Tertiary Polymer Flooding Research Articles

IMMISCIBLE VISCOUS FINGERING MODELING OF TERTIARY POLYMER FLOODING BASED ON REAL CASE OF HEAVY OIL RESERVOIR MODEL

In immiscible displacements, lower viscosity injected fluids with higher mobility than crude oil can create viscous fingers, affecting displacement efficiency. The Buckley–Leverett approach for relative permeabilities (kr) may not represent accurately 2D features like increased water saturation in viscous fingering. Based on the physics issue, this work applies Sorbie's 4-Steps methodology to a 3D simulation of an offshore heavy oil reservoir focusing on waterflooding and tertiary polymer flooding, assessing their impact on oil production forecasts. It also explores the application of this methodology to coarse grid simulation models, employing pseudo kr functions by data assimilation. During tertiary polymer injection, two processes were identified in oil displacement: viscous crossflow mechanism and oil bank mobilization by a second finger. This combination resulted in earlier and increased oil production. For both strategies, refining the grid increased simulation runtime from minutes to days compared to coarse grids, making it impractical for intensive processes. From data assimilation, the best solution with matched field indicators reduced runtime from days to minutes. This study expanded the 4-Steps methodology for 3D reservoir simulation, proposing kr as uncertainties. Data assimilation enhances the methodology, generating pseudo kr for coarser grid simulations, reducing computational costs, and capturing small-scale phenomena.

MODEL-BASED ANALYSIS TO EVALUATE THE EFFECT OF POLYMER PROPERTIES AND PHYSICAL PHENOMENA ON POLYMER FLOODING OPERATIONS

Polymer flooding, known for enhancing heavy oil displacement, may encounter efficiency-limiting physical phenomena. This work assesses the impact of key factors like viscosity, shear rate, and adsorption in field applications using a model-based approach on the EPIC001 case, a real offshore Brazilian heavy oil reservoir. In simulation results, increasing the displacing fluid viscosity using apparent or zero-shear functions, oil production and economic returns show improvements over waterflooding. The shear rate effect slightly increases oil production and enhances injectivity loss due to shear-thinning in polymer flow. However, modeling it increases computation costs, as it extends simulation run time from minutes to days, making it impractical for intensive processes like production optimization. An analysis of the method’s effectiveness shows that it varies based on the adsorption level considered. At its highest value, even with a higher oil recovery factor, the economic return was lower than using waterflooding. Combining shear rate and adsorption has a minimal impact on field indicators when compared to adsorption alone. This work enhances the comprehension of physical phenomena and non-Newtonian behavior in tertiary polymer flooding on heavy oil reservoirs and its impact on the production forecast. It also highlights important considerations for modeling-based procedures.

Immiscible Viscous Fingering: The Simulation of Tertiary Polymer Displacements of Viscous Oils in 2D Slab Floods.

Immiscible viscous fingering in porous media occurs when a high viscosity fluid is displaced by an immiscible low viscosity fluid. This paper extends a recent development in the modelling of immiscible viscous fingering to directly simulate experimental floods where the viscosity of the aqueous displacing fluid was increased (by the addition of aqueous polymer) after a period of low viscosity water injection. This is referred to as tertiary polymer flooding, and the objective of this process is to increase the displacement of oil from the system. Experimental results from the literature showed the very surprising observation that the tertiary injection of a modest polymer viscosity could give astonishingly high incremental oil recoveries (IR) of ≥100% even for viscous oils of 7000 mPa.s. This work seeks to both explain and predict these results using recent modelling developments. For the 4 cases (µo/µw of 474 to 7000) simulated in this paper, finger patterns are in line with those observed using X-ray imaging of the sandstone slab floods. In particular, the formation of an oil bank on tertiary polymer injection is very well reproduced and the incremental oil response and water cut drops induced by the polymer are very well predicted. The simulations strongly support our earlier claim that this increase in incremental oil displacement cannot be explained solely by a viscous “extended Buckley-Leverett” (BL) linear displacement effect; referred to in the literature simply as “mobility control”. This large response is the combination of this effect (BL) along with a viscous crossflow (VX) mechanism, with the latter VX effect being the major contributor to the recovery mechanism.

