Secondary and Tertiary Polymer Flooding in Extra-Heavy Oil: Reservoir Conditions Measurements - Performance Comparison

Abstract

In the challenging context of heavy to extra heavy oil production, polymer flood technology appears to be a promising solution to enhance ultimate recovery of reservoirs. Several field applications have already shown the efficiency of such technologies, although the final incremental recovery and mechanisms involved are still poorly understood. Indeed, the characteristics of the viscous fingering effects that certainly play a role are rarely captured at the field scale or at the core scale. This work aims at comparing the results of two core experiments with polymer flood in secondary and tertiary mode, in reservoir conditions, in term of recovery as well as in terms of relative permeabilities. In both cases, experiments were carried out on reconstituted reservoir cores, with restored wettability, initially saturated with live oil partially degassed in a PVT cell to the expected pressure and viscosity at the start of the field test. Saturation profiles were measured with X-Ray scans; effluents were collected in test-tubes and analyzed by UV measurements. Additional follow-up with tracers was tested in order to better assess the breakthrough of different fluids as well as the polymer adsorption during the experiment. Although the viscosity ratio was still highly unfavorable, with a polymer bulk viscosity around 70 cP at 10s-1 and an oil viscosity estimated at 5500 cP, polymer floods exhibit an excellent recovery factor.

Effect of initial water flooding on the performance of polymer flooding for heavy oil production

“…Core floods realized with 5000-6000 cP oil reported that the secondary polymer flood ultimate recovery was 18% lower than the tertiary polymer flood results in high permeable sandstone (Fabbri et al, 2014). Similarly, the work conducted by Doorwar and Mohanty (2014) evidenced higher tertiary recovery when flooding 200 cP oil in Carbonate and Berea sandstone cores.…”

“…Under this stability condition, history matching of experimental results using conventional Darcy-type simulators has been performed by several authors (Fabbri et al, 2014;Wassmuth et al, 2009).…”

Effects of concentration, salinity and injection scenario of ionic liquids analogue in heavy oil recovery enhancement

“…They showed that polymer flood had better performance when it was injected at tertiary mode after brine flooding (recovery factor 77%) than at secondary injection mode (recovery factor 58%). It has also been stated that the initial water flood can be a stabilizing factor for subsequent polymer flooding (Fabbri et al, 2014;Skuage et al, 2012).…”

“…Zhang and Marow (2006) and Winoto et al, (2012) in their various works of core flooding experiments with Berea sandstone core plugs, they observed significant recovery improvement in tertiary mode when low salinity brine was injected after injection of reservoir brine. Fabbri et al (2014), performed polymer flooding experiments for heavy oil recovery in tertiary and secondary mode. They showed that polymer flood had better performance when it was injected at tertiary mode after brine flooding (recovery factor 77%) than at secondary injection mode (recovery factor 58%).…”

The Impact of Rheology on Viscous Oil Displacement by Polymers Analyzed by Pore-Scale Network Modelling

“…For example, polymer flooding applied in Pelican Lake showed accelerated oil production at a very adverse mobility ratio. Many other studies have investigated the application of polymer flooding for such heavy viscous oils [ 3 , 4 , 5 , 6 , 7 , 8 , 9 , 10 , 11 , 12 ]. These studies definitively established that, contrary to the conventional displacement theory, significant incremental oil could be produced by injecting the polymer in very viscous oils and this oil was produced in an accelerated manner.…”