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• W2023390096 abstract "A discussion of remedies for many placement problems that are caused by gravity segregation of fluids in the wellbore, particularly in stimulation or workover jobs involving small treatment volumes. Three examples are given to illustrate theoretical and experimental models to find remedies for several typical fluid placement problems. Introduction Success of stimulation and workover jobs involving acid. solvents, inhibitors, or other chemicals often is determined by how well an operator understands and can control fluid placement in a completion interval. Sometimes, it is desirable to place a uniform volume of fluid into each part of the completion, while other times it is better to place nearly all of a chemical into only a portion of the completed interval. For example, uniform acid placement probably is necessary for damage removal in placement probably is necessary for damage removal in an interval completed above the water contact, but in a well with potential bottom-water production, carefully controlled acid placement is required so that only the upper part of the completion is stimulated. Although critical to job success, in most low-cost stimulation-workover jobs, little or no foresight is give to fluid placement. Unless mechanical control methods, placement. Unless mechanical control methods, such as packers, can be justified, it is normal to assume a uniform treatment profile. However, such an assumption is only a matter of convenience, because uniform treatment profiles seldom occur. Actual treatment profiles depend on the well completion geometry, formation characteristics, fluid properties, and treatment volume. When a treatment involves a sequence of fluids, as in sand consolidation, the coverage profile for each of the fluids depends on the foregoing factors, plus the profiles of each of the preceding fluids. This paper is presented to call attention to the need for more consideration of placement profiles in increasing stimulation-workover job success. Results from experimental and theoretical studies of placement profiles of sequentially injected, immiscible fluids with different densities and viscosities are described. Experimental studies were performed in a laboratory glass model of a wellbore having three in-line, equally-spaced perforations. Theoretical studies were done using a multilayer, perforations. Theoretical studies were done using a multilayer, radial computer model of a wellbore-completion interval and a surrounding formation, limited by the assumptions of an openhole completion, zero crossflow between formation layers, and radial plugflow in each layer. Variables surveyed include density, viscosity, and sequence of fluids; wellbore configuration and tubing tail position; and formation permeability, pressure, and porosity profiles (Fig. 1). profiles (Fig. 1). Gravity Segregation Whenever two immiscible fluids with different densities are placed in a container, such as a wellbore, they tend to separate. This separation, called gravity segregation, occurs wherever the degree of agitation is less than that needed to disperse the fluids. Our studies show that wellbore gravity segregation is one of the most important factors controlling placement profiles of fluids in the formation around a wellbore. Fig. 2 illustrates why gravity segregation is so important. When a fluid is injected into a well filled with another immiscible fluid (Fig. 2), it tends to rise or fall according to its density and that of the in-wellbore fluid. The injected fluid accumulates at one end of the completion interval, and an interface forms between the two fluids. As the volume of pumped fluid increases, it displaces more of the initial in-wellbore fluid, and an interface moves away from the accumulation point. JPT P. 1657" @default.
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• W2023390096 title "Injection Profile Effects Caused by Gravity Segregation in the Wellbore" @default.
• W2023390096 doi "https://doi.org/10.2118/6129-pa" @default.
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