Foam is utilized in enhanced oil recovery and CO₂ sequestration. Surfactant-alternating-gas (SAG) is a preferred approach for placing foam into reservoirs, due to it enhances gas injection and minimizes corrosion in facilities. Our previous studies with similar permeability cores show that during SAG injection, several banks occupy the area near the well where fluid exhibits distinct behaviour. However, underground reservoirs are heterogeneous, often layered. It is crucial to understand the effect of permeability on fluid behaviour and injectivity in a SAG process. In this work, coreflood experiments are conducted in cores with permeabilities ranging from 16 to 2300 mD. We observe the same sequence of banks in cores with different permeabilities. However, the speed at which banks propagate and their overall mobility can vary depending on permeability. At higher permeabilities, the gas-dissolution bank and the forced-imbibition bank progress more rapidly during liquid injection. The total mobilities of both banks decrease with permeability. By utilizing a bank-propagation model, we scale up our experimental findings and compare them to results obtained using the Peaceman equation. Our findings reveal that the liquid injectivity in a SAG foam process is misestimated by conventional simulators based on the Peaceman equation. The lower the formation permeability, the greater the error.

@en

Aqueous foam is a dispersion of gas in liquid, where the liquid acts as the continuous phase and the gas is separated by thin liquid films stabilized by a surfactant. Foam injection is a widely used technique in various applications, including CO2 sequestration, enhanced oil recovery, soil remediation, etc. Surfactant-alternating-gas (SAG) is a preferred approach for foam injection, and injectivity plays a vital role in determining the efficiency of the SAG process. Different gases can be applied depending on the process requirements and availability. However, the underlying mechanisms by which gas composition impacts injectivity are not yet fully understood. In this work, the effect of gas composition on fluid behavior and injectivity in a SAG process was investigated using three gases: N2, CO2, and Kr. Our observations revealed that gas solubility in liquid was key for the formation and evolution of liquid fingers, and therefore was very important for liquid injectivity. A lower gas solubility in liquid led to a slower increase in surfactant solution injectivity. In addition, the development of surfactant solution injectivity took significantly longer when the surfactant solution was partially pre-saturated compared to when it was unsaturated. Additionally, the propagation of the collapsed-foam bank during gas injection was accelerated when the gas had a greater solubility in water.@en

Surfactant-alternating-gas (SAG) is a preferred method of foam injection, which is a promising means of enhanced oil recovery. Liquid injectivity in a SAG process is commonly problematic. Our previous studies suggest that the liquid injectivity can be better than expected due to the existence of a collapsed-foam region formed during the gas-injection period ahead of the liquid-injection period. A single superficial velocity was used in those studies to examine the flow behavior during gas- and liquid-injection periods, separately. However, in radial flow from an injection well, superficial velocity decreases with distance from the injection well. Understanding the effect of superficial velocity on gas and liquid injectivities is important, but remains unexplored. In this study, we first examine gas injection at different superficial velocities following foam injection. We then study the effect of liquid superficial velocity on the liquid injectivity following a similar volume of gas injection. Our results show that during a prolonged period of gas injection following foam, the propagation velocity and the total mobility of the collapsed-foam bank are not significantly affected by the gas superficial velocity. During liquid injection after a period of gas injection, the dimensionless propagation velocities and the total mobilities of the forced-imbibition bank and the gas-dissolution bank follow a power-law dependence on the liquid superficial velocity. Liquid fingering through the weakened-foam region shows strongly shear-thinning behavior. It is also observed from X-ray computer-tomography experiments that the liquid fingers are wider if the liquid superficial velocity is greater. The impact of the shear-thinning behavior on the estimation of liquid injectivity in a field application is the subject of a companion paper.

@en

Surfactant-alternating-gas (SAG) is a favored method of foam injection, which has been proved as an efficient way for enhancing oil recovery. However, foam flow is extremely complicated, and there are still unsolved problems for foam application. One is liquid injectivity. Our previous studies suggest that the injectivity in a SAG process is determined by propagation of several banks near the injection well that are not represented by current foam models. Uniform bank properties were assumed. However, in a companion paper, our experimental results show that the dimensionless propagation velocity and the total mobility of banks during the liquid-injection period depends on superficial velocity. Shearing-thinning behavior is observed. In radial flow, the superficial velocity varies with distance from the well. In this study, we scale-up the experimental results using a radial bank-propagation model. The comparison of liquid injectivity estimated from conventional foam simulators (Peaceman equation) and the bank-propagation model show that the conventional foam models cannot represent the effect of the superficial-velocity-dependent fluid properties during liquid injection in a SAG process. The shear-thinning behavior can lead to much better liquid injectivity than expected, which should be accounted for in a field application of a SAG foam process.

@en

Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity.

In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator’s results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor.

The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.@en