TX 75083-3836, U. S. A., fax et-972-952.9435. AbstractWe measured three phase relative permeabilities for gravity drainage using a dual-energy medical CT scanner modified to scan vertical cores, Independent measurements of two saturations as a function of time and distance along the length of the core were made from which relative permeabilities were found. Three phase (air/oil/water) gravity drainage experiments were performed on systems with different spreading coefficients and at different initial conditions. Experiments were run on both consolidated and unconsolidated porous media. The results were compared to measurements of three phase flow in capillary tubes, micromodels and to predictions from network modeling.We find that at low oil saturation k,. N S; for hexane and octane as the oil phase. This functional form of relative permeability is consistent with the drainage of oil layers, wedged between the water and gas in crevices of the pore space. For decane, which is non-spreading, the layer drainage regime was not observed. At higher oil saturations kro -+ S: with a x 4 for spreading and non-spreading systems. Within the scatter of the experimental data, oil and water relative permeability are functions only of their own saturations and independent of initial conditions.

Gasflooding in oil reservoirs leads to bypassing of the oil as a result of gravitational, viscous, and/or heterogeneity effects. A part of the bypassed oil can be recovered by the flowing solvent because of crossflow/mass transfer. In this work, we studied the effect of the orientation of the bypassed region and the enrichment of the solvent on the mass transfer. Laboratory-scale mass transfer and coreflood experiments were conducted. Numerical simulation was used to identify the role of the different mechanisms. Results indicate that the mass transfer is the least for the vertical orientation, intermediate for the inverted orientation, and the highest for the horizontal orientation. The mass transfer increases with enrichment for all orientations. Liquid-phase diffusion controls vertical-orientation mass transfer for the fluids studied. Gravity-driven flow contributes the most to the mass transfer in the horizontal and inverted orientations. Oil recovery in horizontal gasfloods can be nonmonotonic with enrichment. Multiphase flow in the near-miscible floods leads to less gravity override compared with the first-contact-miscible (FCM) floods.

Summary Enriched gasfloods incorporate a complex interaction of heterogeneity, fingering, multiphase flow, and phase behavior. Experiments and simulations indicate that the optimum solvent enrichment in high-viscosity-ratio secondary gasfloods can be below minimum miscibility enrichment (MME). The compositional path and resulting mobility profile in multidimensional multiple-contact miscible (MCM) or immiscible floods are different from their 1D counterparts for high-viscosity-ratio floods in heterogeneous media. Introduction The objective of this work is to study the effect of phase behavior on bypassing in laboratory gasfloods by combined use of compositional modeling and laboratory computed tomography (CT) scanning. Oil was displaced from a heterogeneous core by several solvents at constant, high viscosity ratio (1,600). Displacement was vertical to avoid gravity override. The bypassing of the oil during the flood was monitored by a vertical CT scanner. A 2D compositional model was used to simulate these displacements and a model three-component system at viscosity ratios of 22 to 200. The experimental data indicate that bypassing decreases as immiscibility increases. The solvent finger moved fastest in the single-phase displacement and slowest in the three-phase displacement. Compositional simulation of these floods was unstable at a 1,600 viscosity ratio. Model system simulation indicates that as viscosity ratio increases, sweep efficiency in first-contact-miscible (FCM) solvents deteriorates sharply. Sweep in near- and below-MME solvents does not decrease as sharply because of multi phase flow. Optimum solvent enrichment in high-viscosity-ratio, secondary gasfloods can be below MME. The compositional path and resulting mobility profile in multidimensional MCM or immiscible floods are different from their 1D counterparts for high-viscosity-ratio floods in heterogeneous media. Blunt et al.'s1 theory of compositional fingering does not work for the heterogeneous medium studied. Background The economics of hydrocarbon solvent flood projects depends on factors that include the enrichment level of the solvent as well as the slug size and WAG ratio. Similarly, the economics of CO2 flood projects depends heavily on the injection pressure. Common industry practice is to use a hydrocarbon solvent at or above its MME2 or to use CO2 at or above its minimum miscibility pressure (MMP).3 In 1D displacements, MME and MMP are the optimum levels of enrichment or pressure, respectively, for the injection solvent. However, reservoir flow is 3D. Rock heterogeneity, viscous fingering, gravity override, diffusion, dispersion, and presence of mobile water may cause optimum enrichment (or pressure) in a reservoir flood to be different from that in a 1D flood, especially in a slim-tube test. Injected solvent composition (or pressure) affects not only the local displacement efficiency (i.e., that evaluated by 1D experiments or calculation) but also the sweep efficiency.4 The mobility ratio and density contrast are large in most solvent floods. Sweep efficiency can be low as a result of fluid channeling, viscous fingering, and gravity override and plays a crucial role in determining the overall recovery efficiency. Simulations of secondary and tertiary solvent floods in several heterogeneous permeability fields have shown that floods with solvent enrichment at or below that required for development of multicontact miscibility in 1D flow can perform as well or better than floods with richer solvents.4 Pande and Orr5 showed, by method-of-characteristics calculations, that the optimum pressure can be lower than MMP in a two-layer reservoir. These results, if valid, are very important to solvent flood economics because they can reduce solvent cost. Such simulations, however, are always open to questions regarding inclusion of all types of crossflow (e.g., capillary and dispersive), realistic spatial permeability variations, history-dependent relative permeability and capillary pressure hysteresis, and numerical dispersion.6 One objective of this work is to conduct solvent floods in a heterogeneous rock to determine whether optimum enrichment levels can be lower than MME at laboratory scale. This would validate the simulation results reported by Pande4 and Pande and Orr.5 Generally speaking, as enrichment (or pressure) increases, microscopic displacement efficiency increases before leveling off at MME (or MMP). However, sweep efficiency can decrease as enrichment (or pressure) increases.4 This decrease is not because of viscosity ratio or density contrast, which decrease as enrichment (or pressure) increases. However, it may be caused by the interactions of phase behavior and heterogeneous flow field.7,8 The second objective of this work is to study this interaction at a laboratory scale. Blunt et al.1 and Blunt and Christie9 have advanced the empirical theory for viscous fingering significantly. Application of this theory to compositional floods assumes that the 1D average compositional path in fingered floods is the same as in 1D floods. This was the case for their 2D fine-grid simulations in a low-heterogeneity permeability field in the absence of gravity segregation. Fingers were small compared with the widths of the systems in all their examples. The third objective of this study is to determine the effect of bypassing on composition path of our laboratory floods and to verify whether the assumption of Blunt et al.'s1 theory is applicable in these corefloods. In the next two sections, we describe our experimental program and discuss the results. Then, we describe the modeling of experimental floods, the simulation of a three-component model system, and the interactions between phase behavior and flow bypassing. The last section summarizes our findings. Experimental Procedure The experimental program consisted of several corefloods on a vertically mounted 8-in.-long by 1.5-in.-diameter core (Fig. 1). Flow direction was from top to bottom. The experimental setup included a composite core holder with a constant-temperature jacket, an injection module consisting of two pressure vessels for fluid transfer and gas injection and for overburden control, and a production module with a backpressure regulator (BPR) and a graduated centrifuge tube for recording recovery volumes. A Techni care Deltascan 2020 CT scanner oriented for vertical corefloods was used for the experiments. To achieve a complete core scan within 20 minutes, we used a 4.9-in. scan diameter, a 0.3-in. scan thickness, and 16 slices. Five corefloods were conducted: a matched-density/-viscosity miscible flood, a matched-density/adverse-viscosity miscible flood, an ethane flood of oil at 10 mL/hr, an ethane flood at 1 mL/hr, and a hydrocarbon gasflood of oil. All floods were conducted at irreducible water saturation, a 1,650-psi outlet pressure, and a 65°F system temperature. After each experiment, the core was cleaned with decalin, then resaturated with the particular "oil." The oil viscosity was ˜80 cp, and the ethane and hydrocarbon-solvent viscosities were ˜0.05 cp.

