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Collaborating Authors
Results
Does Polymer Stabilize Foam in Porous Media?
Shen, Chun | Nguyen, Quoc Phuc | Huh, Chun (U. of Texas Austin) | Rossen, William Richard (U. of Texas Austin)
Abstract Addition of polymer has been proposed as a way to stabilize foam, especially in the presence of oil. This study probes the putative stabilizing effect of polymer on foam in terms of steady-state properties. Specifically, we tested the effect of polymer addition on the two steady-state foam regimes identified by Alvarez et al. (SPEJ, 2001). For the two polymers (xanthan and partially hydrolyzed polyacrylamide), two oils (decane and 37.5º API crude oil), and an alpha-olefin sulfonate surfactant, it appears from coreflood pressure gradient that polymer destabilizes foam modestly, raising water saturation and water relative permeability. The increased viscosity of the aqueous phase with polymer counteracts the effects of destabilization of foam. For the same polymers and surfactant, polymer does not stabilize foam in the presence of decane or 37.5º API crude oil relative to foam without polymer. Surface-tension measurements with these polymers and surfactant likewise showed no evidence of presence of polymer at the air-water interface that might stabilize foam lamellae between bubbles. This suggests that, for similar polymers and surfactants, addition of polymer would not give stronger foam in field application or stabilize foam against the presence of crude oil. Complex behavior, some of it in contradiction to the expected two steady-state foam regimes, was observed. At the limit of, or in the place of, the high-quality regime, there was sometimes an abrupt jump upwards in pressure gradient as though from hysteresis and a change of state. In the low-quality regime, pressure gradient was not independent of liquid superficial velocity, but decreased with increasing liquid superficial velocity, as previously reported and explained by Kim et al. (SPEJ, 2005). Introduction Foam is a dispersion of gas in liquid stabilized by surfactant. It is used for mobility control in EOR (Rossen, 1996), acid diversion in well stimulation (Gdanski, 1993; Rossen and Wang, 1999) and recovery of wastes in environmental remediation (Hirasaki et al., 2000; Mamun et al., 2002). However, foam has a limited lifetime. One proposed solution is the use of polymer in conjunction with surfactant solution to improve foam properties. It is a familiar observation that polymer increases liquid viscosity and slows the rate of liquid drainage from bulk foam. Whether polymer stabilizes foam in porous media, where water drains rapidly from one pore to the next driven by capillary forces, not gravity, is not clear. In this paper we investigate the effect of polymer additives on the stability of foams made from AOS surfactant. Coreflood experiments have been run with both conventional and polymer-enhanced foam, without and with oil in sandpacks and Boise sandstone.
- North America > United States > Texas (0.93)
- North America > United States > Idaho > Ada County > Boise (0.27)
Abstract We earlier presented a proof for the model of Stone (1982) for gravity segregation in steady-state, horizontal gas-liquid flow in homogeneous porous media using only the standard assumptions of the method of characteristics. We extend this method here to cases of co-injection of gas and liquid over only a portion of the formation interval, injection of water above gas over the entire formation interval, and injection of water and gas in separate zones well separated from each other. If gas and liquid are injected at fixed total volumetric rates, the horizontal distance to the point of complete segregation is the same, whether gas and liquid are co-injected over all or any portion of the formation interval. The volume of reservoir swept by gas may be affected by these different injection strategies, however, and is not directly predicted by our model. At fixed injection pressure, the deepest penetration of mixed gas and water is expected when fluids are co-injected along the entire formation interval. At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does co-injection, but again exactly where the two fluids are injected does not affect the distance to the point of segregation. At fixed injection pressure, injection of liquid above gas is predicted to give much deeper penetration before complete segregation. When injection pressure is limited, the best strategy for simultaneous injection of both phases would be to inject gas at the bottom of the reservoir and liquid over the rest of the reservoir height, with the ratio of the injection intervals adjusted to maximize overall injectivity. These results apply equally to gas-liquid flow and to foam. Sample computer simulations for foam injection agree well with the model predictions if numerical dispersion is controlled. Introduction A useful model for gravity segregation is that of Stone (1982), further elucidated by Jenkins (1984), for steady-state, uniform co-injection of gas and water in a homogeneous porous medium; to distinguish this case from others below, by uniform co-injection we mean injection of gas and water with uniform water fractional flow and uniform superficial velocity all along the height of the formation. Stone assumed that in this case at steady state the reservoir splits into three regions of uniform saturation, with sharp boundaries between them:an override zone with only gas flowing an underride zone with only water flowing a mixed zone with both gas and water flowing.
