Photon Equivalents as a Parameter for Scaling Photoredox Reactions in Flow: Translation of Photocatalytic C−N Cross‐Coupling from Lab Scale to Multikilogram Scale

With the development of new photocatalytic methods over recent decades, the translation of these chemical reactions to industrial‐production scales using continuous‐flow reactors has become a topic of increasing interest. In this context, we describe our studies toward elucidating an empirically derived parameter for scaling photocatalytic reactions in flow. By evaluating the performance of a photocatalytic C?N cross‐coupling reaction across multiple reactor sizes and geometries, it was demonstrated that expressing product yield as a function of the absorbed photon equivalents provides a predictive, empirical scaling parameter. Through the use of this scaling factor and characterization of the photonic flux within each reactor, the cross‐coupling was scaled successfully from the milligram scale in batch to a multi‐kilogram reaction in flow.     

Modelling Unsaturated Moisture Transport in Heterogeneous Limestone

The influence of macro-scale heterogeneities on the imbibition process is investigated for Savonnières, a French layered limestone. Free uptake experiments are performed both parallel and perpendicular to the bedding. It is found that the position of the different layers, and the exact material properties inside each layer can significantly influence the imbibition process. The experimental results are compared with numerical simulations. For the flow simulations, moisture permeability of the different layers is obtained with the upscaling technique presented in Part 1. Good agreement between simulations and experiments validate the proposed upscaling from meso to macroscopic scale.     

Multi-Stage Upscaling: Selection of Suitable Methods

Reservoirs are often composed of an assortment of rock types giving rise to permeability heterogeneities at a variety of length-scales. To predict fluid flow at the full-field scale, it is necessary to be aware of these different types of heterogeneity, to recognise which are likely to have important effects on fluid flow, and to capture them by upscaling. In fact, we may require a series of stages of upscaling to go from small-scales (mm or cm) to a full-field model. When there are two (or more) phases present, we also need to know how these heterogeneities interact with fluid forces (capillary, viscous and gravity). We discuss how these effects may be taken into account by upscaling. This study focusses on the effects of steady-state upscaling for viscous-dominated floods and tests carried out on a range of 2D models are described. Upscaling errors are shown to be reduced slightly by the increase in numerical dispersion at the coarse scale. We select a combination of three different upscaling methods, and apply this approach to a model of a North Sea oil reservoir in a deep marine environment. Six different genetic units (rock types) were identified, including channel sandstone and inter-bedded sandstone and mudstone. These units were modelled using different approaches, depending on the nature of the heterogeneities. Our results show that the importance of small-scale heterogeneity depends on the large-scale distribution of the rock types. Upscaling may not be worthwhile in sparsely distributed genetic units. However, it is important in the dominant rock type, especially if there is good connectivity through the unit between the injector wells (or aquifer) and the producer wells.This revised version was published online in May 2005. In the previous version one of the authors name was missing.     

Upscaling permeability: Error analysis for renormalization

In this paper we briefly discuss the background to the problems of finding effective flow properties when moving from a detailed representation of reservoir geology to a coarse gridded model required for reservoir performance simulation. The basic requirements for the upscaled properties are also discussed. We then consider one technique, renormalization, that in recent years has shown promise as an accurate, yet fast, method. The mathematical background of the renormalization approach is examined. A rigorous formalism is developed that allows an explicit calculation of the error terms to be made. In a very simple case use of the correction terms is shown to produce a dramatic improvement in accuracy of the method.     

INCORPORATION AND INFLUENCE OF VARIABILITY IN AN AGGREGATED FOREST MODEL

ABSTRACT. Variability influences ecological processes at various scales and is incorporated in different ways in forest models. The forest model Dis CFor M scales an individual based, stochastic forest patch model up to a height structured tree population model. To describe the variability arising from stochastic processes in the patch model, Dis CFor M uses theoretical random dispersions of trees in each height class over all patches. This yields a spatial distribution of light and consequently of light dependent process rates. Three major influences of variability on simulations are examined: site condition, patch to patch, and temporal environmental variability. Simulation studies and comparison with forest compositions from the Swiss National Forest Inventory reveal that these influences affect simulated forest dynamics, species composition, and biodiversity, depending on climatic boundary conditions and hence have to be taken into account in modeling.     

