Foam injection is a promising method to increase oil recovery in mature oil fields because it can overcome the limitations of conventional gas injection by significantly reducing the mobility and improve sweep efficiency. It is economic because later gas breakthrough leads to less gas production and reduced costs related to gas recycling and re-injection. Reservoir simulation models describe foam behavior with parameters that are difficult to measure in core-flooding experiments. For example, foam mobility depends on gas bubble density, which changes through bubble generation and coalescence events on the pore scale. A further complication is that foam mechanisms and film stability generally are different in the presence of oil, as shown in experiments. Thus, reservoir simulators rely heavily on fitting foam parameters to core-scale floods before their use. In this project, we will develop and use mathematical methods to investigate multiphase foam flow on the pore scale with a detailed description of the mechanisms for foam film stability and rupture. The project will conduct new pore-scale micromodel experiments to validate and calibrate the modelling approach. We will use the developed methods on segmented 3D rock images to understand and quantify the effect of oil on foam flow in porous rock. The outcome will be a better understanding of foam dynamics in porous rock, which allows a more accurate foam representation in reservoir simulations.
We have developed and implemented a method that can simulate foam displacement with a detailed description of interfaces and triple points between gas bubbles at pore level (activity 1). The work is based on the conservative Multiphase Level Set (MLS) method, that we recently published. We have also developed a flow model (activity 2), which uses the immersed boundary method (IBM) to couple fluid and solid, as well as the ghost-fluid method (GFM) to handle discontinuities of physical variables across fluid-fluid interfaces and triple junctions. We are working on developing the coupled model further to allow merging of several gas bubbles when intermediate liquid films (lamellae) collapse. These models are coupled to the SAMRAI software framework, which facilitates parallel simulations with adaptive mesh.
The UiS/NORCE PhD student has developed methods for diffusion-driven coarsening (Ostwald ripening) of gas-bubble populations in porous media and implemented it in the MLS code (activity 1). This approach can handle arbitrary pore geometries and is thus more general than previous work published in the literature. Simulations confirm that both coarsening and “anti-coarsening” of gas bubbles occur in porous media, and that coarsening is more significant in micro-fractured porous structures than in homogeneous media. Simulations on sandstone show that small, spherical bubbles dissolve while large ganglia grow and develop a more ramified structure. Simulations on micromodel geometries show that the mass transfer rate can be described by either a local or global ripening regime, or a combination of both, depending on initial bubble distribution. The developed methods have been extended to describe ripening of gas bubble populations in the presence of both oil and water. Due to gas solubility differences in water and oil, the ripening evolution is faster for gas bubbles in oil than for gas bubbles in water. A key finding is that the gas-bubble population after ripening exhibits different gas bubble sizes in oil and water. The difference in bubble sizes is a function of oil/water capillary pressure. We are currently investigating this matter with respect to wetting state in porous media. From this work, we have published one article, two papers are submitted, and two more papers are being prepared. The PhD student plans to submit the thesis in February 2023.
As part of the micromodel experiments (activity 5), the PhD Student at UiB has upgraded the experimental setup to investigate the effect of oil on CO2 foam. Unsteady-state CO2-foam experiments in water-wet micromodels pre-saturated with a foaming solution and trapped oil in a miscible condition (25 degree C and 100 bar) have been conducted and analyzed. CO2-foam experiments without oil present were carried out at similar conditions. The experiments show mechanisms for foam generation and coalescence. A quantitative analysis of the dynamic evolution of gas bubble density and foam texture was performed. The results show that a large fraction of the foam remain trapped. This diverts the flow to otherwise inaccessible areas and improves sweep efficiency. The results were recently published and will be useful for the modelling activities.
We have also developed a method for exploring foam hysteresis behavior in porous media. The method is based on a rugged energy landscape obtained from micromodel experiments and calculates the evolution of bubble pressures as well as averaged pressure during foam drainage and imbibition.
Foam injection is a promising method to increase oil recovery in mature oil fields because it can overcome the limitations of conventional gas injection by significantly reducing the mobility and improve sweep efficiency. It is economic because later gas breakthrough leads to less gas production and reduced costs related to gas recycling and re-injection. Reservoir simulation models describe foam behaviour with parameters that are difficult to measure in core-flooding experiments. For example, foam mobility depends on gas bubble density, which changes through bubble generation and coalescence events on the pore scale. A further complication is that foam mechanisms and film stability generally are different in the presence of oil, as shown in experiments. Thus, reservoir simulators rely heavily on fitting foam parameters to core-scale floods before their use. In this project, we will develop and use mathematical methods to investigate multiphase foam flow on the pore scale with a detailed description of the mechanisms for foam film stability and rupture. The project will conduct new pore-scale micromodel experiments to validate and calibrate the modelling approach. We will use the developed methods on segmented 3D rock images to understand and quantify the effect of oil on foam flow in porous rock. Efforts to model foam with oil present on pore scale are missing in the scientific literature, yet it is an essential part to improve our understanding of foam and make reservoir simulations with foam reliable. From pore-scale simulations, we will determine foam stability and texture, foam generation and coalescence rates, trapped gas fractions, limiting capillary pressure for foam coalescence, relative permeability curves, and hysteresis effects, to investigate foam mobility reduction with and without oil present. The outcome will be a better understanding of foam dynamics in porous rock, which allows a more accurate foam representation in reservoir simulations.
