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The success of foam-induced flow diversion in fractured carbonates hinges on proper injection strategies, requiring an in-depth understanding of the factors responsible for stimulating fracture–matrix interactions. In this study, we present a novel investigation of the interactions between the fracture and the matrix influenced by the mobility control effect during CH4-foam injections. These interactions were probed at the pore scale using a three-phase flow system integrated with a high-resolution micro-CT scanner. In situ phase saturations were monitored and quantified to interpret the resulting fluid transport at various injection parameters. At the initial stage of foam injection, the surfactant solution was able to invade the matrix leading to water/oil displacement events, however, impeding gas penetration. Increasing total injection velocity produced higher in situ foam quality in the fracture than the injected quality, where significant fraction of the surfactant solution from the foam was primarily diverted into the matrix. A pronounced increase in the average gas saturation within the matrix was only observed at the highest injection velocity. The pore-scale evidence showed the occurrence of combined displacement processes (water/oil, gas/oil, gas/oil/water) in the matrix, attributed to the established mobility control in the fracture, which contributed to the diversion of surfactant solution and gas to the matrix. Lastly, the injection–soaking–production technique effectively mobilized the residual oil after a long injection process of CH4-foam. At this stage, the surfactant solution was no longer playing a role as the primary invading fluid; rather, it was the diverted gas that led to the increase in the matrix-oil production. [ABSTRACT FROM AUTHOR]

$$\hbox {CO}_{2}$$ flood is one of the most successful and promising enhanced oil recovery technologies. However, the displacement is limited by viscous fingering, gravity segregation and reservoir heterogeneity. Foaming the $$\hbox {CO}_{2}$$ and brine with a tailored surfactant can simultaneously address these three problems and improve the recovery efficiency. Commonly chosen surfactants as foaming agents are either anionic or cationic in class. These charged surfactants are insoluble in either $$\hbox {CO}_{2}$$ gas phase or supercritical phase and can only be injected with water. However, some novel nonionic or switchable surfactants are $$\hbox {CO}_{2}$$ soluble, thus making it possible to be injected with the $$\hbox {CO}_{2}$$ phase. Since surfactant could be present in both $$\hbox {CO}_{2}$$ and aqueous phases, it is important to understand how the surfactant partition coefficient influences foam transport in porous media. Thus, a 1-D foam simulator embedded with STARS foam model is developed. All test results, from different cases studied, have demonstrated that when surfactant partitions approximately equally between gaseous phase and aqueous phase, foam favors oil displacement in regard to apparent viscosity and foam propagation speed. The test results from the 1-D simulation are compared with the fractional flow theory analysis reported in the literature. [ABSTRACT FROM AUTHOR]

Unfavorable mobility ratio and reservoir heterogeneities contribute to water fingering phenomenon that leads to relatively low oil recovery factors in heavy oil fields. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Capillary-driven mobility alteration of the water phase by emulsion drops leads to not only more uniform macroscopic reservoir sweep, but also a pore scale reduction in the residual oil saturation. Despite recent developments, fundamental aspects of dilute oil-in-water emulsion flow through porous media and its application as an EOR method are still not clear. Experiments were performed in a 1D flow configuration using silica sandpacks and sandstone cores to determine the effect of permeability, emulsion drop size, dispersed phase concentration and size of injected emulsion bank on the volume of displaced oil, a crude heavy oil from Campos Basin ( $$20^{\circ }$$ API). X-ray computerized tomography images obtained during experiments in a Castlegate sandstone block in a 1/4 5-spot configuration revealed that emulsion acts both in the macroscale and pore scale, improving the macroscopic sweep and lowering the residual oil saturation. [ABSTRACT FROM AUTHOR]

Foam injection is a proven enhanced oil recovery (EOR) technique for heterogeneous reservoirs, but is less studied for EOR in fractured systems. We experimentally investigated tertiary $$\text {CO}_{2}$$ injections, and $$\text {N}_{2}$$ - and $$\text {CO}_{2}$$ -foam injections for enhanced oil recovery in fractured, oil-wet limestone core plugs. Miscible $$\text {CO}_{2}$$ and $$\text {CO}_{2}$$ -foam was compared with immiscible $$\text {CO}_{2}$$ - and $$\text {N}_{2}$$ -foam as tertiary recovery techniques, subsequent to waterfloods, in fractured rocks with different wettability preferences. At water-wet conditions waterfloods produced approximately 40 % OOIP, by spontaneous imbibition. Waterflood oil recovery at oil-wet conditions was below 20 % OOIP, due to suppressed imbibition where water predominantly flowed through the fractures, unable to mobilize the oil trapped in the matrix. Tertiary, supercritical $$\text {CO}_{2}$$ -mobilized oil trapped in the matrix, particularly at weakly oil-wet conditions, by diffusion. Recovery by diffusion was high due to small core samples, high initial oil saturation and a continuous oil phase at oil-wet conditions. Both immiscible $$\text {CO}_{2}$$ - and $$\text {N}_{2}$$ -foams and miscible, supercritical $$\text {CO}_{2}$$ -foam demonstrated high ultimate oil recoveries, but immiscible foam was less efficient (30 pore volumes injected) compared to miscible foam (2 pore volumes injected) to reach ultimate recovery. This is explained by the capillary threshold pressure preventing the injected $$\text {N}_{2}$$ gas from entering the matrix, verified by computed X-ray tomography, and the mobilized oil was displaced by the aqueous surfactant in the foam. At miscible conditions, there exists no capillary entry pressure between the oil-saturated matrix and the injected $$\text {CO}_{2}$$ , allowing foam to invade the matrix for efficient oil recovery. [ABSTRACT FROM AUTHOR]