General Anisotropic Effective Medium Theory for the Effective Permeability of Heterogeneous Reservoirs

One of the techniques to calculate the effective property of a heterogeneous medium is the effective medium theory. The present paper presents a general mathematical formulation for the effective medium approximation using a self-consistent choice of the effective permeability, to apply it to the case of a general anisotropic 2D medium and to the case of a 3D isotropic medium with randomly oriented ellipsoidal inclusions. The 2D results are compared with analytical results and with a homogenization technique with good result. The 3D correlations are used to derive percolation thresholds in two-phase systems with a large permeability contrast, which are compared to numerical results from the literature, also with good results.     

Dynamics of the Water–Oil Front for Two-Phase, Immiscible Flow in Heterogeneous Porous Media. 2 – Isotropic Media

We study the evolution of the water–oil front for two-phase, immiscible flow in heterogeneous porous media. Our analysis takes into account the viscous coupling between the pressure field and the saturation map. Although most of previously published stochastic homogenization approaches for upscaling two-phase flow in heterogeneous porous media neglect this viscous coupling, we show that it plays a crucial role in the dynamics of the front. In particular, when the mobility ratio is favorable, it induces a transverse flux that stabilizes the water–oil front, which follows a stationary behavior, at least in a statistical sense. Calculations are based on a double perturbation expansion of equations at first order: the local velocity fluctuation is defined as the sum of a viscous term related to perturbations of the saturation map, on one hand, plus the perturbation induced by the heterogeneity of the permeability field with a base-state saturation map, on the other hand. In this companion paper, we focus on flows in isotropic media. Our results predict the dynamics of the water–oil front for favorable mobility ratios. We show that the statistics of the front reach a stationary limit, as a function of the geostatistics of the permeability field and of the mobility ratio evaluated across the front. Results of numerical experiments and Monte-Carlo analysis confirm our predictions.     

Dual Mesh Method for Upscaling in Waterflood Simulation

Detailed geological models typically contain many more cells than can be accommodated by reservoir simulation due to computer time and memory constraints. However, recovery predictions performed on a coarser upscaled mesh are inevitably less accurate than those performed on the initial fine mesh. Recent studies have shown how to use both coarse and fine mesh information during waterflooding simulations. In this paper, we present an extension of the dual mesh method (Verdière and Guérillot, 1996) which simulates water flooding injection using both the coarse and the original fine mesh information. The pressure field is first calculated on the coarse mesh. This information is used to estimate the pressure field within each coarse cell and then phase saturations are updated on the fine mesh. This method avoids the most time consuming step of reservoir simulation, namely solving for the pressure field on the fine grid. A conventional finite difference IMPES scheme is used considering a two phase fluid with gravity and vertical wells. Two upscaling methodologies are used and compared for averaging the coarse grid properties: geometric average and the pressure solve method. A series of test cases show that the method provides predictions similar to those of full fine grid simulations but using less computer time.     

Numerical investigation of dual-porosity model with transient transfer function based on discrete-fracture model

Based on the characteristics of fractures in naturally fractured reservoir and a discrete-fracture model, a fracture network numerical well test model is developed.Bottom hole pressure response curves and the pressure field are obtained by solving the model equations with the finite-element method. By analyzing bottom hole pressure curves and the fluid flow in the pressure field, seven flow stages can be recognized on the curves. An upscaling method is developed to compare with the dual-porosity model(DPM). The comparisons results show that the DPM overestimates the inter-porosity coefficient λ and the storage factor ω. The analysis results show that fracture conductivity plays a leading role in the fluid flow. Matrix permeability influences the beginning time of flow from the matrix to fractures. Fractures density is another important parameter controlling the flow. The fracture linear flow is hidden under the large fracture density.The pressure propagation is slower in the direction of larger fracture density.