Heavy oil recovery by polymer flooding and hot water injection using numerical simulation

Rego, Fabio Bordeaux; Botechia, Vinícius Eduardo; Schiozer, Denis José

doi:10.1016/j.petrol.2017.03.033

Cited by 29 publications

(12 citation statements)

References 15 publications

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“…However, measurements of viscosity using a rheometer are much easier to obtain. Thus, some authors use rheometer viscosity data for HPAM polymer flooding simulation on the core scale [35] or field scale [3].…”

Section: Introductionmentioning

confidence: 99%

History matching of experimental polymer flooding for enhanced viscous oil recovery

Zampieri

Ferreira

Quispe

et al. 2020

J Braz. Soc. Mech. Sci. Eng.

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Polymer flooding has been widely studied and applied for enhancing reservoir oil recovery. The key to evaluating the potential application of polymer injection is based on a clear understanding of the mechanisms involved in the recovery process. This work focuses on history matching of laboratory core flooding of heavy oil recovery by polymer flooding. We match the experiments through a small-scale simulation model and evaluate the challenges of representing the polymer behavior in porous media. The methodology we propose in this paper aims to model core-flooding experiments with laboratory-measured data. These data come from different experiments, including rheology, single-and two-phase core flooding and are separated into consolidated and uncertain data. Consolidated data include: core volume, permeability, porosity, oil viscosity and density, initial saturation conditions, test temperature and injection rate. The uncertain input parameters involve more complex variables, such as viscosity behavior against shear rate and concentration, residual resistance factor, adsorption, inaccessible pore volume and water-oil relative permeabilities. We compare the simulation output parameters with laboratory results and evaluate the quality of the match for four different two-phase core-flooding experiments. The output parameters include histories for differential pressure, recovery factor, water cut and cumulative produced water, oil and liquid. Our results show that the simulation models successfully matched the experimental data, for all the cases, using appropriate representation of the laboratory parameters. The contribution of this work relies on the proposed methodology, which allows integrating the laboratory data in the construction and validation of core scale simulation models appropriately.

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Section: Introductionmentioning

confidence: 99%

History matching of experimental polymer flooding for enhanced viscous oil recovery

Zampieri

Ferreira

Quispe

et al. 2020

J Braz. Soc. Mech. Sci. Eng.

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“…Known as an abundant oil resource, heavy oil accounts for more than 70% of the total original oil in place (OOIP) worldwide, extensively occurring in South America, North America, East Asia and Middle East. − As conventional light oil has been increasingly consumed, it is particularly important to highlight the further development of heavy oil, , which however has been constrained by its high viscosity and the consequent low mobility ratio of the displacing aqueous phase to the displaced oil phase . Thermal-recovery methods, such as cyclic steam injection, steam flooding, and steam-assisted gravity drainage (SAGD), , are accordingly applied, as they can mobilize the heavy oil with high heat input and thus significantly improve the oil recovery. , Nevertheless, these methods are criticized to be uneconomical and environmentally unfriendly due to the high energy consumption and massive carbon dioxide release. , Moreover, wide application of these methods has been limited by cumbersome associated equipment and complicated operation processes of thermal recovery, especially when it comes to the application in the offshore oilfield . Therefore, it is vital to achieve high oil recovery by using chemical additives in a low thermal energy system.…”

Section: Introductionmentioning

confidence: 99%

“…They can reduce heavy oil viscosity by 80–90% and even 95–99% when mixed with some other surfactants. − Unfortunately, even when the reduction rate is more than 95%, most of the times remaining viscosity is still a few hundreds due to the high initial oil viscosity. Oil recovery efforts have been constrained by the inevitable negative mobility ratio of water to oil. , Therefore, it is significant to find one material that can increase the viscosity of the displacing phase while achieving a comparable viscosity reduction effect on displaced phase. In this context, amphiphilic polymers with hydrophilic and hydrophobic components are ideal candidates as they can increase the viscosity of the displacing aqueous phase by acrylamide dissolution while reducing the viscosity of the displaced oil phase by π–π interactions between a hydrophobic microenvironment formed by macromolecule aggregates and asphaltenes. − A viscosity reduction of more than 98% has been reported. − We envisage that increasing the temperature can promote further viscosity reduction when viscosity reduction is already high.…”

Section: Introductionmentioning

confidence: 99%

“…9,10 Nevertheless, these methods are criticized to be uneconomical and environmentally unfriendly due to the high energy consumption and massive carbon dioxide release. 11,12 Moreover, wide application of these methods has been limited by cumbersome associated equipment and complicated operation processes of thermal recovery, especially when it comes to the application in the offshore oilfield. 13 Therefore, it is vital to achieve high oil recovery by using chemical additives in a low thermal energy system.…”

Section: Introductionmentioning

confidence: 99%

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Amphiphilic-Polymer-Assisted Hot Water Flooding toward Viscous Oil Mobilization

Liu

Mendiratta

Chen

et al. 2019

Ind. Eng. Chem. Res.

