Summary The saturation distribution after unstable waterflooding into highly viscous oil may have a decisive effect on the efficiency of tertiary polymer flooding, in particular because of hysteresis effects associated with oil banking. In this work, we model waterflood and tertiary polymer-flood experiments performed on Bentheimer sandstone slabs with heavy oils of approximately 2,000 and 7,000 cp, and compare the numerical results with experimental production, pressure, and X-ray data. The unstable waterfloods are initially simulated in two dimensions with our parallel in-house research reservoir simulator (IHRRS) using a high-resolution discretization. In agreement with existing literature, we find that Darcy-type simulations dependent on steady-state relative permeabilities—inferred here from a 3D quasistatic pore-network model (PNM)—cannot predict the measured waterflood data. Even qualitatively, the viscous-fingering patterns are not reproduced. An adaptive dynamic PNM is then applied on a 2D pore network constructed from the statistics of the 3D network. If the fingering patterns simulated with this 2D PNM are qualitatively in good agreement with the experimental data, a quantitative match still cannot be obtained because of the limitations of 2D modeling. Although 3D dynamic PNMs at the slab scale would currently lead to prohibitively high computational cost, they have the potential to address the deficiencies of continuum models at highly unfavorable viscosity ratio. For the tertiary polymer floods characterized by a much more favorable mobility ratio, Darcy-type modeling is applied, and history matching is conducted from the end of the waterfloods. We find that unless hysteresis caused by oil banking is accounted for in the relative permeability model, it is not possible to reconcile the experimental data sets. This hysteresis phenomenon, associated with oil invasion into previously established water channels, explains the rapid propagation of the oil bank. For the considered experiments, a simultaneous history match of good quality is obtained with the production and pressure data, and the simulated 2D saturation maps are in reasonable agreement with X-ray data. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and adaptive dynamic PNM, by comparing the simulated results with experimental data including saturation maps. It also highlights the important role of relative permeability hysteresis in the tertiary recovery of viscous oils by polymer injection.
Polymer flooding in very viscous oil has been gaining interest since its efficiency has been field proven. Multiple laboratory investigations have evidenced that the incremental oil recovered by the tertiary process increases considerably the recovery reached thanks to water flooding. However, such tertiary injection is made all the more complex that it is preceded by unstable displacement of oil by water. Therefore a better understanding of the physics is needed, in order to better predict and optimize the viscous oil reserves associated with tertiary polymer flooding. This work presents the interpretation of three similar tertiary polymer flood experiments carried out at the Centre for Integrated Petroleum Research (CIPR, Norway). Each experiment consisted in a water flood followed by a polymer flood. They involved the same Bentheimer outcrop sandstone, 2000 cP oil, 70 cP polymer solution, 2D slab geometry, but different slab lengths (2 slabs are 30cmx30cm, 1 slab is 30cmx90cm). Saturation evolution was monitored by X-ray. On the one hand, provided simple simulation assumptions, the three water floods under study could be history matched (production, pressure). Similar ratios between water and oil relative permeabilities were found, although the water flood relative permeabilities, matched with non Corey-type curves, reflected an important variability. On the other hand, the tertiary polymer floods were found challenging to match consistently. In particular, using classic history matching approaches, the history matching of the long slab experiment could not be reconciled with that of short slab experiments. Simulations were initialized with saturation maps obtained at the end of the water floods. None of the tested approaches enabled us to match consistently the short and long slab experiments together, unless a hysteresis model was implemented. Indeed, a memory effect was observed experimentally from the quantitative analysis of X-ray saturation maps and interpreted as a hysteresis phenomenon. This simple model, with two additional matching parameters, is then further validated by the comparison of 2D simulations with measured in situ saturations.
In this work we present the results obtained from a coreflood experiment with polymer injection in secondary mode for extra heavy oil at 5500 cP viscosity. The work was carried out on a 30 cm length reconstituted core composed from cleaned reservoir sand. The core was packed using an in-house developed method, and then saturated with live oil partially degassed in PVT cell from initial reservoir conditions down to expected pressure at start of a field test (Pres). Saturation profiles were accurately measured by means of X-Ray scans on the core, enabling the visualization of flow instability development (viscous fingering). Effluents were collected in carbon cells under reservoir conditions with X-Ray production level measurements. The effluents were then flashed to atmospheric conditions, collected in test tubes and re-measured by X-Ray and UV measurements. The polymer flood carried out in secondary mode showed excellent results with a recovery of around 60% after 1.8 PV of polymer injected at 1 cc/h, even though viscosity ratio was highly unfavourable. The estimated apparent viscosity of the polymer was 60 cP at 7 s -1 , corresponding to the frontal advancement rate achieved during the coreflood. This recovery is in the same order as that obtained in tertiary mode after water flood in outcrop cores (Wassmuth et al. 2009, Wassmuth et al. 2007).
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.
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