Pore connectivity is likely one of the most important factors affecting the permeability of reservoir rocks. Furthermore, connectivity effects are not restricted to materials approaching a percolation transition but can continuously and gradually occur in rocks undergoing geological processes such as mechanical and chemical diagenesis. In this study, we compiled sets of published measurements of porosity, permeability and formation factor, performed in samples of unconsolidated granular aggregates, in which connectivity does not change, and in two other materials, sintered glass beads and Fontainebleau sandstone, in which connectivity does change. We compared these data to the predictions of a Kozeny-Carman model of permeability, which does not account for variations in connectivity, and to those of Bernabé et al. (2010, 2011) model, which does [Bernabé Y., Li M., Maineult A. (2010) Permeability and pore connectivity: a new model based on network simulations, J. Geophys. Res. 115, B10203; Bernabé Y., Zamora M., Li M., Maineult A., Tang Y.B. (2011) Pore connectivity, permeability and electrical formation factor: a new model and comparison to experimental data, J. Geophys. Res. 116, B11204]. Both models agreed equally well with experimental data obtained in unconsolidated granular media. But, in the other materials, especially in the low porosity samples that had undergone the greatest amount of sintering or diagenesis, only Bernabé et al. model matched the experimental data satisfactorily. In comparison, predictions of the Kozeny-Carman model differed by orders of magnitude. The advantage of the Bernabé et al. model was its ability to account for a continuous, gradual reduction in pore connectivity during sintering or diagenesis. Although we can only speculate at this juncture about the mechanisms responsible for the connectivity reduction, we propose two possible mechanisms, likely to be active at different stages of sintering and diagenesis, and thus allowing the gradual evolution observed experimentally.
In this paper, we modelled the electrical transport behaviour of bimodal carbonate rocks from a reservoir in China using dual-pore networks. One basic assumption, generally supported by experimental data and microstructure observations in the reservoir samples, was that the low porosity, monomodal rocks had the same properties and structure as the microporous matrix of the high porosity, bimodal samples. We assumed that the matrix was homogeneous and always interconnected but that the connectivity and the pore size distribution of macropore system was randomly variable. Both pore systems were supposed to act locally as 'in parallel' electrical conductors, an approach previously used by Bauer et al. Hence, the effect of matrix properties, macropore size distribution and connectivity on electrical properties of bimodal rocks could be modelled and investigated. We simulated electrical current through 3-D, simple cubic and body-centred cubic networks with different coordination numbers, different pipe radius distributions of macropore system and different matrix properties. The main result was that the formation factor of dual-pore network obeyed a 'universal' scaling relationship (i.e. independent of lattice type). Based on this result, we extended the power-law model derived by Bernabé et al. for monomodal porous media. We developed methods for evaluating the scale-invariant pore structure parameters in the model using conventional core analysis and satisfactorily tested the proposed model against experimental data from the Chinese reservoir as well as some other previously published data sets.
Flooding tests often reveal a crossover zone between the capillary and viscous fingering zones, which can have adverse effects on displacement efficiency. While previous studies have leveraged phase diagrams to investigate the effects of viscosity ratio and wettability on the crossover zone, the influence of rock heterogeneity has not yet been examined. Here, we constructed a pore network model for simulating water flooding incorporating multiple orders of magnitude of injection velocity and various heterogeneity levels, while considering fluid compressibility. Based on the simulation results, we quantify the crossover zone as a function of the characteristic front flow rate‾q*cff. We observed that the pressure at the injection end increases as the porous media heterogeneity increases, resulting in lower saturation and a higher‾q*cff, leading to a wider range of the crossover zone. Our findings have practical implications in the fields of geophysics and engineering applications, where optimizing displacement efficiency is critical.
CO2 flooding is considered as one of the most effective enhanced oil recovery (EOR) methods in lowpermeability reservoirs.In our work, we studied CO2 miscible/immiscible flooding in low-permeability sandstones, using nuclear magnetic resonance (NMR) and volume of fluid (VOF) method.The experimental results indicated that the oil recovery after CO2 miscible flooding is 68.13%, which is twice as much as the one after CO2 immiscible flooding; oil in large pores is mainly displaced in the process of CO2 immiscible flooding, whereas in the case of CO2 miscible flooding, the oil comes from all kinds of pores.On the basis of VOF simulation results, it was fond that oil recovery after CO2 miscible flooding is also two times the one after CO2 immiscible flooding, which are dependent on the characteristic of CO2-oil contact.Moreover, oil recovery of CO2 miscible/immiscible flooding significantly decreased with the increase of oil viscosity.The interesting observation is that piston displacement happened at the injection part and finger displacement did at the production part during CO2 miscible flooding.In the end, we found that CO2 storage rate of miscible flooding is higher than that of immiscible flooding, and CO2 storage rate also significantly decreased with the increase of oil viscosity.
The pore structure characteristic parameters of vuggy carbonate reservoirs were extracted, and matrix resistivity of vuggy reservoir was calculated by the percolation network simulation. A segmented cross-scale resistivity calculation method was established, in which the finite element method was used to simulate the resistivity of vuggy reservoirs. The mathematical models of vug porosity and water saturation with rock resistivity in vuggy carbonate reservoir were established, and the relationships between them were obtained. Experimental results verified the reliability of the simulation results. The method presented provides new technical means and research method for the resistivity log interpretation of vuggy carbonate reservoirs. The matrix porosity, vug porosity and matrix pore water saturation are the key factors determining the resistivity of reservoir rocks.
Abstract Fluid flow through geological formations is often concentrated on distinct preferential flow paths owing to the presence of fractures or large‐scale permeability structures. However, the existence of such structures is not a mandatory condition of preferential paths formation. Pore‐scale spatial fluctuations of pore size and/or pore connectivity in statistically stationary porous media, if sufficiently large, can also lead to the concentration of fluid flow on distinct pathways. In this paper, we attempted to establish the conditions of formation of preferential flow paths in heterogeneous porous media in terms of pore‐size heterogeneity and pore connectivity. We simulated steady‐state flow through stochastically constructed two‐ and three‐dimensional pore networks, in which the width of the pore radius distribution and the pore coordination number (a measure of pore connectivity) were varied. We developed new techniques based on graph theory to identify potential preferential flow paths and characterize them. We observed a gradual transition from approximately uniform flow fields in low heterogeneity/high connectivity networks to flow localization on preferential paths with increasing pore‐size heterogeneity and decreasing connectivity. The transition occurred at lower heterogeneity levels in three‐dimensional than in two‐dimensional simulations and was less influenced by pore connectivity variations. These results were summarized in a phase diagram in pore‐size heterogeneity/pore connectivity parameter space, which we found consistent with relevant real rocks data.
Dynamic network model, validated by comparing with the previous studies, is presented for investigating pore-scale displacement and oil recovery in dilute surfactant flooding (DSF), which is an economically enhanced oil recovery (EOR) technology. The objective is to study the effects of water/oil interfacial tension (IFT), injection rate, and oil viscosity on oil recovery in DSF and the corresponding water flooding (WF). The results indicate that oil recovery increased with the reduction of IFT and the increase of the viscosity ratio. Displacement patterns also reveal that relatively large sweep efficiency can be achieved by using DSF.
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