Foamy Oil Behavior Research Articles

Numerical Simulation of Foamy Oil Stability Using Natural Gas Huff and Puff for Ultra-Deep Heavy Oil Reservoir

The nature of injected gas dispersion in oil distinguishes foamy oil behavior from conventional heavy oil behavior. Unlike normal two-phase flow, it involves flow of dispersed gas bubbles with pseudo single phase. This paper presents the results of a numerical simulation study of the stability of foamy oil created by liberation of dissolved gas during natural gas huff and puff process. Through the history matching of labs test conducted by three series of various core tubes in numerical simulation, foamy oil impactions on recovery were discussed based on vertical heterogeneous model. The effects on the stability of foamy oil flow behavior were investigated by mobility ratio, viscous to gravity ratio, layer permeability contrast, vertical to horizontal permeability ratio and the transverse dispersion number in the paper. The results show that foamy oil stability increases with higher oil viscosity, higher injection gas density. The oil recovery decrease with the mobility ratio and the layer permeability contrast, while the oil recovery increase with the vertical to horizontal permeability ratio. This work demonstrates that the transverse dispersion number should be used to assess vertical or microscopic sweep efficiency. The study indicates that foamy oil in porous media during production is unstable, but it will be huge potentials to apply natural gas huff and puff for ultra-deep heavy oil reservoirs.

Rheological Behavior of Foamy Oils

When a reservoir is depleted, the lightest components (methane, ethane, etc.) can exsolve from the crude oil and create a gaseous phase. In conventional oils, the bubbles grow and coalesce quickly and the gas usually separates from the oil (slug flow). On the contrary, in heavy oils, bubbles are small, remain dispersed, and flow within the oil for a long time. This “foamy oil” phenomenon can drastically change the flow properties of the crude oil. This paper is devoted to the characterization of the heavy oil foaming behavior through a rheological study. Our objectives are to study the kinetics of bubble evolution in heavy oil and to measure the influence of the bubbles on the heavy oil viscosity. A new experimental method was developed on the basis of rheological measurements under pressure. Several heavy oils containing dissolved gas have been depleted inside the pressure cells of controlled stress rheometers to create foamy oils. Viscosity and viscoelastic properties have been continuously measured using respectively continuous and oscillatory tests from the nucleation to the disengagement of bubbles from oil. Results reveal that, under low shear rates, the presence of bubbles leads to an increase in heavy oil viscosity, as predicted by the hard sphere model or Taylor. A theoretical model describing the viscosity of foamy oil was then established. It takes into account both first-order kinetics of the appearance and release of bubbles in oil and a classic suspension model. Good agreement was obtained between experimental data and model predictions. Several tests reveal the strong influence of the shear rate on the foamy oil behavior and point out the major role of bubble deformation on the viscosity of foamy oils, as shown previously in other viscous materials, such as magmas and polymers. Under high shear rates, we suggest that the stabilization of the elongated bubbles in oil leads to the establishment of an anisotropic material, which can be seen as a sandwich-like structure. As a result, the viscosity appears lower in the direction of the flow.

Viscosity Behavior of Foamy Oil: Experimental Study and Modeling

Heavy oil cold production is faced with the foamy oil phenomenon: while extracted, a heavy crude oil is submitted to a depletion that can induce the formation of dispersed gas bubbles and makes it appear as a foam. This situation results in a change of the flow properties of the live oil that is still debated: correlations predict a decrease or an increase in the gas bubble-dispersed oil viscosity with the gas volume fraction. We attempted to improve the understanding of the foamy oil behavior through rheological measurements. A live oil was depleted inside the pressure cell of a controlled stress rheometer. The occurrence of bubbles was checked and visualized with x-ray scanning experiments. Viscosity was continuously measured using oscillatory and continuous tests. This particular experimental approach allowed us to successfully study the rheological behavior of a foamy oil in relationship with the two main parameters, which are the composition and the viscosity of the crude oils. A theoretical model describing the viscosity of a foamy oil has been established. It takes into account both first-order kinetics of appearance and release of bubbles in oil and a basic suspension model. Results from this model are in agreement with experimental data obtained from different heavy crude oils.

Use of Magnetic Resonance Imaging as a Tool for the Study of Foamy Oil Behavior for an Extra‐Heavy Crude Oil. T2 /Viscosity Correlation with Respect to Pressure

The purpose of this work is to present the results of the phase behavior study for a live heavy oil during a pressure depletion process using magnetic resonance imaging (MRI) as a tool to characterize foamy oil phenomena. The experiments were carried out in the pressure range of 13.1 to 1.4 MPa. Signal intensity images were obtained at each pressure and with respect to time, that is, approximately for a total time of 3 h after each pressure change. It is possible to see a variation in intensity across the sample. These changes can be associated with changes in mobility as well as segregation of the oil. It was also possible to observe that what we trust is the formation of gas channels at the last two pressure values, as it comes out of solution. A correlation between the transverse relaxation time T2 and temperature was established with the aim of producing one between T2 and viscosity. In this way viscosity maps for the live oil were obtained as a function of pressure and time. It was observed that above the bubble point, the viscosity maps varied from low to high to low with respect to time for the same pressure. Below the bubble point the situation is reverse. The viscosity map changes from high to low to high with respect to time for the same pressure. The study shows the potential use of MRI to follow viscosity changes during pressure depletion test in a PVT MRI cell.