This paper reports the objectives, design and progress of a field test of "CO2-foam" as a lowered progress of a field test of "CO2-foam" as a lowered mobility displacing fluid. It includes the background of mobility control considerations leading to the trial, and describes the influence on it of various operational conditions and constraints. The Rock Creek oil field of Roane County, West Virginia, has been produced since 1906 from a low permeability sandstone with high clay content, and is now near the end of economic life. The area utilized in this test is a smaller portion of two ten-acre five-spots that have been subjected to a conventional CO2 flood and subsequent waterflooding, in addition to gas recycling and primary production. A major goal of the test was primary production. A major goal of the test was to determine whether the oil remaining in this area could be displaced by a slug of thickened CO2 to form a mobile oil bank that could be detected at a nearby observation well. A second goal was to test the injectivity of CO2-foam as liquid CO2 and dilute surfactant solution were pumped simultaneously down fiberglass tubing into the injection well. The design of the test was based on published measurements of the ability of the chosen surfactant (Alipal CD128) to form a foam-like dispersion with liquid CO2, on stability at reservoir temperature (73F; 23C), on the extent of adsorption onto the reservoir rock, and on the appropriate value, of the relative mobility of the CO2-foam (0.2 cp-1). Although it has been possible to inject the target quantity of CO2 foam, possible to inject the target quantity of CO2 foam, the injection of chase water has not yet been completed.
Disintegration of slugs of displacement fluid, early breakthrough, and loss of efficiency and profitability of flood programs can all be viewed profitability of flood programs can all be viewed as the result of non-uniform displacement velocity in the reservoir. Such non-uniformities are, in turn, the result of two major causes—the inhomogeneity of most reservoir rock, and frontal instability. Although both of these causes can be quite serious, only the second one is addressed in this paper. The "mobility control" referred to in the title is an attempt to deal with the frontal instability which is caused by an unfavorable mobility ratio. The attempt, described in this paper, has been to thicken the injected fluid—in paper, has been to thicken the injected fluid—in this case, CO2—to lower mobility only to the level of the mobility of the oil, itself. The goal in the use of CO2-foam in this project is not flow diversion, which is a different aim in which much greater mobility reductions have been sought. The name CO2-foam, itself, is a convenient abbreviation that does not imply the existence in the porespace of the same foam observed in ordinary circumstances.
In the use of mobility control envisaged here, the goal is to thicken all of the CO2 required for the displacement from a given injection well, and to inject all of it in a single slug. This contrasts also with the usual WAG method of mobility control, in which the required CO2 is split into several slugs, separated by interludes of surfactant-free water injection.
This use of CO2-foam as a mobility-controlled displacing fluid has been attempted in a portion of the Rock Creek field in Roane County, West Virginia. The field has been produced since 1906 from the Big Injun formation—a clayey, tight sandstone at a depth of about 2000 ft. In addition to primary production, the field has been subjected to gas re-injection, waterflooding and conventional CO2 flooding.