Polymer Flooding a ~500-cp Oil

Abstract

Abstract Relatively high oil prices, modest polymer prices, and advances that promote higher injectivity for polymer solutions have allowed polymer flooding to be applied in reservoirs with notably more viscous oils than in previous years. This paper describes a polymer flooding pilot project in the Tambaredjo field in Suriname. The average viscosity of the produced oil is ~1,700 cp, but solution gas reduces the effective oil viscosity in the reservoir to 400–600 cp (through the "foamy oil" mechanism). Interestingly, the primary drive mechanism in the pilot area is compaction—leading to ~20% OOIP recovery. Because various restrictions preclude application of thermal methods, polymer flooding was explored as a means to enhance oil recovery. The average permeability of the sand exceeds 4darcys, but the level of heterogeneity is significant (>10:1 permeability contrast is common). The first simulation efforts suggested that injection of 25–40-cp polymer solutions might be optimum, considering both displacement and injectivity. Consequently, ~40-cp polymer solutions were injected during the first part of the pilot. However, later analysis revealed that sweep efficiency could be improved significantly using polymer solutions up to 160 cp. Although injection was done at pressures below what was believed to be the formation parting pressure, injectivity data from several water injection cycles shows that partition of the formation followed by partial sustenance of the fracture did occur. Analysis of produced water salinities, polymer and tracer concentrations, water/oil ratios (WOR), and inter-well pressure responses all indicated that severe channeling (i.e., through fracture-like features) did not occur. Instead, analysis of the project response indicated that (1) sweep could benefit from injecting more viscous polymer solutions, (2) injectivity for more viscous polymers would not be a problem because of controlled (i.e., not detrimental) fracture extension, and (3) oil production rates could be enhanced (without sacrificing WOR) by increasing injection rates. Consequently, these ideas are currently being field tested in our project. This paper details results to date for this polymer pilot.