Impact of flow rate variation in dynamic properties of a terpolymer in sandstone

Ferreira, Vitor Hugo; Moreno, Rosângela Barros Zanoni Lopes

doi:10.1016/j.petrol.2017.07.071

Cited by 13 publications

(20 citation statements)

References 16 publications

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“…The polymer referenced to in the study was a synthetic terpolymer composed of polyacrylamide, acrylic acid, and ATBS (Flopaam 5115 SH) with a molecular weight between 14 and 16 million Daltons, and 15% hydrolysis degree (Ferreira & Moreno, 2017b;Silveira et al, 2018).…”

Section: Methodsmentioning

confidence: 99%

“…Therefore, one can see that the IAPV effect on the in-situ viscosity has a much more meaningful impact on the injection/production performance than the direct IAPV effect. Based on our laboratory scale simulation study and current literature on experimental polymer behavior in porous media (Ferreira & Moreno, 2017b;Stavland et al, 2010), one can say that FPF3 is the most realistic case studied in this paper and, therefore, it should be used in any polymer flooding modeling or simulation.…”

Section: Field Scalementioning

confidence: 99%

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Polymer Apparent Viscosity Dependence on Inaccessible Pore Volume: Laboratory and Field Studies of Its Influence on Enhanced Oil Recovery

Ferreira

Moreno

2019

BJPG

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The successful use of polymer-enhanced oil recovery observed in the last two decades is leading to effective field implementations. One of the reasons for such positive results in polymer flooding is the integration between laboratory-measured properties and reservoir simulation. Recent reports show that inaccessible pore volume (IAPV) plays a significant role in the apparent viscosity of random coil polymers, such as hydrolyzed polyacrylamide (HPAM). This paper assesses both direct and indirect impacts of IAPV on polymer flooding. This investigation relies on laboratory and field-scale simulations of polymer flooding using CMG-STARS. Simulation cases review the effects of IAPV on production indicators in direct and indirect forms. This study compares laboratory-scale simulations with experimental results and uses quality indicators to evaluate the history matching of both approaches. It relies on a modified benchmark field case to study both approaches in comparison to waterflooding and idealized polymer flooding. Results indicate that IAPV has a small direct impact on production curves. However, data show significant indirect implications of the IAPV on recovery. This effect occurs because the apparent viscosity of HPAM has a direct relationship with IAPV. Although the simulation results were consistent with current literature, the results obtained through the experiments indicate that the most realistic simulation case is achieved when considering the impact of IAPV on polymer viscosity.

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Section: Methodsmentioning

confidence: 99%

Section: Field Scalementioning

confidence: 99%

Polymer Apparent Viscosity Dependence on Inaccessible Pore Volume: Laboratory and Field Studies of Its Influence on Enhanced Oil Recovery

Ferreira

Moreno

2019

BJPG

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“…One polymer bank of 10 PV size is injected to establish an initial equilibrium of polymer retention. Successively, the irreversible retention is reached by the brine bank injection as post flush of 15 PV size (Ferreira and Moreno;. Finally, assuming that no further retention and desorption occur, 10 PV polymer bank is injected so the inaccessible pore volume effect can be determined.…”

Section: Dynamic Retention Measurementmentioning

confidence: 99%

“…2). Different authors as Lotsch et al (1985), Hugues et al (1990), Osterloh and Law (1998), Zhang and Seright (2014), Zhang and Seright (2015), Wan andSeright, 2016, Ferreira andMoreno (2017) have used this method successfully.…”

Section: Dynamic Retention Measurementmentioning

confidence: 99%

“…The inaccessible pore volume is one of the factors that most affect the polymer retention and it is defined as the pore volume fraction that the polymer molecules were not able to access, but accessible to the small solvent and salt molecules during the polymer flooding. (Dawson and Lantz, 1972;Szabo, 1975;Gupta, 1978;Lotsch et al, 1985;Huh et al, 1990;Hughes et al, 1990;Mezzomo et al, 2002;Pancharoen et al, 2010;Ferreira and Moreno;. IPV causes an acceleration on polymer propagation, meanwhile, polymer retention delays this propagation (Zhang and Seright, 2014).…”

Section: Introductionmentioning

confidence: 99%

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Less-Concentrated HPAM Solutions as a Polymer Retention Reduction Method in CEOR

Lizcano¹,

Ferreira²,

Moreno³

2020

Rev. fuentes reventón enrg.

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Polymer Flooding has become one of the most implemented EOR techniques, due to three factors: First, Polymer flooding has expanded the range of the screening criteria parameters. Second, this EOR method is more effective than water injection, while handling water management issues in high water-cut reservoirs. Nevertheless, polymer retention can turn a viable technical project into an uneconomical one. Polymer loss due to retention is an inevitable phenomenon, which happens during injection processes. The development of experimental analysis aiming to minimize or reduce polymer loss from the displacing fluid bank is beneficial to broaden the application of this CEOR method. This experimental work evaluated the injection schemes aiming to reduce polymer retention in porous media. The approach consisted of injecting less-concentrated polymer banks followed for the main polymer bank designed for mobility control. An experimental methodology to quantify polymer retention due to each injected polymer bank, cumulative polymer retention, resistance factor, residual resistance factor and inaccessible pore volume (IPV) was developed. The measurement process was based on the injection of 20 PV polymer banks at a constant flow rate of 1ml/min at 25°C, separated by 30 PV brine banks. Two HPAM with molecular weights of 6-8 million and 20 million Daltons using 350mD and 5000 mD sandstone cores were tested, respectively. The HPAM solutions considering a Colombian field (0.7% NaCl) and seawater (3.5% TDS) salinities were prepared. All rock samples were previously submitted to the injection of 50 PV for preventing fines migration. Two injection schemes with variable polymer concentrations were performed: The first one in which the polymer concentration increased in each successive bank, and the second one in which the concentration decreased. HPAM concentration solutions from 50 ppm to 2000 ppm were sequentially used in both injection schemes. By comparing the results of these two schemes, the effect of the injection of the less-concentrated polymer solutions was evaluated. For the increasing concentration experiments, cumulative retention values of 175.7 μg/g and 58.9 μg/g were calculated for the low-molecular weight polymer and the high-molecular weight polymer, respectively. While comparing with decreasing concentration experiments, for the high-molecular weight HPAM a 19% of retention reduction was evidenced, but no retention reduction was observed for the low-molecular weight one. The results indicate that different retention mechanisms are strongly dependents on the absolute permeability of the samples. Additionally, IPV values of 0.5 PV and 0.25 PV were calculated using low and high permeability samples, respectively. There was no linear relation between the absolute permeability reduction and the polymer concentration of the first bank injected into the sample. The novelty of this work is to use sacrificial banks of less-concentrated HPAM solutions as a reducing retention agent for the polymer bank designed for mobility control.

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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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Impact of flow rate variation in dynamic properties of a terpolymer in sandstone

Cited by 13 publications

References 16 publications

Polymer Apparent Viscosity Dependence on Inaccessible Pore Volume: Laboratory and Field Studies of Its Influence on Enhanced Oil Recovery

Polymer Apparent Viscosity Dependence on Inaccessible Pore Volume: Laboratory and Field Studies of Its Influence on Enhanced Oil Recovery

Less-Concentrated HPAM Solutions as a Polymer Retention Reduction Method in CEOR

History matching of experimental polymer flooding for enhanced viscous oil recovery

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