Mass transfer from a bypassed region to a flowing region is a very strong function of the solvent phase behavior. Diffusion, dispersion, and capillarity-driven crossflow can contribute to this mass transfer in addition to pressure-and buoyancy-driven crossflow. Our experiments indicated that the mass transfer rate increased with enrichment. Liquid phase diffusion played a significant role and capillary pumping did not contribute to mass transfer in the cases studied. IntroductionInjection of carbon dioxide and/or enriched hydrocarbon gases is still a popular enhanced oil recovery technique despite the low oil prices of the recent years. The cost of solvent injected is the key to the economics of such a gasflood project. In 1D displacements, recovery decreases sharply with pressure (or enrichment) below the minimum miscibility pressure (MMP), or the minimum miscibility enrichment (MME). 1,2 However, reservoirs are 3D. Recent laboratory work of Shyeh-Yung 3 shows that oil recovery does not fall sharply below MMP in tertiary CO 2 floods; near-miscible solvents can be effective at core-scale in vertical floods. Near-miscible solvents are defined as solvents with composition near the MME composition; enrichment can be slightly lower than the MME. Chang et al. 4 have shown that recovery in gravity-dominated secondary gasfloods does not increase monotonically with enrichment in corescale hydrocarbon displacements. Burger et al. 5 showed that improvement in overall recovery in the near-miscible region comes from improvement in sweep over the more enriched solvents in laboratory-scale vertical corefloods using computed tomography (CT). Pande 6 has shown that, at the field scale, the optimum enrichment for a water-alternating-gas flood depends on the heterogeneity of the reservoir. Reservoir rocks are heterogeneous. The viscosity and density of injectants are significantly smaller than those of oils to be displaced. Rock heterogeneity, gravity override, and viscous fingering conspire to bypass oil in gasfloods. Recovery of oil depends on the amount of bypassing and the amount of crossflow/mass transfer from the bypassed regions to the invaded regions.The objective of this paper is to understand the amount of crossflow and mass transfer from bypassed regions to the invaded regions in gasfloods. There are four contributing factors to this crossflow/ mass transfer: pressure-driven, 7 gravity-driven, dispersion/diffusion-driven and capillarity-driven. 8 The pressure-driven and gravity-driven crossflows are accounted for directly in flow equations. The accuracy of these two crossflow terms, however, depends on the resolution of the gridblocks and the accuracy of the pressure fields. The other two factors need to be incorporated into the flow equations. Dispersion and diffusion are often not represented mechanistically at the field scale. The capillarity-driven crossflow is often ignored at the field scale. When the bypassed fluid and displacement fluid are first contact miscible (FCM), there is no capillary crossflow. When thes...

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