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A special issue of Polymers (ISSN 2073-4360). This special issue belongs to the section "Polymer Processing and Engineering".

Deadline for manuscript submissions: closed (25 August 2022) | Viewed by 17822

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Dr. Arne Skauge

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Centre for Integrated Petroleum Research, Uni Research AS CIPR, Allegaten 41, Bergen, Norway
Interests: polymer flooding; in situ rheology in a porous medium; simulation of polymer flow in a porous medium; polymer retention; polymer resistance factor (RF)—residual resistance factor (RRF); polymer applications and field trials; polymer flow at adverse mobility; polymer mechanical degradation; polymer thermal stability; polymer adsorption; polymer injectivity; polymer–rock interactions

Special Issue Information

Dear Colleagues,

Polymer flooding is the most frequently implemented chemical enhanced oil recovery process and has received increased attention since several successful large-scale polymer flood projects were reported in the literature. It has primarily been used to accelerate oil production through sweep improvement. However, promising results have emerged in recent years, suggesting it may be able to mobilize capillary trapped oil as well. During polymer flooding, the injection brine is viscosified by adding water-soluble polymers, thereby stabilizing the displacement process by means of improved mobility ratio between oil and water. Many field tests have shown acceleration of oil production due to oil crossflow into high water saturation areas, either into water fingers or permeability layers. Articles on field results are encouraged, and this invitation also extends to field problems and polymer injectivity.

The extensive research effort has changed the perception of polymer flooding from a simple augmented water flood toward being identified as an extremely complex EOR process. This is mainly due to the non-Newtonian nature of water-soluble polymers as they flow through porous media. Despite intensive research, significant controversy and uncertainties are still associated with several topics within polymer flooding technology. One of these topics is polymer in situ porous medium rheology. Articles on bulk and in situ rheology are requested, and also modelling and experimental results on porous medium rheology. Studies of the impact of rheology; salinity; polymer structure; polymer molecular weight; flow geometry; retention; adsorption; mechanical degradation; and mobility ratio on oil recovery are key elements for improving our understanding of polymer flooding potential.

Prof. Dr. Arne Skauge
Guest Editor

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Keywords

Polymer flooding
Field case studies
Operational problems
Polymer injectivity
Water-soluble in situ polymer rheology
Impact of polymer structure, molecular weight, flow geometry on in situ rheology
Impact of rheology and mobility ratio on oil recovery
Impact of mechanical degradation on polymer injectivity
Polymer retention and adsorption in porous media
Impact of polymer retention on oil mobilization
Simulation of polymer flow in porous media
Polymer flow in porous medium

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Published Papers (6 papers)

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Research

19 pages, 4732 KiB

Open AccessArticle

Influence of Polymer Viscoelasticity on Microscopic Remaining Oil Production

by Yiqun Yan, Lihui Wang, Guoqiang Sang and Xu Han

Polymers 2022, 14(5), 940; https://doi.org/10.3390/polym14050940 - 26 Feb 2022

Cited by 3 | Viewed by 2022

Abstract

To investigate the impact of polymer viscoelasticity on microscopic remaining oil production, this study used microscopic oil displacement visualisation technology, numerical simulations in PolyFlow software, and core seepage experiments to study the viscoelasticity of polymers and their elastic effects in porous media. We analysed the forces affecting the microscopic remaining oil in different directions, and the influence of polymer viscoelasticity on the displacement efficiency of microscopic remaining oil. The results demonstrated that the greater the viscosity of the polymer, the greater the deformation and the higher the elasticity proportion. In addition, during the creep recovery experiment at low speed, the polymer solution was mainly viscous, while at high speed it was mainly elastic. When the polymer viscosity reached 125 mPa·s, the core effective permeability reached 100 × 10⁻³ μm², and the equivalent shear rate exceeded 1000 s⁻¹, the polymer exhibited an elastic effect in the porous medium and the viscosity curve displayed an ‘upward’ phenomenon. Moreover, the difference in the normal deviatoric stress and horizontal stress acting on the microscopic remaining oil increased exponentially as the viscosity of the polymer increased. The greater the viscosity of the polymer, the greater the remaining oil deformation. During the microscopic visualisation flooding experiment, the viscosity of the polymer, the scope of the mainstream line, and the recovery factor all increased. The scope of spread in the shunt line area significantly increased, but the recovery factor was significantly lower than that in the mainstream line. The amount of remaining oil in the unaffected microscopic area also decreased. Full article