The Role of Immiscible Fingering on the Mechanism of Secondary and Tertiary Polymer Flooding of Viscous Oil

Immiscible viscous fingering in porous media occurs when a low viscosity fluid displaces a significantly more viscous, immiscible resident fluid; for example, the displacement of a higher viscosity oil with water (where μo > > μw). Classically, this is a significant issue during oil recovery processes, where water is injected into the reservoir to provide pressure support and to drive the oil production. In moderate/heavy oil, this leads to the formation of strong water fingers, bypassed oil and high/early water production. Polymer flooding, where the injected water is viscosified through addition of high molecular weight polymers, has often been applied to reduce the viscosity contrast between the two immiscible fluids. In recent years, there has been significant development in the understanding of both the mechanism by which polymer flooding improves viscous oil recovery, as well as in the methodologies available to directly simulate such processes. One key advance in modelling the correct mechanism of polymer oil recovery in viscous oils has been the development of a method to accurately model the “simple” two-phase immiscible fingering (Sorbie in Transp Porous Media 135:331–359, 2020). This was achieved by first choosing the correct fractional flow and then deriving the maximum mobility relative permeability functions from this. It has been proposed that central to the polymer oil recovery is a fingering/viscous crossflow mechanism, and a summary of this is given in this paper. This work seeks to validate the proposed immiscible fingering/viscous crossflow mechanism experimentally for a moderately viscous oil (μo = 84 mPa.s at 31 °C; μw = 0.81 mPa.s; thus, (μo/μw) ~ 104) by performing a series of carefully monitored core floods. The results from these experiments are simulated directly to establish the potential of our modified simulation approach to capture the process (Sorbie, et al., 2020). Both secondary and tertiary polymer flooding experiments are presented and compared with the waterflood baselines, which have been established for each core system. The oil production, water cut and differential pressure are then matched directly using a commercial numerical reservoir simulator, but using our new “fractional flow” derived relative permeabilities. The use of polymer flooding, even when applied at a high water cut (80% after 0.5 PV of water injection), showed a significant impact on recovery; bringing the recovery significantly forward in time for both tertiary and secondary polymer injection modes—a further 13–16% OOIP. Each flood was then directly matched in the simulator with excellent agreement in all experimental cases. The simulations allowed a quantitative visualisation of the immiscible finger propagation from both water injection and the banking of connate water during polymer flooding. Evidence of a strong oil bank forming in front of the tertiary polymer slug was also observed, in line with the proposed viscous crossflow mechanism. This work provides validation of both polymer flooding’s viscous crossflow mechanism and the direct simulation methodology proposed by Sorbie et al. (Transp Porous Media 135:331–359, 2020). The experimental results show the significant potential for both secondary and tertiary polymer flooding in moderate/heavy oil reservoirs.

On the Modelling of Immiscible Viscous Fingering in Two-Phase Flow in Porous Media

