Foam reduces gas mobility and can help improve sweep efficiency in an enhanced-oil-recovery (EOR) process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that the local pressure gradient exceed a critical value (!P ^min). Normally, this happens only in the near-well region. Away from wells, these requirements might not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (Rossen 1999). The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of fractional flow on this process. This article is an extension of a recent study (Shah et al. 2018) investigating the effect of permeability contrast on this process. In this study, the effects of fractional flow and total superficial velocity are described. Coreflood experiments were performed in a cylindrical sintered-glass porous medium with two homogeneous layers and a sharp permeability jump in between, representing a lamination or cross lamination. Unlike previous studies of this foam-generation mechanism, in this study, gas and surfactant solution were coinjected at field-like velocities into a medium that was first flooded to steady state with gas/brine coinjection. The pressure gradient is measured across several sections of the core. X-ray computed tomography (CT) is used to generate dynamic phase-saturation maps as foam generates and propagates through the core. We investigate the effects of velocity and injected-gas fractional flow on foam generation and mobilization by systematically changing these variables through multiple experiments. The core is thoroughly cleaned after each experiment to remove any trapped gas and to ensure no hysteresis. Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, and it then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities. Foam was generated in all cases, at all the injected conditions tested; however, at the lowest velocity tested, strong foam did not propagate all the way to the outlet of the core. Although foam generation was triggered across the permeability boundary at this velocity, it appeared that, for our system, the limit of foam propagation, in terms of a minimum-driving-force requirement, was reached at this low rate. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and f _g. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate—probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in !P and S _g) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injection rate.

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Foam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In steady gas-liquid flow, foam is generated in homogeneous porous media by exceeding a critical pressure gradient, which normally only happens near the wellbore. Away from wells, these requirements may not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. This could dominate foam generation away from wells in layered or laminated geological formations and can improve the chances of success of a foam application. The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of permeability contrast, velocity and fractional flow on this process. In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving co-injection of gas and surfactant solution at field-like velocities were performed. Layered, consolidated and well-characterized sintered glass cores were used as the porous media. The permeability change in each core was analogous to sharp, small-scale heterogeneities such as laminations and cross-laminations. The experiments were carefully designed not to allow foam generation by mechanisms other than snap-off at the permeability boundary in the core. Local pressure gradient was measured at various locations and was used to identify foam generation and subsequent propagation through the porous medium. Additionally, X-ray computed tomography (CT) was employed to detect changes in phase saturation that accompany foam generation and subsequent propagation downstream. CT-based saturations measurements were also used to qualitatively chart the reduction in capillary pressure across the sharp permeability jump, supporting theoretical explanations behind this process. The effect of permeability contrast, superficial velocity and flowing gas fraction on this process was also investigated. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous theory (Rossen, 1999). Conditions for propagation of foam were explored by successively performing experiments at lower velocities and higher gas fractional flows. Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and greater permeability contrasts. @en

A novel multiscale method for multiphase flow in heterogeneous fractured porous media is devised. The discrete fine-scale system is described using an embedded fracture modeling approach, in which the heterogeneous rock (matrix) and highly-conductive fractures are represented on independent grids. Given this fine-scale discrete system, the method first partitions the fine-scale volumetric grid representing the matrix and the lower-dimensional grids representing fractures into independent coarse grids. Then, basis functions for matrix and fractures are constructed by restricted smoothing, which gives a flexible and robust treatment of complex geometrical features and heterogeneous coefficients. From the basis functions one constructs a prolongation operator that maps between the coarse- and fine-scale systems. The resulting method allows for general coupling of matrix and fracture basis functions, giving efficient treatment of a large variety of fracture conductivities. In addition, basis functions can be adaptively updated using efficient global smoothing strategies to account for multiphase flow effects. The method is conservative and because it is described and implemented in algebraic form, it is straightforward to employ it to both rectilinear and unstructured grids. Through a series of challenging test cases for single and multiphase flow, in which synthetic and realistic fracture maps are combined with heterogeneous petrophysical matrix properties, we validate the method and conclude that it is an efficient and accurate approach for simulating flow in complex, large-scale, fractured media.

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