(This article belongs to the Special Issue Polymer Flooding and Rheology)

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16 pages, 3335 KiB

Open AccessArticle

Study on Micro Production Mechanism of Corner Residual Oil after Polymer Flooding

by Xianda Sun, Mengqing Zhao, Xiaoqi Fan, Yongsheng Zhang, Chengwu Xu, Lihui Wang and Guoqiang Sang

Polymers 2022, 14(5), 878; https://doi.org/10.3390/polym14050878 - 23 Feb 2022

Cited by 4 | Viewed by 1811

Abstract

To study the microscopic production mechanism of corner residual oil after polymer flooding, microscopic visualization oil displacement technology and COMSOL finite element numerical simulation methods were used. The influence of the viscosity and interfacial tension of the oil displacement system after polymer flooding on the movement mechanism of the corner residual oil was studied. The results show that by increasing the viscosity of the polymer, a portion of the microscopic remaining oil in the corner of the oil-wet property can be moved whereas that in the corner of the water-wet property cannot be moved at all. To move the microscopic remaining oil in the corners with water-wet properties after polymer flooding, the viscosity of the displacement fluid or the displacement speed must be increased by 100–1000 times. Decreasing the interfacial tension of the oil displacement system changed the wettability of the corner residual oil, thus increasing the wetting angle. When the interfacial tension level reached 10⁻² mN/m, the degree of movement of the remaining oil in the corner reached a maximum. If the interfacial tension is reduced, the degree of production of the residual oil in the corner does not change significantly. The microscopic production mechanism of the corner residual oil after polymer flooding expands the scope of the displacement streamlines in the corner. Full article

(This article belongs to the Special Issue Polymer Flooding and Rheology)

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17 pages, 2345 KiB

Open AccessArticle

Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir

by Ilnur Ilyasov, Igor Koltsov, Pavel Golub, Nikolay Tretyakov, Andrei Cheban and Antoine Thomas

Polymers 2021, 13(16), 2737; https://doi.org/10.3390/polym13162737 - 16 Aug 2021

Cited by 10 | Viewed by 3604

Abstract

Polymer flooding is a well-established technique aimed at improved recovery factors from oilfields. Among the important parameters affecting the feasibility of a large deployment, polymer retention is one of the most critical since it directly impacts the oil bank delay and therefore the final economics of the project. This paper describes the work performed for the East-Messoyakhskoe oilfield located in Northern Siberia (Russia). A literature review was first performed to select the most appropriate methodology to assess polymer retention in unconsolidated cores at residual oil saturation. 4 polyacrylamide polymers were selected with molecular weights between 7 and 18 M Da and sulfonated monomer (ATBS) content between 0 and 5% molar. An improved 2-fronts dynamic retention method along with total organic carbon—total nitrogen analyzers were used for concentration measurement. Retention values vary between 93 and 444 The sentence could be rephrased μg/g, with the lowest given by the polymers containing ATBS, corroborating other publications on the topic. This paper also summarizes the main learnings gathered during the adaptation of laboratory procedures and paves the way for a faster and more efficient retention estimation for unconsolidated reservoirs. Full article

(This article belongs to the Special Issue Polymer Flooding and Rheology)