- Europe (0.93)
- North America > United States > Oklahoma (0.28)
Abstract Foam is used in the oil industry in a variety of applications, and polymer is sometimes added to increase foam's stability and effectiveness. A variety of surfactant and polymer combinations have been employed to generate polymer-enhanced foam (PEF), typically anionic surfactants and anionic polymers, to reduce their adsorption in reservoir rock. While addition of polymer to bulk foam is known to increase its viscosity and apparent stability, polymer addition to foams for use in porous media has not been as effective. In this pore-level modeling study, we develop an apparent viscosity expression for PEF at fixed bubble size, with the intention of better interpreting the conflicting laboratory coreflood data available. To derive the apparent viscosity, the pressure-drop calculation of Hirasaki and Lawson (1985) for gas bubbles in a circular tube is extended to include the effects of shear-thinning polymer in water, employing the Bretherton's asymptotic matching technique. For polymer rheology, the Ellis model is employed, which predicts a limiting Newtonian viscosity at the low-shear limit and the well-known power-law relation at high shear rates. While the pressure drop due to foam can be characterized fully with only the capillary number for Newtonian liquid, the shear-thinning liquid requires one additional grouping of the Ellis-model parameters and bubble velocity. The model predicts that the apparent viscosity for PEF shows behavior more shear-thinning than that for polymer-free foam, because the polymer solution being displaced by gas bubbles in pores tends to experience a high shear rate. Foam apparent viscosity scales with gas velocity (Ug) with an exponent [-a/(a+2)], where a, the Ellis-model exponent, is greater than 1 for shear-thinning fluids. With a Newtonian fluid, for which a =1, foam apparent viscosity is proportional to the (−1/3) power of Ug, as derived by Hirasaki and Lawson. A simplified capillary-bundle model study shows that the thin-film flow around a moving foam bubble is generally in the high-shear, power-law regime. Since the flow of polymer solution in narrower, water-filled tubes is also governed by shear-thinning rheology, it affects foam mobility as revealed by plot of pressure gradient as a function of water and gas superficial velocities. The relation between the rheology of the liquid phase and of that of the foam is not simple, however. The apparent rheology of the foam depends on the rheology of the liquid, the trapping and mobilization of gas as a function of pressure gradient, and capillary pressure, which affects the apparent viscosity of the flowing gas even at fixed bubble size. Introduction When a gas such as CO2 or N2 is injected into a mature oil reservoir for improved oil recovery, its sweep efficiency is usually very poor due to gravity segregation, reservoir heterogeneity and viscous fingering of gas, and foam is employed to improve sweep efficiency with better mobility control (Shi and Rossen 1998; Zeilinger et al., 1996). When oil is produced from a thin oil reservoir overlain with a gas zone, a rapid coning of gas can drastically reduce oil production rate, and foam is used to delay the gas coning (Aarra et al., 1997; Chukwueke et al., 1998; Dalland and Hanssen 1997; Thach et al., 1996). During a well stimulation operation with acid, a selective placement of acid into a low-permeability zone from which oil has not been swept is desired, which can be accomplished with use of foam (Cheng et al., 2002). For environmental remediation of subsurface soil using surfactant, foam is used to improve displacement of contaminant, such as DNAPL, from heterogeneous soil (Mamun et al., 2002).
- Europe (0.67)
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)