diagenetic history in which dolomitisation of micrite-rich facies has significantly enhanced reservoir quality. Using published information on the diagenetic evolution, digital textural representations of the limestones and dolostones are created using the Multi-Component Architecture Method (MCAM). This technique allows integration of images at different length scales (e.g., SEM, micro-/nano- XRT) which provide different forms of information about the pre-dolomitisation rock, including textural and compositional factors, and the arrangements of preserved components. These digital representations of the dolostones, together with their now completely overprinted precursor micritic limestones, permit exploration of the impact on porosity and permeability of uncemented, partly cemented and biomoulds Nummulites, their number per unit volume, and their orientation (i.e., uniformly or randomly orientated) allowing investigation of the petrophysical consequences of different distributions, orientations and abundances of the matrix and fossiliferous components. Viable diagenetic pathways, which were identified by thin section analysis as well as data available in the literature, are linked to petrophysical property evolution. In this way MCAM permits investigation of earlier stages of the diagenetic processes which were overprinted by later diagenetic processes.

@en

With the aim of supporting future traffic needs, an account of how to reconstruct an existing cyclic timetable by inserting additional train services will be given in this paper. The Timetable-based Extra Train Services Inserting (TETSI) problem is regarded as an integration of railway scheduling and rescheduling problem. The TETSI problem therefore is considered involving many constraints, such as flexible running times, dwell times, headway and time windows. Characterized based on an event-activity graph, a general Mixed Integer Program model for this problem is formulated. In addition, several extensions to the general model are further proposed. The real-world constraints that concerning the acceleration and deceleration times, priority for overtaking, allowed adjustments, periodic structure and frequency of services are incorporated into the general model. From numerical investigations using data from Shanghai-Hangzhou High-Speed Railway in China, the proposed framework and associated techniques are tested and shown to be effective.@en

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.

@en

Although flow through fractured rocks involves many different length-scales, it is crucial for the prediction of continuum-scale single- and multi-phase flow functions to understand, at the pore-scale, the interaction between the rock matrix and fractures. Here we present a pore-network extraction method in which the pore diameters and fracture apertures are of similar size. The method involves a shrinking algorithm to extract a hybrid skeleton of medial axes and surfaces, and it includes a workflow to convert the medial surfaces of fractures into dense networks of virtual medial axes, allowing generation of an integrated pore-network for the entire pore space. Appropriate single- and two-phase flow properties are assigned to network elements representing the fractures. We validate the method via comparisons between pore network flow simulations and an analytical solution, direct flow simulations and experimental observations. The network calculations are several orders of magnitude faster than the direct simulations.@en

Carbonate reservoirs contain more than half of the world's remaining petroleum reserves and are increasingly becoming targets for water-alternating-gas (WAG) flooding as secondary or tertiary recovery. Heterogeneity in carbonate reservoirs spans from pore- to reservoir-scale. This is exacerbated by the presence of natural fractures and post-depositional dissolution. Furthermore, carbonate reservoirs tend to have variable wettability that impacts fluid flow which adds to reservoir uncertainty and renders managing WAG floods difficult. In this work, we examine the effect of rock and wettability heterogeneity on recovery profiles in naturally fractured carbonate reservoirs (NFCR). To simulate WAG flooding in NFCR with arbitrary wettability, we use saturation functions derived from a state-of-the-art pore network model to preserve multi-scale heterogeneities at the pore-scale. We study the interplay of capillary, gravity and viscous forces at an intermediate scale, then simulate WAG flooding in the presence of fractures in a heterogeneous carbonate ramp outcrop model. Adding the permeability and wettability heterogeneities impacts ultimate recoveries during water injection cycles by up to 6% and 14% absolute, respectively. Both heterogeneities affect the speed of recovery during gas injection cycles. Depending on its relation to permeability distribution, non-uniform wettability of matrix blocks can have a substantial impact on recovery during water injection cycles while recovery efficiency during the gas injection cycle can be reduced by a factor of 50%. Our work identifies the key factors that must be considered when modelling WAG floods in NFCR. We evaluate the reliability of conventional dual-porosity/dual- permeability numerical simulation approaches for NFCR by comparing results with multi-stage upscaled models through which we capture the fundamental controls on multi-phase flow. Hence, we can offer explanations for possible NFCR responses to WAG flooding and novel ways to improve the predictive ability of field-scale numerical simulation models.@en

The application of high resolution x-ray computed tomography in conjunction with x-ray transparent core holders and representative volumes of porous carbonate media enable exceptionally high quality imaging of fluid displacement processes. The experiments show that the rock is water wet. This in turn is in agreement with what was expected prior to running the experiments since the rock was a clean outcrop and has never been exposed to hydrocarbon phases. Moreover, major fluid displacement mechanisms being used in pore scale simulations including piston like displacement and snap off have been captured clearly. The experiments have characterized the transport features and the structure of residual oil present in a water wet system. Subsequent experiments will focus on wettability alteration to develop oil wet surfaces for direct comparison. The on-going phase of this study will focus on building multiple scale network models and using them to run fluid displacement simulations. These models will be validated against experimental data such as MICP and relative permeability measurements.

@en

Porosity and permeability of carbonate sediments evolve markedly with burial depth, reflecting the combined effects of mechanical compaction, chemical compaction, dissolution and cementation. While trends in porosity change with depth can be qualified, the evolution of permeability remains problematic. Here, we create a theoretical series of 2D images of major pore-occluding and pore enhancing diagenetic processes linked to their depth of occurrence. These images were then used to create 3D pore architecture models using Markov Chain Monte Carlo simulation, from which pore network were extracted to obtain multiphase fluid flow properties. The modelled porosity and permeability evolution from three different diagenetic pathways display several tipping points where the decrease in permeability is significantly larger than the associated drop in porosity. Such diagenetic pathway models can provide constraints on the predicted behaviour of carbonates during burial and/or uplift scenarios.

@en

Carbonate reservoirs have textural heterogeneities at all length-scales (triple porosity pore-vug-fracture) and tend to be mixed- to oil-wet The choice of an enhanced oil recovery process and the prediction of oil recovery require a sound understanding of the fundamental controls on fluid flow in mixed- to oil-wet carbonate rocks, as well as physically robust flow functions, i e relative permeability and capillary pressure functions Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during water-alternating-gas injection (WAG) We have recently developed a method for integration of pore-networks derived from micro CT images at different length-scales, thus capturing pore structures from different types of porosity The network integration method honours the connectivity between different pore types, including micro-fractures, and their spatial distribution In this work, we use these multi-scale networks as input for our three-phase flow pore-network model, which comprises a novel thermodynamic criterion for formation and collapse of oil layers that strongly depends on the fluid spreading behaviour and the rock wettability The criterion affects in particular the oil relative permeability at low oil saturations and the accurate prediction of residual oil saturations We generate three-phase flow functions for gas injection and WAG from networks with carbonate pore geometries and connectivities and we demonstrate the impact on residual saturations of the different types of porosity and the interaction with different realistic wettability scenarios We also show that the network generated three-phase flow relative permeabilities are distinctly different from traditional models, such as Stone's The flow functions will be used in a heterogeneous carbonate reservoir model and to demonstrate their impact on the sweep efficiency.@en