The uniqueness and sensitivity of foam modeling parameters are crucial for simulating foam flow through porous media. In the absence of oil in the porous medium, the local-equilibrium foam model investigated in this work uses three parameters to describe the foam quality dependence: $$fmmob,\, fmdry$$ , and $$epdry$$ . Even for a specified value of $$epdry$$ , in some cases, two pairs of $$fmmob$$ and $$fmdry$$ values can experimentally match measured transition foam quality ( $$f_\mathrm{g}^{t}$$ ) and transition foam apparent viscosity ( $$\mu _\mathrm{foam,app}^t$$ ). This non-uniqueness can be broken by limiting the solution such that $$fmdry$$ is smaller than the transition water saturation ( $$S_\mathrm{w}^t$$ ). In addition, a three-parameter fit using all experimental data of apparent viscosity versus foam quality was developed to simultaneously estimate $$fmmob,\, fmdry$$ , and $$epdry$$ . However, a better strategy is to conduct and match a transient experiment, in addition to steady-state experiments, in which a gas displaces the surfactant solution at 100 % water saturation. This transient foam quality scans the entire range of fractional flow, and the values of the foam parameters that best match the experiment can be uniquely determined. The numerical artifact of pressure oscillations in simulating this transient foam process was investigated by comparing the finite difference algorithm with the method of characteristics. Sensitivity analyses indicated that the estimated foam parameters were highly dependent on the parameters used for the water and gas relative permeabilities. In particular, the water relative permeability exponent and connate water saturation are important. [ABSTRACT FROM AUTHOR]

Modeling the flow of emulsion in porous media is extremely challenging due to the complex nature of the associated flows and multiscale phenomena. At the pore scale, the dispersed phase size can be of the same order of magnitude of the pore length scale and therefore effective viscosity models do not apply. A physically meaningful macroscopic flow model must incorporate the transport of the dispersed phase through the porous material and the changes on flow resistance due to drop deformation as it flows through pore throats. In this work, we present a dynamic capillary network model that uses experimentally determined pore-level constitutive relationships between flow rate and pressure drop in constricted capillaries to obtain representative transient macroscopic flow behavior emerging from microscopic emulsion flow at the pore level. A parametric analysis is conducted to study the effect of dispersed phase droplet size and capillary number on the flow response to both emulsion and alternating water/emulsion flooding in porous media. The results clearly show that emulsion flooding changes the continuous-phase mobility and consequently flow paths through the porous media, and how the intensity of mobility control can be tuned by the emulsion characteristics. [ABSTRACT FROM AUTHOR]

The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control. [ABSTRACT FROM AUTHOR]

Chang and Slattery (1986, 1988b) introduced a simplified model of dispersion that contains only two empirical parameters. The traditional model of dispersion (Nikolaevskii, 1959; Bear, 1961; Scheidegger, 1961; de Josselin de Jong and Bossen, 1961; Peaceman, 1966; Bear, 1972) has three empirical parameters, two of which can be measured in one-dimensional experiments while the third, the transverse dispersivity, must be measured in experiments in which a two-dimensional concentration profile develops. It is found that nearly the same linear stability behavior results from using either model. [ABSTRACT FROM AUTHOR]

Viscous fingering and gravity tonguing are the consequences of an unstable miscible displacement. Chang and Slattery (1986) performed a linear stability analysis for a miscible displacement considering only the effect of viscosity. Here the effect of gravity is included as well for either a step change or a graduated change in concentration at the injection face during a downward, vertical displacement. If both the mobility ratio and the density ratio are favorable (the viscosity of the displacing fluid is greater than the viscosity of the displaced fluid and, for a downward vertical displacement, the density of the displacing fluid is less than the density of the displaced fluid), the displacement will be stable. If either the mobility ratio or the density ratio is unfavorable, instabilities can form at the injection boundary as the result of infinitesimal perturbations. But if the concentration is changed sufficiently slowly with time at the entrance to the system, the displacement can be stabilized, even if both the mobility ratio and the density ratio are unfavorable. A displacement is more likely to be stable as the aspect ratio (ratio of thickness to width, which is assumed to be less than one) is increased. Commonly the laboratory tests supporting a field trial use nearly the same fluids, porous media, and displacement rates as the field trial they are intended to support. For the laboratory test, the aspect ratio may be the order of one; for the field trial, it may be two orders of magnitude smaller. This means that a laboratory test could indicate that a displacement was stable, while an unstable displacement may be observed in the field. [ABSTRACT FROM AUTHOR]

A linear stability analysis has been performed for a miscible displacement in a semi-infinite system of finite thickness and unbounded width. A more general description of dispersion has been adopted than those used by previous workers. It is shown that, when there is a step change in concentration and the mobility ratio is unfavorable, the displacement can be unstable at the injection boundary. But, if the concentration is changed sufficiently slowly with time at the entrance to the system, the displacement is stable to infinitesimal perturbations, no matter how unfavorable the mobility ratio. When the mobility ratio is favorable, the displacement is unconditionally stable. [ABSTRACT FROM AUTHOR]

A one-dimensional ternary two-phase simulator has been extended to include improved physical properties. These physical properties - such as phase behavior, interfacial tension, residual saturations, relative permeabilities, phase viscosities, wettability, capillary pressure, adsorption and dispersion - are modeled as concentration dependent functions. Their functionality completely controls the chemical flood transport phenomena. In this paper, the influence of phase behavior, interfacial tension reduction, mobility control and wettability alteration on chemical flooding are analyzed. In a subsequent paper the influence of capillary pressure, adsorption, and physical and numerical dispersion will be presented. The main application of the simulator here presented is to describe enhanced oil recovery processes. It may also be applied to describe oil spill cleaning and groundwater contamination. [ABSTRACT FROM AUTHOR]