Foam dynamics in the presence of oil during multiphase flow in porous rock

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 economically attractive 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 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. This project has developed and used mathematical methods to investigate foam dynamics in the presence of oil and water at the pore scale in porous rock. The project also conducts micromodel experiments to validate and calibrate the modelling approach. Application of the developed methods on segmented 3D rock images quantifies how oil and water impact bubble population dynamics in porous rock with respect to foam texture, and rates for mass transfer, bubble generation and destruction. This provides input to reservoir simulation models for a more accurate foam representation. The developed pore-scale model for simulating foam exploits a detailed description of interfaces and triple points between gas bubbles, based on the Multiphase Level Set (MLS) method. We have also developed a flow model that accounts for fluid-solid and fluid-fluid interactions. The project has also developed methods for diffusion-driven coarsening (Ostwald ripening) of gas-bubble populations in porous media and implemented it in the MLS code. The models handle arbitrary pore geometries and bubble configurations. We have coupled the models to the SAMRAI software framework, which facilitates parallel simulations with adaptive mesh refinement. We have also developed a method that explores foam hysteresis behaviour 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. Two-phase simulations of bubble population dynamics with the MLS code confirm that both coarsening and “anti-coarsening” of gas bubbles occur in porous media. Simulations on micromodel geometries show that the coarsening rate depends on both pore geometry and the initial configuration of bubbles with high and low pressures. In homogeneous media, mass transfer between neighbour bubbles is often sufficient to reach equilibrium, while in heterogeneous or layered porous media, the ripening rate is slower as mass transfers sequentially across multiple bubbles. Simulations on sandstone show that small, spherical bubbles dissolve while larger ganglia grow and develop a more ramified structure. Application of the developed methods on gas bubble populations in the presence of both oil and water shows that the equilibrium configuration after ripening exhibits different gas-bubble sizes in oil and water. The difference in bubble sizes is a function of oil/water capillary pressure, in addition to gas/liquid interfacial tensions and wetting state. This implies that the volume fractions of gas in oil and water vary with depth in oil/water transition zones at the field scale. Three-phase simulations in sandstone show that the evolution of gas bubble density depends on the initial configuration, and that coarsening can trigger redistribution of trapped oil. Simulations with different gases (e.g., nitrogen, CO2) at immiscible and near-miscible conditions exhibit different evolution and ripening rates of bubble populations, emphasizing the importance of simulating bubble population dynamics with the correct gas type at realistic reservoir conditions in three-phase systems. The project has used an upgraded setup for the micromodel experiments 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 compared against similar experiments without oil. The experiments reveal mechanisms for foam generation and coalescence. A quantitative analysis of the dynamic evolution of gas bubble density and foam texture shows that a large fraction of the foam remain trapped. This diverts the flow to otherwise inaccessible areas and improves sweep efficiency. The experiments provide valuable data for comparison against the modelling activities. The project has educated a PhD student within pore-scale modelling (UiS/NORCE) and another PhD student within micromodel experiments (UiB).

Foam injection has high potential to enhance oil recovery in hydrocarbon reservoirs by flow diversion and improved sweep efficiency because foam has significantly lower mobility than gas. Injection of CO2-foam for CO2 storage also benefits from such mobility control by increasing the storage potential. However, the foam description in existing reservoir simulation models is based on an excessive use of parameter fitting to experimental data, and hence the reservoir simulator loses its value as a predictive tool. This project has developed advanced numerical tools for parallel simulations with adaptive mesh refinement for investigating bubble population dynamics at the pore scale in the presence of oil and water. This research represents a necessary and crucial step towards improving the description of foam at core and reservoir scales. The models generate data, such as density of bubble populations, and rates for bubble generation and destruction, for input to reservoir simulators based on population-balance equations, which will improve the foam description in these models. The use of the developed numerical tools in an initial planning of foam EOR projects, or foam-CO2 EOR/storage projects, would reduce the need for extensive experimental work and speed up the workflow leading towards field implementation. During the project period, there has been a shift in focus in both industry and academia from technologies for improved oil recovery to subsurface storage technologies that could play a key role in providing cleaner energy production (storage of natural gas and hydrogen) and to mitigate climate changes (CO2 storage). This has spawned interest in industry and academia on investigating the long-term behaviour of trapped gas after gas injection. In temporary gas storage, formation of trapped gas is an undesired mechanism, as it is hard to recover, while in CO2 storage it is a desired mechanism for safe and permanent storage. The developed methods and research results in this project can also be utilized in this context and lead to new practice for interpreting measurements of trapped gas in core-scale experiments. Within this application area, our results and publications have attracted interest from industry, led to new contacts in academia internationally, and resulted in invitations to hold presentations at international conferences. Releasing the numerical model as open source will attract additional interest from academia and industry beyond the project duration and may also lead to new application areas.

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.