Viscous fingering in porous media is an instability which occurs when a low-viscosity injected fluid displaces a much more viscous resident fluid, under miscible or immiscible conditions. Immiscible viscous fingering is more complex and has been found to be difficult to simulate numerically and is the main focus of this paper. Many researchers have identified the source of the problem of simulating realistic immiscible fingering as being in the numerics of the process, and a large number of studies have appeared applying high-order numerical schemes to the problem with some limited success. We believe that this view is incorrect and that the solution to the problem of modelling immiscible viscous fingering lies in the physics and related mathematical formulation of the problem. At the heart of our approach is what we describe as the resolution of the “M-paradox”, where M is the mobility ratio, as explained below. In this paper, we present a new 4-stage approach to the modelling of realistic two-phase immiscible viscous fingering by (1) formulating the problem based on the experimentally observed fractional flows in the fingers, which we denote as f_{rm w}^{*} , and which is the chosen simulation input; (2) from the infinite choice of relative permeability (RP) functions, k_{rm rw}^{*} and k_{rm ro}^{*} , which yield the same f_{rm w}^{*} , we choose the set which maximises the total mobility function, lambda_{text{T}}^{{}} (where lambda_{text{T}}^{{}} = lambda_{text{o}}^{{}} + lambda_{text{w}}^{{}} ), i.e. minimises the pressure drop across the fingering system; (3) the permeability structure of the heterogeneous domain (the porous medium) is then chosen based on a random correlated field (RCF) in this case; and finally, (4) using a sufficiently fine numerical grid, but with simple transport numerics. Using our approach, realistic immiscible fingering can be simulated using elementary numerical methods (e.g. single-point upstreaming) for the solution of the two-phase fluid transport equations. The method is illustrated by simulating the type of immiscible viscous fingering observed in many experiments in 2D slabs of rock where water displaces very viscous oil where the oil/water viscosity ratio is (mu_{text{o}} /mu_{text{w}} ) = 1600 . Simulations are presented for two example cases, for different levels of water saturation in the main viscous finger (i.e. for 2 different underlying f_{rm w}^{*} functions) produce very realistic fingering patterns which are qualitatively similar to observations in several respects, as discussed. Additional simulations of tertiary polymer flooding are also presented for which good experimental data are available for displacements in 2D rock slabs (Skauge et al., in: Presented at SPE Improved Oil Recovery Symposium, 14–18 April, Tulsa, Oklahoma, USA, SPE-154292-MS, 2012. https://doi.org/10.2118/154292-MS, EAGE 17th European Symposium on Improved Oil Recovery, St. Petersburg, Russia, 2013; Vik et al., in: Presented at SPE Europec featured at 80th EAGE Conference and Exhibition, Copenhagen, Denmark, SPE-190866-MS, 2018. https://doi.org/10.2118/190866-MS). The finger patterns for the polymer displacements and the magnitude and timing of the oil displacement response show excellent qualitative agreement with experiment, and indeed, they fully explain the observations in terms of an enhanced viscous crossflow mechanism (Sorbie and Skauge, in: Proceedings of the EAGE 20th Symposium on IOR, Pau, France, 2019). As a sensitivity, we also present some example results where the adjusted fractional flow ( f_{rm w}^{*} ) can give a chosen frontal shock saturation, S_{rm wf}^{*} , but at different frontal mobility ratios, M(S_{rm wf}^{*} ) . Finally, two tests on the robustness of the method are presented on the effect of both rescaling the permeability field and on grid coarsening. It is demonstrated that our approach is very robust to both permeability field rescaling, i.e. where the (kmax/kmin) ratio in the RCF goes from 100 to 3, and also under numerical grid coarsening.

Exact Solution for Tertiary Polymer Flooding with Polymer Mechanical Entrapment and Adsorption

Two-phase transport with simultaneous component adsorption and mechanical entrapment occurs in numerous suspension and nano-colloidal flows in porous media, including polymer flooding in oilfields. To the contrary of one-dimensional (1D) self-similar solution for polymer flooding that ignores the mechanical entrapment, accounting for this phenomenon breaks self-similarity. However, this non-self-similar problem allows for an exact integration. For the first time, the present work derives an exact solution for polymer injection into a rock saturated by oil and water with simultaneous adsorption and mechanical entrapment. The splitting method that uses Lagrangian coordinate as an independent variable instead of time, splits the 3 × 3 governing system into 2 × 2 auxiliary system that determines suspended and captured polymer concentrations, and the scalar equation for unknown phase saturation. The exact solution reveals two fingerprints of the component entrapment under small entrapped concentrations: stabilisation of the breakthrough concentration at the value below the injected one, and non-stabilised pressure drop growth. Three sets of laboratory polymer core-floodings exhibit a close match by the analytical model.

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

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.

Effect of Layering on Incremental Oil Recovery From Tertiary Polymer Flooding

Summary It has been demonstrated in both laboratory measurements and field applications that tertiary polymer flooding can enhance oil recovery from heterogeneous reservoirs, primarily through macroscopic sweep (conformance). This study quantifies the effect of layering on tertiary polymer flooding as a function of layer-permeability contrast, the timing of polymer flooding, the oil/water-viscosity ratio, and the oil/polymer-viscosity ratio. This is achieved by analyzing the results from fine-grid numerical simulations of waterflooding and tertiary polymer flooding in simple layered models. We find that there is a permeability contrast between the layers of the reservoir at which maximum incremental oil recovery is obtained, and this permeability contrast depends on the oil/water-viscosity ratio, polymer/water-viscosity ratio, and onset time for the polymer flood. Building on an earlier formulation that describes whether a displacement is understable or overstable, we present a linear correlation to estimate this permeability contrast. The accuracy of the newly proposed formulation is demonstrated by reproducing and predicting the permeability contrast from existing flow simulations and further flow simulations that have not been used to formulate the correlation. This correlation will enable reservoir engineers to estimate the combination of permeability contrast, water/oil-viscosity ratio, and polymer/water-viscosity ratio that will give the maximum incremental oil recovery from tertiary polymer flooding in layered reservoirs regardless of the timing of the start of polymer flooding. This could be a useful screening tool to use before starting a full-scale simulation study of polymer flooding in each reservoir.

