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

Abstract

In the domain of heavy to extra heavy oil production, viscous polymer may be injected after water injection (tertiary mode), or as an alternative (secondary mode) to improve the sweep efficiency and increase oil recovery. To prepare field implementation, nine polymer injection experiments in heavy oil have been performed at core scale, to assess key modelling parameters in both situations. Among this consistent set of experiments, two have been performed on reconstituted cylindrical sandpacks in field-like conditions, and seven on consolidated Bentheimer sandstone in laboratory conditions. All experiments target the same oil viscosity, between 2000 cP and 7000 cP, and the viscosity of Partially Hydrolyzed Polyacrylamide solutions (HPAM 3630) ranges from 60 cP to 80 cP. Water and polymer front propagation are studied using X-ray and tracer measurements. The new experimental results presented here for water flood and polymer flood experiments are compared with experiments described in previous papers. The effects of geometry, viscosity ratio, injection sequence on recoveries, and history match parameters are investigated. Relative permeabilities of the water flood experiment are in line with previous experiments in linear geometry. Initial water floods led to recoveries of 15–30% after one Pore Volume Injected (PVI), a variation influenced by boundary conditions, viscosity, and velocities. The secondary polymer flood in consolidated sandstone confirms less stable displacement than tertiary floods in same conditions. Comparison of secondary and tertiary polymer floods history matching parameters suggests two mechanisms. First, hysteresis effect during oil bank mobilization stabilizes the tertiary polymer front; secondly, the propagation of polymer at higher oil saturation leads to lower adsorption during secondary experiment, generating a lower Residual Resistance Factor (RRF), close to unity. Finally, this paper discusses the use of the relative permeabilities and polymer properties estimated using Darcy equation for field simulation, depending on water distribution at polymer injection start-up.

Measurement and Modelling of the Interfacial Tensions of Co2 + Decane-Iododecane Mixtures at High Pressures and Temperatures

“…8 shows the deviations of the experimental IFTs of CO 2 and decane-iododecane mixtures from the results predicted by Eq. (10). Most of the deviations are within ±0.6 mN•m −1 .…”

“…In core flooding experiments with X-ray CT imaging, contrast agents are usually added to fluids to modify their X-ray attenuation coefficients and enhance the contrast between phases [6,7] so that multiphase flow can be more-easily visualized. Commonly used contrast agents for the oil phase include iododecane [5,[8][9][10][11], iodobenzene [12,13], iodoheptane [14,15] and iodononane [16]. The mass fraction of the dopant typically ranges from 7% to 50% and the optimum concentration for specific systems can be determined from either contrast scans or grey-scale histograms [5].…”

Immiscible Viscous Fingering: the Effects of Wettability/Capillarity and Scaling

“…Skauge and Salmo 2015;Bondino et al 2011;Fabbri et al 2015;Salmo et al 2017;T. Skauge et al 2014;de Loubens et al, 2018;Fabbri et al 2020). Unstable waterfloods (and tertiary polymer floods) were performed on 2D slabs of Bentheimer sandstone, and the full dataset of oil recovery, watercut and pressure drop profiles and in situ x-ray images of the finger patterns (all vs. PV injected) were reported.…”

Dynamic and static gelation behavior of phenol formaldehyde resin gel system in ampoule bottles and porous media

“…When dynamic gelation in porous media, the HPAM/PFR gelant suffered from the shear of porous media. And the shear rate was calculated by equation (1) (Savins, 1969;Hirasaki and Pope, 1974;Camilleri et al, 1987;Fabbri et al, 2020). The shear rates under different concentrations and permeabilities were listed in Table 5:…”