Polymer flow through water- and oil-wet porous media

Hatzignatiou, D.G.; Moradi, H.; Stavland, Arne

doi:10.1016/s1001-6058(15)60537-6

Cited by 19 publications

(6 citation statements)

References 8 publications

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“…Polymer cannot enter some small pores when the polymer solution flows through the rock, which results in an inaccessible pore volume [47]. Here, the inaccessible pore volume is treated by a factor of fipv, which is given as: fipv=ViVp where Vi is the polymer inaccessible pore volume in m 3 and Vp is the pore volume in m 3 .…”

Section: Methodsmentioning

confidence: 99%

Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Xin

Chen

et al. 2018

Polymers

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The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

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Section: Methodsmentioning

confidence: 99%

Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Xin

Chen

et al. 2018

Polymers

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“…Polymers are molecular clusters with a certain hydrodynamic radius, and there are some inaccessible small pores in the process of formation substitution of crude oil, thus forming an inaccessible pore volume, which affects the flow of polymer solutions in porous media. 40,41 The inaccessible pore volume is mainly influenced by the physical properties of the reservoir rock itself and the molecular weight of the polymer. 42 (4) Adsorption properties.…”

Section: Introductionmentioning

confidence: 99%

Simulated evaluation of the degradation of hydrophobically associative polymers in the formation

Qi,

Shu,

Luo

2023

J of Applied Polymer Sci

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In this work, indoor physical simulation experiments were used to examine the effects of shear, thermal, chemical, and microbial degradation on the properties of the hydrophobic associative polymer AP‐P4. It was discovered that the viscosity of the polymer solution generally decreased as the shear time was extended. The larger the shear strength, the lower the solution viscosity. Fitting of the nonlinear equation of solution viscosity with shear time, η = 12,988 t−1.08. When thermal degradation started, the solution viscosity first started to rise, however, this phase was just a short one. The viscosity of the solution gradually started to decrease as the thermal degradation period grew. In addition, the trends of properties like hydrokinetic radius, hydrophobic connectivity, and hydrolysis essentially followed the same patterns as those of solution viscosity. At the beginning of the degradation process, the viscosity retention of the polymer solution without oxygen is significantly higher than that of the aerobic environment. However, the difference between the two becomes smaller as the degradation time increases. In addition, the AP‐P4 had good temperature resistance and aging resistance capabilities when iron ions were present. Finally, it was discovered that AP‐P4 had a strong antibacterial effect, which decreased the viscosity brought on by microbial action.

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“…Interactions play an important role in polymer flooding efficiency and may cause changes in both the pore space (clogged pores and decreased pore sizes) and rock surface characteristics. The effects of polymer/rock interactions include disproportionate permeability reduction (DPR); where a polymer flood subsequently reduces water relative permeability without having a similar effect on oil relative permeability (see [7,8]), polymer retention (see [9]) and wettability changes. The interaction effects are often different sides of the same story, hence, the wettability parameter has been discussed alongside DPR and retention.…”

Section: Introductionmentioning

confidence: 99%

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging

et al. 2022

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Polymers have been used as viscosifying agents in enhanced oil recovery applications for decades, but their influence on rock surface wettability is rarely discussed relative to its importance: wettability largely controls fluid flow in porous media and changes in wettability may significantly influence subsequent system performance. This paper presents a two-part systematic investigation of wettability alteration during polymer injection into oil-wet limestone. The first part of the paper determines wettability and wetting stability on the core scale. The well-established Amott–Harvey method is used, and five full cycles performed with repeated spontaneous imbibition and forced displacements. Wettability alterations are measured in a polymer/oil system, to determine polymer influence on wettability, and evaluated towards simpler brine/oil and glycerol/oil systems, to determine reproducibility and uncertainty related to the method and fluid/rock system. Polymer injection into oil-wet limestone core plugs is shown to repeatedly and reproducibly reverse the core wettability towards water-wet. Wettability changed both quicker and towards stronger water-wet conditions with polymer solution as the aqueous phase compared to brine and glycerol. The second part of the paper attempts to explain the observed behavior; by utilizing in situ imaging by Positron Emission Tomography, an emerging imaging technology within the geosciences. High resolution imaging provides insight into fluid flow dynamics during water and polymer injections, identifying uneven displacement fronts and significant polymer adsorption.

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Polymer flow through water- and oil-wet porous media

Cited by 19 publications

References 8 publications

Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Simulated evaluation of the degradation of hydrophobically associative polymers in the formation

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging

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