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Heavy oil recovery is the most challenging part for the petroleum industry, and several techniques including steam and water injection are currently used that are either energy intensive, expensive, or less efficient. This study aims to evaluate a novel amphiphilic viscosity reducing polymer (DN-1) used along with hot water flooding for promoting viscous oil mobilization. Its performance for heavy oil mobilization was evaluated using viscosity measurements at different temperatures followed by core flooding experiments. Our results indicate that DN-1 at low concentrations could form 3D networks and stable aggregates. DN-1 featured good interfacial properties including low CMC, low IFT, and small contact angle. Even at low concentration it could form dynamic oil in water emulsions, thereby causing easy emulsification and fast demulsification. The injection pressure of DN-1 was much smaller than that of the conventional polymers or associative polymers used for heavy oil development and is beneficial for oil recovery in real reservoir scenarios where a high-pressure gradient cannot be achieved. Interestingly, unlike polymer flooding, this amphiphilic polymer increased displacing phase viscosity, while it simultaneously reduced the displaced oil viscosity. Finally, DN-1-assisted hot water flooding could impressively achieve an ultimate recovery factor of 75.7% at 115 °C that was similar to that by hot water flooding at 175 °C. Even when DN-1 was injected at 55 °C, which was the reservoir temperature, the oil recovery factor was still 12.8% higher than hot water flooding, proving it as an efficient material in improving heavy oil recovery at low temperatures. As per our knowledge, this is the first report on the use of amphiphilic-polymer-assisted hot water flooding for heavy oil recovery.

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“…Moreover, commercial simulation software, such as ECLIPSE and the Computer Modeling Group (CMG) GEM, have also poorly treated polymer degradation [30]. To improve polymer flooding simulation, some methods have been proposed [31,32]. The first-order concentration attenuation model was used to characterize polymer concentration reduction during polymer flooding and could be embedded into the polymer mass conservation equations in simulation [33].…”

Section: Introductionmentioning

confidence: 99%

Effect of Polymer Degradation on Polymer Flooding in Heterogeneous Reservoirs

Xin

Chen

et al. 2018

Polymers

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Polymer degradation is critical for polymer flooding because it can significantly influence the viscosity of a polymer solution, which is a dominant property for polymer enhanced oil recovery (EOR). In this work, physical experiments and numerical simulations were both used to study partially hydrolyzed polyacrylamide (HPAM) degradation and its effect on polymer flooding in heterogeneous reservoirs. First, physical experiments were conducted to determine basic physicochemical properties of the polymer, including viscosity and degradation. Notably, a novel polymer dynamic degradation experiment was recommended in the evaluation process. Then, a new mathematical model was proposed and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed to examine both polymer static and dynamic degradation. The designed simulator was validated by comparison with the simulation results obtained from commercial software and the results from the polymer flooding experiments. This simulator further investigated and validated polymer degradation and its effect. The results of the physical experiments showed that the viscosity of a polymer solution increases with an increase in polymer concentration, demonstrating their underlying power law relationship. Moreover, the viscosity of a polymer solution with the same polymer concentration decreases with an increase in the shear rate, demonstrating shear thinning. Furthermore, the viscosity of a polymer solution decreased with an increase in time due to polymer degradation, exhibiting an exponential relationship. The first-order dynamic degradation rate constant of 0.0022 day−1 was greater than the first-order static degradation rate constant of 0.0017 day−1. According to the simulation results for the designed simulator, a 7.7% decrease in oil recovery, after a cumulative injection volume of 1.67 pore volume (PV) was observed between the first-order dynamic degradation rate constants of 0 and 0.1 day−1, which indicates that polymer degradation has a detrimental effect on polymer flooding efficiency.

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Heavy oil recovery by polymer flooding and hot water injection using numerical simulation

Cited by 29 publications

References 15 publications

History matching of experimental polymer flooding for enhanced viscous oil recovery

History matching of experimental polymer flooding for enhanced viscous oil recovery

Amphiphilic-Polymer-Assisted Hot Water Flooding toward Viscous Oil Mobilization

Effect of Polymer Degradation on Polymer Flooding in Heterogeneous Reservoirs

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