Heller, John P., SPE, New Mexico Petroleum Recovery Research Center Petroleum Recovery Research Center Lien, Cheng Li, SPE, New Mexico Petroleum Recovery Research Center, Kuntamukkula, Murty S., SPE, New Mexico Petroleum Recovery Research Center Petroleum Recovery Research Center AUGUST 1985
Abstract
At the reservoir temperature and pressure at which CO2 can displace a crude oil with high microscopic-displacement efficiency, its density and compressibility are close to those of the crude oil-and not greatly different from those of water itself. Because of this, the mechanical and chemical characteristics of a high-pressure, CO2-in-water "foam" cannot be assumed to be the same as those of an air/water foam at near-atmospheric pressure. pressure. This paper reports information on the mobility of foamlike dispersions in reservoir rock. The data come both from the recalculation of selected experimental work reported in the literature and from new experiments. An important criterion for these experiments is to eliminate or greatly reduce the influence of fluid compressibility, so as to approximate field conditions in CO2 floods more closely. The core flow experiments performed for this work meet this condition by use of the nonaqueous phase of either liquid CO2 at high pressure, or a light hydrocarbon to simulate dense CO2 in experiments performed at low pressure. We postulate that to be effective in retarding the growth of fingers or other instability patterns in CO2 floods while maintaining a high microscopic displacement efficiency, a foamlike dispersion of dense CO2 in surfactant/water should have the following characteristics. 1. Its aqueous-phase content should be as low as possible, to minimize oil trapping and to permit maximum possible, to minimize oil trapping and to permit maximum contact between CO2 and the crude oil. 2. Its effective mobility in the reservoir rock should be adjustable, by some parameters accessible during its generation, to about that of the oil bank it is expected to form and to displace.
Introduction
Since the classical flow and model experiments, and calculations of the 1950's and 1960's, it has been well known that adverse mobility ratio prevents the attainment of high areal sweep efficiencies in both miscible and immiscible displacements. The mechanism responsible for this is the formation of "fingers" of an unstable displacement front, which leads to early breakthrough and lowered oil production rates. The only apparent remedy is to thicken or to decrease the mobility of the injected fluids. An early suggestion along this line was to use foams to displace the oil. Several dozen papers over the intervening years have studied this idea further in both laboratory and field, and there is general agreement that the method holds great promise for selected plugging or diversion of flow from high-permeability streaks. Although the literature points out that large pressure drops ate required to move foam through porous media, and although this is very promising for mobility control, serious questions remain unresolved for that application. One such problem is that in most of the reported experiments, considerable expansion in volume occurred over the length of the flow system. Thus, it is difficult to separate the effects of the foam's compressibility from its inherent flow-resisting properties. An even more fundamental question concerns the mechanism of foam flow itself and the task of describing it quantitatively. We reject the idea that a useful description can be given in terms of a "foam viscosity" as measured in any standard viscometer. To explain this view, and to justify a more modest description in terms only of measurable quantities, we present a section on the rheological background of the problem. problem. This work is directed specifically toward the development of foamlike dispersions of dense CO2 in aqueous surfactant solutions for use in the control of mobility ratio in CO2 floods. We have searched the literature for applicable information, and have re-examined several studies of foam flow in porous media. In most cases the given results have been recalculated to cast them all into a common form that, it is hoped, offers a basis for calculation of the pressure gradients associated with foam flow in a reservoir. This paper also contains the results of original, steady-state experiments, performed under approximate field conditions and designed to permit the calculation of the mobility of foam-like dispersions of CO2 in reservoir rock. Finally, some general conclusions are drawn concerning the use of such foams for mobility control.
Rheological Background
The concept of "viscosity" to represent the resistance offered by a fluid to continuous deformation under the influence of shearing force has been a cornerstone of classical fluid mechanics and is of paramount importance in engineering practice involving fluid flow. The viscosity of a fluid is given by the ratio of shear stress to the rate of shear and is generally a strong function of temperature and weakly dependent on pressure.
SPEJ
p. 603
Reservoir Characterisation of High-Pressure, High-Temperature Zone of Malay Basin Using Seismic Inversion and Artificial Neural Network Approach
