Water Control in Producing Wells: Influence of an Adsorbed-Polymer Layer on Relative Permeabilities and Capillary Pressure

Barreau, Patrick (U. of Bordeaux) | Bertin, Henri (U. of Bordeaux) | Lasseux, Didier (U. of Bordeaux) | Glénat, Philippe (Total) | Zaitoun, Alan (Inst. Français du Pétrole)

OnePetro 

Summary

To determine modifications of oil/water two-phase-flow properties after injection of water-soluble polymers, unsteady-state flow experiments were performed on both water- and oil-wet (silane-treated) sandstones. The same imbibition cycle (water displacing oil) under the same conditions was performed on the same core, first without any polymer and then after polyacrylamide had been adsorbed within the core. The capillary pressure was measured directly along the core by use of water- and oil-wet semipermeable membranes, while relative permeabilities were determined from the measurement of the saturation profile (by gamma ray absorption), outlet fluid production, and pressure drop.

The action of adsorbed polymer on relative permeabilities was found to be the same with both water- and oil-wet cores (i.e. a selective reduction of the relative permeability to water with respect to the relative permeability to oil). The trend was somewhat different for the capillary pressure. For the case of water-wet sandstones, the capillary pressure remained positive but increased dramatically after polymer adsorption. Because the polymer has little effect on the interfacial tension (IFT), this effect was attributed to the reduction of pore-throat size caused by macromolecule adsorption and to a possible improvement of the wettability of the core to water. For the case of oil-wet sandstone, the capillary pressure curve moved from negative to positive values, indicating that, in addition to pore-size restriction, the wettability of the core changed after polymer adsorption. This wettability change also induced a dramatic drop in residual oil saturation (ROS).

Introduction

Excessive production of water as a result of heterogeneities or fractures often causes channeling or water coning and is a problem of central importance for field operators. Several techniques have been developed to overcome this problem. Among them, direct injection of polymer or gels in the production well was shown to enable the reduction of the water cut. If the drawdown on the treated well can be increased, then, in addition to the reduction in water production, the treatment can induce an increase in oil production.1 Several researchers have studied the mechanisms involved in the action of polymer or gels (Schneider and Owens,2 Zaitoun and Kohler,3 Zaitoun et al.,4 Liang et al.5). They all found that polymer or gels are able to reduce selectively the relative permeability to water with respect to the relative permeability to oil. Provided that the polymer is hydrophilic, this property does not depend on the polymer type (polyacrylamide, xanthan or scleroglucan) or on the nature of the rock (sandstone, limestone, or unconsolidated sand). Most existing experiments have been performed either under steady- or unsteady-state conditions at a high flow rate (Welge method).

Several physical processes have been proposed to explain the selective action of the polymer. The following are some principal ones.

1. Shrinking of the gel in the presence of oil. Dawe and Zhang6 observed water eviction from a gel during the displacement of an oil droplet in a micromodel. The influence of the wettability was also investigated. The gel was shown to have a lower blocking efficiency in oil-wet micromodels.

2. Partitioning of fluids. This hypothesis, put forward by Liang et al.,5 suggests that a segregation of oil and water occurs in the core and explains the disproportionate permeability.

3. Wall effect. The presence of the polymer adsorbed on pore walls may induce a lubrication effect that favors the flow of oil through the center of the pore channels and attenuate pore-wall roughness. This hypothesis was suggested by Zaitoun and Kohler.3 These authors proposed a simple two-phase-flow capillary model within a cylindrical geometry to describe the effect of an adsorbed polymer layer at the pore wall. To complete this pore-level study, we are developing a numerical model where the pore consists in a periodic two-dimensional (2D) divergent/convergent channel.7 The first results8 confirm qualitatively the experimental observations.

4. Wettability effect. The adsorption of the hydrophilic polymer on pore walls may enhance the water wettability of the rock and thus contribute to the relative permeability modification.

Most of reported studies were focused on relative permeability modifications, but little information (Barrufet and Ali9) is available about the effect of polymer on the capillary pressure. Our experimental procedure aimed at the measurement of this parameter as well. We performed unsteady-state core-flow experiments at low flow rates. To our point of view, these experiments are more realistic than steady-state ones. During these experiments, we measured directly the capillary pressure along the core using semipermeable membranes at pressure taps, and we determined the relative permeabilities over the whole saturation range.

Experimental

Fluids.

We used synthetic brines containing 50 g/L&minus1 KI and 0.4 g/L&minus1 NaN3. The potassium ion prevents clay migration while the iodide ion improves the accuracy of saturation measurements by gamma ray attenuation technique.10 Sodium azide was used as a bactericide. As the oil phase, we used Marcol 52, a mineral oil having a viscosity of 10.5 mPa·s at 20°C. IFT's between brine and oil and between polymer solution and oil were measured with the ring technique; values were 33´10&minus3 and 28´10&minus3 N/m&minus1, respectively.

Polymer Solution.

We used a high-molecular-weight nonionic polyacrylamide (PAM) available in powder form. The polymer behaves like a flexible coil in solution with an average diameter of 0.32 mm. Its molecular weight is 9´106 dalton.4 The solution, whose concentration is 2500 ppm, was prepared by slow addition of polymer powder to the brine in a vortex created by magnetic stirring. After complete dissolution of the powder, the solution was filtered on line with a set of 8-, 3- and 1.2-mm Millipore membranes to remove any solid or microgel. The viscosity of the polymer solution was measured over a wide range of shear rates with a Contraves LS 30 viscometer. The curve of viscosity vs. shear rate is plotted in Fig. 1.