Can 25-cp Polymer Solution Efficiently Displace 1,600-cp Oil During Polymer Flooding?

Abstract

Summary This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada's Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds−1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.

Evaluation of Polymeric Materials for Chemical Enhanced Oil Recovery

“…They also found that increasing the viscosity of the polymer solution beyond 25 cP did not increase oil recovery. The efficient heavy oil displacement observed in these experimental runs was attributed to the low relative water permeability achieved during polymer flooding that resulted in a favorable mobility ratio [143].…”

“…This suggests that polymer flooding might become more popular as an EOR process for viscous oil reservoirs in the near future. A recent core-flooding experimental study conducted by Seright et al [143] used core plugs from the Cactus Lake (Canada) heavy oil reservoir and demonstrated that a polymer solution with a viscosity of 25 cP (7.3 s −1 ) effectively displaced Cactus heavy with a viscosity of 1610 cP at 27 • C and 1 ft/day. They also found that increasing the viscosity of the polymer solution beyond 25 cP did not increase oil recovery.…”

Development of novel mathematical models for laboratory studies of hydrolyzed polyacrylamide polymer injectivity in high-permeability conduits

“…Some of these methods can include other chemical methods or solvent injection Fakher 2019a, b). The polymer solution will have a high viscosity and thus will overcome several displacement and mobility problems associated with water flooding, mainly viscous fingering (Zhou et al 2019;Seright et al 2018;Seright 2017). Different types of polymers have been developed and used to improve oil recovery and mobility control; however, HPAM polymer still remains the most widely used polymer for chemical EOR applications mainly due to its cost, availability, and ease of handling (Seright 2017;Koh et al 2018;Fletcher et al 1992;Buell et al 1990;Gerlach et al 2019).…”

“…Polymer injectivity can be defined as the ease by which the polymer can be injected into the formation (Shuler et al 1987). If the polymer solution is too viscous, it may be extremely difficult, or sometimes impossible, to inject it into the formation (Seright et al 2018). Injectivity is therefore an extremely important factor to consider when designing any polymer flooding project since it has a direct impact on cost of the overall project and can impact safety as well if the formation is fractured during injection (Sharma et al 2016;De Simoni et al 2018).…”

“…This, however, is sometimes impractical or impossible especially if the pore size is too small or the polymer solution is too viscous. Seright et al (2009) researched three properties of polymers that may impact their injectivity, including polymer rheology in porous media, where they found that pseudo-plastic behavior for HPAM may occur if the pore structure is too small for the polymer to propagate through easily.…”