James W. Jennings

Simultaneous Determination of Capillary Pressure and Relative Permeability by Automatic History Matching

This paper presents a new method for the simultaneous determination of capillary pressure and relative permeability that is a modification of the porous-plate capillary pressure experiment. The modifications involve the use of thin core samples and thin plastic filtration membranes, resulting in a significantly faster experiment. Relative permeabilities are determined from the experimental data by the use of an automatic history-matching simulator. The new method is found to be particularly well suited for the measurement of small oil relative permeabilities in gas/oil systems.

A preliminary computational investigation of a macro-model for vuggy porous media

A vug is a relatively large void region or cavity in a rock. A vuggy porous medium has many vugs scattered throughout its extent; moreover, these vugs may be interconnected. A Darcy-Stokes system of equations is needed to describe the flow on the micro-scale. Recently a macro-model of flow was derived by mathematical homogenization that provides the effective permeability of a vuggy medium. In this paper we present two computational studies to illustrate and verify this macro-model. In the first study, we illuminate the nature of the effective permeability itself by considering vuggy media with (i) layered vugs (ii) meandering vug channels, (iii) constricted vug channels, and (iv) disconnected vugs. We find that vug connectivity is the most critical variable in predicting macroscopic properties. In the second study, we consider the macro-model. We compare fluid flow in a vuggy medium on the micro-scale to that on the macro-scale. We find support for the macro-model, and again find that vug interconnectivity is the critical variable to preserve in the upscaling process.

Simultaneous Determination of Residual Saturation and Capillary Pressure Curves Utilizing the Ultracentrifuge

Residual saturation and capillary pressure curves are important for modelling reservoir and laboratory processes. Knowledge of the residual saturation curve is necessary to determine the ultimate production from a tertiary recovery process. Capillary pressure is required to interpret laboratory core floods and to describe multi-phase reservoir fluid flow. The ultracentrifuge provides a rapid means of determining capillary pressure and residual saturation relationships. It is non-destructive, uses small samples, and is capable of attaining both high capillary pressures and extremely low residual saturations. The effects of variation in residual saturation with Bond number are not included in the traditional Hassier-Brunner analysis for capillary pressure. Such desaturation effects can explain the anomalous experimental saturation distributions reported at high rotation rates. The current work generalizes the Hassler-Brunner analysis to include desaturation and also to include the variation in centripeta acceleration through the core. The analysis also provides for the determination of residual saturation as a function of Bond number (k..delta..rhog/sigma.

Modeling Coupled Fracture-Matrix Fluid Flow in Geomechanically Simulated Fracture Networks

In conventional reservoir simulations, gridblock permeabilities are frequently assigned values larger than those observed in core measurements to obtain reasonable history matches. Even then, accuracy with regard to some aspects of the performance such as water or gas cuts, breakthrough times, and sweep efficiencies may be inadequate. In some cases, this could be caused by the presence of substantial flow through natural fractures unaccounted for in the simulation. In this paper, we present a numerical investigation into the effects of coupled fracture-matrix fluid flow on equivalent permeability. A fracture-mechanics-based crack-growth simulator, rather than a purely stochastic method, was used to generate fracture networks with realistic clustering, spacing, and fracture lengths dependent on Young’s modulus, the subcritical crack index, the bed thickness, and the tectonic strain. Coupled fracture-matrix fluid-flow simulations of the resulting fracture patterns were performed with a finite-difference simulator to obtain equivalent permeabilities that can be used in a coarse-scale flow simulation. The effects of diagenetic cements completely filling smaller aperture fractures and partially filling larger aperture fractures were also studied. Fractures were represented in finite-difference simulations both explicitly as grid cells and implicitly using nonneighbor connections (NNCs) between grid cells. The results indicate that even though fracture permeability is highly sensitive to fracture aperture, the computed equivalent permeabilities are more sensitive to fracture patterns and connectivity.

ABSTRACT: Modeling Coupled Fracture-Matrix Fluid Flow in Simulated Fracture Patterns

In conventional reservoir simulation, grid block permeabilities must frequently be assigned values systematically larger than justified by core measurements to obtain reasonable history matches. Even then, accuracy with regard to some aspects of reservoir performance such as water or gas cuts, breakthrough times, and sweep efficiencies may be inadequate. Often this discrepancy can be attributed to flow taking place through natural fractures not accounted for in the simulation. We present a numerical investigation into the effects of coupled fracture-matrix fluid flow on effective permeability.