Representing slow foam dynamics in laboratory corefloods for enhanced oil recovery

On thelaboratory scale, foam can be slow to come to steady state (local equilibrium). In fitting dynamic foam corefloods, if local equilibrium does not apply, it is essential to understand and fit the dynamics so that an accurate local-equilibrium model can be applied on the field scale. We report an attempt to represent slow foam dynamics using a simple first-order kinetic expression for the approach of foam to steady state in a population-balance model. In particular, we attempt to fit a case of gas injection into a surfactant-saturated core ("SAG" injection) (Ma et al., 2013), where the peak in pressure difference across the core takes place well after gas breakthrough, in violation of most local-equilibrium foam models. As the kinetics of foam generation are slowed in our model, the peak pressure gradient is reduced, but the timing of the peak remains at the time of gas breakthrough, i.e. after less than one pore volume injection. For sufficiently slow kinetics, the peak can be broadened significantly by spreading of the traveling wave at the shock at the foam front. We survey published population-balance models for mechanisms that could give a late peak in pressure gradient in a SAG coreflood. Most previous studies with population-balance models use parameter values that would give rapid foam generation and a peak in pressure drop at gas breakthrough in a SAG coreflood. The data of Ma et al. suggest an abrupt onset of foam generation later in the coreflood. to represent it, we believe some sort of triggering mechanism for foam generation (for instance, pressure gradient) is needed in the population-balance model. Another possible mechanism leading to a late peak is a nonlinear response of gas relative permeability to gas trapping and refining foam texture. Copyright 2014, Society of Petroleum Engineers

Effect of permeability on foam-model parameters: An integrated approach from core-flood experiments through to foam diversion calculations

We present a set of steady-state foam-flood experimental data for four sandstones with different permeabilities, ranging between 6 and 1900 mD, and with similar porosity. We derive permeability-dependent foam parameters with two modelling approaches, those of Boeije and Rossen (2015a) and a non-linear least-square minimization approach (Eftekhari et al., 2015). The two approaches can yield significantly different foam parameters. Thus, we critically assess their ability in deriving reliable foam parameter estimates. In particular, the way the two approaches treat shear-thinning foam behaviour and foam coalescence is discussed. The foam parameter set acquired from the latter approach is further used as input in foam diversion calculations: this serves to evaluate mobility predictions in non-communicating reservoir layers. This study aims to provide a framework to integrate experimental work, modelling and simple qualitative diversion calculations to provide a background for the upscaling of foam studies, with particular focus on heterogeneous systems

Effect of temperature on foam flow in Porous media

Foam can increase sweep efficiency within a porous medium, which is useful for oil-recovery processes (Farajzadeh et al., 2012). The flow of foam in porous media is a complex process that depends on properties like permeability, porosity and surface chemistry, but also temperature. Although the surface activity of surfactants as a function of temperature is well described at the liquid/liquid or liquid/gas interface, data on the effect of temperature on foam stability is limited, especially in porous media. In this work, we tested a surfactant (AOS) at different temperatures, from 20°C to 80°C, in a sandstone porous medium with co-injection of foam. The pressure drop, or equivalently the apparent viscosity, was measured in steady-state experiments. The core-flood experiments showed that the apparent viscosity of the foam can decrease by 50% when the temperature increased to 80°C. This effect correlates with the lower surface tension at higher temperatures. These results are compared to bulk foam experiments, which show that at elevated temperatures foam decays and coalesces faster. This effect, however, can be attributed to the faster drainage at high temperature, as a response to the reduction in liquid viscosity, and greater film permeability leading to faster coarsening. Our results show that one cannot fit foam-model parameters to data at one temperature and apply the model at other temperatures, even if one accounts for the change in fluid properties (surface tension and liquid viscosity) with temperature

Effect of temperature on foam flow in porous media

Foam can increase sweep efficiency within a porous medium, which is useful for oil-recovery processes [1]. The flow of foam in porous media is a complex process that depends on properties like permeability, porosity and surface chemistry, but also temperature. Although the surface activity of surfactants as a function of temperature is well described at the liquid/liquid or liquid/gas interface, data on the effect of temperature on foam stability is limited, especially in porous media.In this work, we tested a surfactant (AOS) at different temperatures, from 20 °C to 80 °C, in a sandstone porous medium with co-injection of foam. The pressure gradient, or equivalently the apparent viscosity, was measured in steady-state experiments. The core-flood experiments showed that the apparent viscosity of the foam decreased by 50% when the temperature increased to 80 °C. This effect correlates with the lower surface tension at higher temperatures. These results are compared to bulk foam experiments, which show that at elevated temperatures foam decays and coalesces faster. This effect, however, can be attributed to the faster drainage at high temperature, as a response to the reduction in liquid viscosity, and greater film permeability leading to faster coarsening.Our results using the STARS foam model show that one cannot fit foam-model parameters to data at one temperature and apply the model at other temperatures, even if one accounts for the change in fluid properties (surface tension and liquid viscosity) with temperature. Experiments show an increase in gas mobility in the low-quality foam regime with increasing temperature that is inversely proportional to the decrease in gas-water surface tension. In the high-quality regime, results suggest that the water saturation at which foam collapses fmdry increases and Pc* decreases with increasing temperature