Permeability Reduction Due to use of Liquid Polymers and Development of Remediation Options

Abstract

Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.

Experimental Study on the Relationship between Carbonate Reservoir Quality Index and Dynamic Parameters of Chemical Solutions for Oil Recovery Practice

“…lowest values of injectivity for both core plugs occurred for polymer solution injection.Figures 12,13,and 14 show the same trend for the concentration of 0.2 wt %. Compared the injectivity of primary and post-seawater injection with the case of polymer solution whether the concentration of 0.1 or 0.2 wt %, the reduced injectivity is caused by the viscosity impact14 and adsorption of the polymer solution.…”

“…The values of the injectivity for seawater, polymer solution, and seawater injections are listed in Table 5. Figures 10,11,12,13,and 14 present the relationship between injectivity and frontal velocity with RQIs for five core plugs A, B, C, D, and E, respectively. Two core flooding experiments have been completed for the concentration of 0.1 wt % using core plugs A and B with RQIs of 1.01 and 0.95 μm, respectively.…”

Assessment of Polymer-Induced Formation Damage Using Microfluidics

“…While at the reservoir scale, processes are designed to be in the order of one pore-volume injected (PVI), the near-wellbore region will effectively encounter a much larger PVI. Therefore, laboratory screening programs should incorporate such extended polymer injection tests (Alexis et al, 2016;Alfazazi et al, 2019;Dwarakanath et al, 2016). While at the coreflood scale, this can be a limitation, here, we show that microfluidics can be used for such high throughput tests.…”

Historical and recent observations in polymer floods: An update review

“…Captain Field offshore UK is another important polymer flood project injecting liquid polymers; however, its documentation is scarce (Chevron 2014(Chevron & 2015Poulsen, 2009Poulsen, & 2010. Dwarakanath et al (2016) recently reported a study evaluating the permeability reduction in porous media (Bentheimer rock, Ottawa sand and unconsolidated field sand) due to the use of liquid polymers. This study also reports remediation formulations to improve injectivity.…”