Polymer Flooding in a High Salinity Heavy-Oil Reservoir

Moreno

2019

BJPG

Self Cite

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.

Section: Resultsmentioning

confidence: 99%

“…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%

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

Moreno

2019

BJPG

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“…This work concerns only with the simulation and data history matching of four laboratory two-phase displacement tests using CMG-STARS. More details on the experimental work are given by Lopes et al [27], Silveira et al [44] and Ferreira and Moreno [14].…”

Section: Methodsmentioning

confidence: 99%

“…Note that the core-flooding data used in this work were obtained for the same salinity conditions, i.e., a 10.5% TDS multi-ionic brine [14,44]. Thus, we did not have to account for the salinity effect in the adsorption.…”

Section: Adsorptionmentioning

confidence: 99%

“…In this paper, we focus on history matching four polymer core-flooding tests for heavy oil recovery through simulation. The four displacement tests performed by Silveira et al [44] were conducted using core samples of sandstones and HPAM-ATBS solution prepared with high salinity/hardness synthetic-produced water. The injections were performed through a core holder with pressure monitor along the sample, collecting mass and volumes of injected and produced fluids over time.…”

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

History matching of experimental polymer flooding for enhanced viscous oil recovery

Zampieri

J Braz. Soc. Mech. Sci. Eng.

Quispe

et al. 2020

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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.

Rheology-based method for calculating polymer inaccessible pore volume in core flooding experiments

Moreno

2019

E3S Web Conf.

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Polymer flooding is an enhanced oil recovery (EOR) method that reduces the mobility ratio between the displaced oil and the displacing injected water. The flow of polymer solutions through porous media is subject to some process-specific phenomena, such as the inaccessible pore volume (IAPV). Due to IAPV, polymer molecules move faster through the porous medium than smaller ones. Thus the IAPV value needs to be accounted for in experiments and field projects. Recent reports found that polymer in-situ rheology correlates with the IAPV. The objective of this paper is to develop a method for estimating IAPV based on the in-situ rheology of polymers. The methodology proposed here can be used in both single- and two-phase experiments. The technique requires measurement of polymer resistance factor (RF) and residual resistance factor (RRF) at steady state conditions. Core permeability, porosity, and residual oil saturation, as well as water and polymer bulk viscosities, also need to be taken into account. Correlations for polymer in-situ viscosity and shear rate are solved simultaneously, to wield an estimative for the IAPV. Aiming at to prove the method, we report 16 core-flooding experiments, eight single- and eight two-phase experiments. We used a flexible polymer and sandstone cores. All the tests were run using similar rock samples. In the single-phase experiments, we compare the alternative method with the classic tracer method to estimate IAPV. The results show an average relative difference of 11.5% between the methods. The two-phase results display, on average, an 18% relative difference to the IAPV measured in the single-phase experiments. The difference between single- and two-phase results can be an effect of the higher shear rates experienced in the two-phase floodings since, in these cases, the aqueous phase shear rate is also dependent on the phase saturation. Additionally, temperature, core length, pore pressure, and iron presence on the core did not show any influence on the IAPV for our two-phase experiments. The method proposed in this paper is limited by the accuracy of the pressure drop measurements across the core. For flexible polymers, the method is valid only for low and mid shear rates, but, accoording to literature, for rigid polymers the method should be accurate for a broad range of shear rates. The method proposed here allows the measurement of polymer IAPV on two- and single- phase core-flooding experiments when a tracer is not used.