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

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

Basin modelling tools are widely used to predict reservoir charging but, unfortunately, their application to carbonate reservoirs is far from straightforward. For carbonates, the relationships between porosity/ effective stress/depth, must be addressed before a reliable basin model can be produced. We propose using a synthetic diagenesis approach, where Pore Architecture Models (PAMs) are used to generate representative porosity values for the different diagenetic (backstripped) stages that are recognised from cores or thin sections. The synthetic diagenesis approach is then used to inform more conventional basin modelling. The viability of this method is the topic of this contribution.@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

Fractured reservoirs contain around 60% of the world's remaining oil reserves. Fracture corridors have been noticed as a major architectural element in outcrops of fractured rock and are known to affect recovery by providing high-permeability flow conduits. Simulations of fractured reservoirs using multi-porosity and multi-permeability models has proven to be challenging, with ever-changing modifications being proposed since the introduction of the dual porosity model in the 1960s. To increase the reliability of reservoir simulation of fractured reservoirs, we propose a new workflow to represent fractured reservoirs by coupling Discrete Fracture and Matrix (DFM) models for fracture corridor properties (which uses finite element and finite volume methods), and the conventional single porosity simulation(which uses finite difference methods). Relative permeabilities of fracture corridors are upscaled over a single grid block size using DFM models based on an unstructured mesh that accommodates fracture corridor patterns and characteristics. The upscaled relative permeabilities are transferred into a single porosity simulation model to reproduce the behaviour of fractured reservoirs without resorting to the transfer functions. Various fracture patterns and apertures were studied to investigate their impact on flow properties. Also, different multiphase upscaling techniques were investigated based on the dominant driving forces and the type of boundary conditions used in the upscaling process. A performance match was done between two models, a fine-mesh DFM model and a simple coarse single porosity model that uses the upscaled relative permeabilities. The models behaved similarly. Recommendations are derived as to how to use appropriate upscaling methods. The new workflow complements and may even have the potential to eliminate the need for classical dual-porosity models.@en