Polymer Flooding a ~500-cp Oil

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.

Polymer Flooding of Heavy Oil - From Screening to Full-Field Extension

“…An inverted 5-spot pattern is unconfined thus recovery is more difficult to estimate but polymer losses will be reduced. It is better in those two cases to use several patterns such as was done in Tambaredjo (Moe Soe Let et al 2012). The reader is referred to Teletzke et al (Teletzke et al 2010) for a more detailed discussion on pilot best practices.…”

“…When the reservoir is layered with free crossflow and severe contrasts of permeability, some authors (Seright 2010, Moe Soe Let et al 2012) recommend to inject a high viscosity (120-160 cp for Tambaredjo for instance). The basis for this is:…”

“…‫ؠ‬ In Tambaredjo, increasing the injected viscosity from 40 to 160 cp requires increasing the polymer concentration by a factor , however incremental recovery will increase by a smaller factor according to the estimates (Moe Soe Let et al 2012). This remains true even when accounting for the improved sweep efficiency, at least in Tambaredjo.…”

“…If injection water is different from formation water then it is also useful to sample produced water periodically to monitor the evolution of the water composition as was done for instance in the Tambaredjo pilot (Moe Soe Let et al 2012).…”

“…Successful smaller scale pilots are also ongoing or have been completed in Argentina (6 injection and 3 production wells in an oil with a live oil viscosity of 160 -300 cp, (Hryc et al 2013)), Suriname (3 injection and 9 production wells in an oil with an apparent live oil viscosity of 300 to 600 cp, (Moe Soe Let et al 2012), the North Sea (Etebar 1997) and Canada (Wassmuth et al 2009, Liu et al 2012, Delamaide et al 2014a. The data for the documented field tests are summarized in Table 1 to Table 4.…”