Sweep Improvement in CO2 Flooding by Use of Foaming Agents

Abstract

Summary. This study has two objectives:to screen and select foaming agents for specific CO2 floods andto determine the effectiveness of foam in improving sweep efficiency in CO2 flooding. Foaming agents were evaluated on their ability to produce ample, lasting foam and to have low loss from adsorption on reservoir rock and decomposition at reservoir conditions. Foaming agents that performed well in shaking, blender, long-term stability, and high-pressure stability tests were selected for core-flow experiments. The stability test results demonstrated that foaming agents are reservoir-specific. The extent of the loss depends on the foaming agent, reservoir fluids, reservoir lithology, and reservoir conditions. The core-flow experiments involved the simultaneous injection of CO2 into two waterflooded Berea cores. The cores were arranged in parallel and had different permeabilities. The test temperature and pressure were constant and above the critical conditions for CO2. Three types of core-flow tests, involving injection of CO2 to displace oil, injection of alternate slugs of CO2 and brine, and injection of foaming agents, were conducted. The foaming agents were injected before CO2 injection and after CO2 had displaced oil from the more permeable core. The results show that in-situ foam generation is an effective method for improving CO2) displacement efficiency. Foam was most effective when the foaming agent was injected after CO2 displaced the oil from the more permeable core. The improved sweep efficiency was caused by the tendency permeable core. The improved sweep efficiency was caused by the tendency of the foam to be generated preferentially in the more permeable core. The foam increased resistance to flow in this core and caused more CO2 to flow through the less permeable core. The second injection method is also more applicable to field implementation. Introduction Laboratory experiments and fieldwide tests have shown that significant amounts of residual oil can be recovered by CO2 flooding. The success of the CO2 floods has been diminished by the unfavorable mobility ratio between CO2 and oil. The unfavorable mobility ratio, together with the heterogeneities of the reservoir, results in reduced sweep efficiency. Several methods have been proposed to control CO2 mobility. The major methods are direct thickening of CO2 with chemicals, injection of alternate slugs of CO2 and water, and in-situ generation of foam. Direct thickening of CO2 involves increasing its viscosity by adding a chemical directly to supercritical CO2. It has been difficult, however, to find chemicals that at low concentration can increase the viscosity of dense-phase CO2. In the other method of improving CO2 mobility, water-alternating-gas (WAG) injection, the multiphase flow of CO2 and water increases the resistance to flow, thereby reducing the CO2 mobility. A WAG process, however, is not without its drawbacks. Major ones are process, however, is not without its drawbacks. Major ones are gravity segregation between water and CO2 and increased project time. A promising method of mobility control is the in-situ generation of foam by the injection of slugs containing a foaming agent. CO2 disperses throughout the liquid slug, generating a large interfacial area whose resistance to flow is much greater than that of the CO2 or the solution. This process causes increased flow of CO2 to unswept areas of the reservoir. A foaming agent can also reduce the interfacial tension at the oil/water interface and thereby assist in mobilizing residual oil. The major objectives of this laboratory study were to develop and implement methods to screen and select foaming agents and to test the oil production efficiency of the foaming process in parallel cores of different permeabilities. Selection of a Foaming Agent An effective screening method should result in the selection of a suitable foaming agent for a given set of reservoir conditions. The foaming agent should be capable of generating ample, lasting foam in the presence of reservoir rock. It should have low adsorption and decomposition losses. A good foaming agent should increase the CO2 sweep efficiency and the oil recovery in porous media tests. In addition, it should be commercially available and inexpensive. A screening procedure was devised and implemented. This procedure is similar to that given by others. Fig. 1 shows the procedure is similar to that given by others. Fig. 1 shows the overall screening method. It consists of preliminary screening, sta-bility, and core tests. Preliminary Screening Tests. Preliminary screening provides a rapid and simple method for estimating the concentration of maximum foam quality, for determining relative foaming ability and stability, and for estimating the effects of brine and oil on these properties. Shaking and blender tests were used to determine the foaming ability and stability. The shaking test used air and isooctane, whereas the blender test used air. In each test, the foam volume and the time required to drain one-half of the liquid were recorded. The foam volume and liquid were used to calculate foam quality. The time for one-half of the liquid to drain was taken as a measure of foam stability. Stability Tests. A foaming agent may lose its ability to function in the reservoir because of adsorption on the reservoir rock, partitioning into the oil, or chemical decomposition. The main goals partitioning into the oil, or chemical decomposition. The main goals of the stability tests are to determine these losses and to help predict which foaming agents would have a good chance of success over the life of a CO2 field flood. Fig. 2 shows the test variables, test duration, and the determined properties for short-term, long-term and high-pressure stability. The short-term static adsorption tests last for several days and are conducted in reservoir brine with crushed rock at reservoir temperature and different foaming-agent concentrations. The long-term stability tests last for 6 months. They include the conditions of the short-term static adsorption tests; in addition, the pH is adjusted to that caused by the dissolution of CO2. The high-pressure stability testing apparatus featured two high-pressure window cells that could be rotated to mix their contents. SPERE P. 1186