Upscaling of polymer adsorption

This article considers upscaling of polymer adsorption. Input to adsorption values employed in reservoir simulation models are typically obtained from core plug measurements. There are several orders of magnitude in scale difference between core plugs and grid cells in reservoir simulation models, which foster a need for upscaling of the adsorption values.Polymer concentration distribution on the lithofacies scale is investigated in this article. The effect of diffusion on concentration distribution is investigated analytically. The slow diffusion of polymer molecules retards mixing even at the lithofacies scale. We introduce a formula to estimate the redistribution of polymer due to capillary forces in a layered model, and this formula is validated through numerical simulations. From our considerations we conclude that it is questionable to assume a constant polymer concentration in lithofacies models. This impedes applying steady-state upscaling techniques. Such upscaling techniques will over-predict polymer adsorption.Different methods for upscaling adsorption are presented in this paper, and applied to a simplified layered model and to more realistic fine-scale numerical models based on the SPE10 model. These numerical models were populated with adsorption values obtained from published experiments conducted on samples from the Brent sequence modeled in SPE10. Simulations of tertiary polymer flooding on the upscaled models were compared to simulations of the same flooding sequences on the original fine scale models. The tested upscaling methods include a volume averaging technique employed by other authors, and a method were we distribute the adsorption values by the same functional relationship as in the fine scale model. In addition we introduce upscaling methods were we assign zero adsorption to fine scale grid cells with permeability below a given cut-off value. The cut-off value is obtained from a single phase simulation on the fine scale model. In our models the cut-off value methods yield the best match between the coarse scale and fine scale simulation results. The volume averaging technique over-predict the polymer adsorption.Results from both the lithofacies and geomodel scale indicate a tendency to over-predict polymer adsorption, which could lead to conservative estimates for the effect of polymer flooding.

Numerical Modeling of Unstable Waterfloods and Tertiary Polymer Floods Into Highly Viscous Oils

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.

Numerical Modeling of Unstable Waterfloods and Tertiary Polymer Floods for Viscous Oils

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182638, “Numerical Modeling of Unstable Waterfloods and Tertiary Polymer Floods For Highly Viscous Oils,” by R. de Loubens, SPE, G. Vaillant, M. Regaieg, J. Yang, A. Moncorgé, SPE, C. Fabbri, and G. Darche, SPE, Total, prepared for the 2017 SPE Reservoir Simulation Conference, Montgomery, Texas, USA, 20–22 February. The paper has not been peer reviewed. The saturation distribution after unstable waterflooding for 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. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and an adaptive dynamic prenetwork model, 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. Introduction Waterflooding into viscous oils can lead to severe viscous fingering of the injected water—a well-known type of instability in porous-media flow that is intrinsically related to the viscosity contrast between the displaced fluid (oil) and the displacing fluid (water). A direct consequence of this phenomenon is a significant bypassing of the oil in place and a low recovery factor, as observed at both laboratory scale and field scale. Viscous instabilities between two immiscible fluids are dependent not only on the viscosity ratio but also on the capillary number and rock wettability. In particular, experimental studies have shown that the effect of viscous fingering strongly increases when the displacing fluid gets less wetting than the displaced fluid (i.e., when going from imbibition to drainage). In order to reduce or eliminate hydrodynamic instabilities, polymer flooding can be implemented as a secondary or tertiary recovery mechanism. This work considers three waterflood and tertiary-polymer-flood experiments conducted on Bentheimer sandstone slabs with heavy oils with viscosity of approximately 2,000 and 7,000 cp, under nonwater-wet conditions. These experiments belong to a series of heavy-oil- displacement experiments whose objective was to investigate the effect on oil recovery of various parameters, such as oil viscosity, slab length, and injection pattern. Besides standard measurements of fluid production and differential pressures, an X-ray scanner was used to visualize the spatial distribution of the fluids as a function of time.