Accurate modeling of foam rheology on the field scale requires detailed understanding of the correlation between the fundamental properties of foam and the scalable parameters of the porous medium. It has been experimentally observed that foam experiences an abrupt coalescence when the capillary pressure in the porous medium approaches a certain value referred to as the "limiting capillary pressure", P c *. Current foam models that treat foam texture implicitly mimic this fundamental behavior with a so-called dry-out function, which contains adjustable parameters like fmdry and epdry (in the STARS foam simulator). Parameter fmdry (called S w * in other models) represents the water saturation corresponding to the limiting capillary pressure, P c *, and epdry determines the abruptness of foam coalescence as a function of water saturation. In this paper, using experimental data, we examine the permeability dependence of these parameters. We find that the value of fmdry decreases with increasing permeability. We also find that, for the data examined in this paper, the transition from the high-quality regime to low-quality regime is more abrupt in lower-permeability rocks. This implies that in high-permeability rocks foam might not collapse abruptly at a single water saturation; instead, there is a range of water saturation over which foam weakens. In addition, we address the question of whether P c * is dependent on formation permeability. We estimate P c * from data for foam mobility versus foam quality and find, as did Khatib et al. (SPE Reservoir Eng., 1988, 3 (3), 919−926), who introduced the limiting capillary pressure concept, that P c * can vary with permeability. It increases as permeability decreases, but not enough to reverse the trend of increasing foam apparent viscosity as permeability increases.

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The stabilization of carbon dioxide-in-water (C–W) foams with nanoparticles (NPs) becomes highly challenging as the temperature and salinity increase, particularly for divalent ions, as the nanoparticles often aggregate in the brine phase. For silica nanoparticles with a medium coverage (MC) and high coverage (HC) of organic ligands, the hydrophilic–CO2-philic balance (HCB) was found to be in the appropriate range to produce a large reduction in the C–W interfacial tension (IFT). Furthermore, the nanoparticles were colloidally stable in concentrated brine (15% total dissolved solids, TDS) up to 80 °C. With these interfacially active nanoparticles, C–W foams were stabilized with apparent foam viscosities up to 35 cP and foam textures with bubble sizes on the order of 40 μm at various gas fractional flows (foam qualities) in beadpack experiments. At the foam quality where the apparent viscosity was a maximum (transition quality) in the beadpack, we also produced CO2 foams in Boise and Berea cores versus temperature with apparent viscosities up to 26 cP at 70 °C and 15% TDS and hysteresis in the apparent viscosity versus the interstitial velocity. The reductions in the IFT and foam strength at elevated temperature were modestly larger for the HC nanoparticles than for the MC nanoparticles but were low for the low-coverage case. Given that the interfacial adsorption increased with salinity up to 15% TDS, the screening of the charge helped drive the particles from the brine phase to the interface, which was necessary to stabilize the foams.

Summary Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates. The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times. One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.

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Polymer flooding is one of the most widely used chemical enhanced oil recovery methods due to its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution is often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior at near well-bore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, we propose a new model to history match field injection rate/pressure data. The pertinent equations for deep-bed filtration and external cake build-up in radial coordinate were coupled to the viscoelastic polymer rheology to capture important mechanisms. We selected radial coordinate in order to minimize the velocity/shear rate errors due to gridblock size in Cartesian coordinate. We used filtration theory and successfully history matched the field data. We performed systematic simulations and studied the impact of adsorption (retention), shear thickening, deep bed filtration, and external cake formation to explain the well injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure during early times is attributed to the shear thickening rheology at high velocities experienced by viscoelastic HPAM polymers around the wellbore and the permeability reduction due to polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external cake growth is responsible for the sharper increase in injection pressure at the later times. The proposed model can be used to calculate the injectivity of the polymer injection wells, understand the contribution of different phenomena on the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.