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20 pages, 4395 KiB

Open AccessArticle

Artificial Neural Network to Forecast Enhanced Oil Recovery Using Hydrolyzed Polyacrylamide in Sandstone and Carbonate Reservoirs

by Hossein Saberi, Ehsan Esmaeilnezhad and Hyoung Jin Choi

Polymers 2021, 13(16), 2606; https://doi.org/10.3390/polym13162606 - 5 Aug 2021

Cited by 13 | Viewed by 3604

Abstract

Polymer flooding is an important enhanced oil recovery (EOR) method with high performance which is acceptable and applicable on a field scale but should first be evaluated through lab-scale experiments or simulation tools. Artificial intelligence techniques are strong simulation tools which can be used to evaluate the performance of polymer flooding operation. In this study, the main parameters of polymer flooding were selected as input parameters of models and collected from the literature, including: polymer concentration, salt concentration, rock type, initial oil saturation, porosity, permeability, pore volume flooding, temperature, API gravity, molecular weight of the polymer, and salinity. After that, multilayer perceptron (MLP), radial basis function, and fuzzy neural networks such as the adaptive neuro-fuzzy inference system were adopted to estimate the output EOR performance. The MLP neural network had a very high ability for prediction, with statistical parameters of R² = 0.9990 and RMSE = 0.0002. Therefore, the proposed model can significantly help engineers to select the proper EOR methods and API gravity, salinity, permeability, porosity, and salt concentration have the greatest impact on the polymer flooding performance. Full article

(This article belongs to the Special Issue Polymer Flooding and Rheology)

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19 pages, 13633 KiB

Open AccessArticle

Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir

by Mohamed Adel Alzaabi, Juan Manuel Leon, Arne Skauge and Shehadeh Masalmeh

Polymers 2021, 13(11), 1765; https://doi.org/10.3390/polym13111765 - 27 May 2021

Cited by 6 | Viewed by 3187

Abstract

Polymer flooding has gained much interest within the oil industry in the past few decades as one of the most successful chemical enhanced oil recovery (CEOR) methods. The injectivity of polymer solutions in porous media is a key factor in polymer flooding projects. The main challenge that faces prediction of polymer injectivity in field applications is the inherent non-Newtonian behavior of polymer solutions. Polymer in situ rheology in porous media may exhibit complex behavior that encompasses shear thickening at high flow rates in addition to the typical shear thinning at low rates. This shear-dependent behavior is usually measured in lab core flood experiments. However, data from field applications are usually limited to the well bottom-hole pressure (BHP) as the sole source of information. In this paper, we analyze BHP data from field polymer injectivity test conducted in a Middle Eastern heterogeneous carbonate reservoir characterized by high-temperature and high-salinity (HTHS) conditions. The analysis involved incorporating available data to build a single-well model to simulate the injectivity test. Several generic sensitivities were tested to investigate the impact of stepwise variation in injection flow rate and polymer concentration. Polymer injection was reflected in a non-linear increase in pressure with injection, and longer transient behavior toward steady state. The results differ from water injection which have linear pressure response to rate variation, and quick stabilization of pressure after rate change. The best match of the polymer injection was obtained with complex rheology, that means the combined shear thickening at high rate near the well and moving through apparent Newtonian and shear thinning at low rate. Full article

(This article belongs to the Special Issue Polymer Flooding and Rheology)

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28 pages, 17087 KiB

Open AccessArticle

The Impact of Rheology on Viscous Oil Displacement by Polymers Analyzed by Pore-Scale Network Modelling

by Iselin C. Salmo, Ken S. Sorbie and Arne Skauge

Polymers 2021, 13(8), 1259; https://doi.org/10.3390/polym13081259 - 13 Apr 2021

Cited by 8 | Viewed by 2630

Abstract

Several experimental studies have shown significant improvement in heavy oil recovery with polymers displaying different types of rheology, and the effect of rheology has been shown to be important. These experimental studies have been designed to investigate why this is so by applying a constant flow rate and the same polymer effective viscosity at this injection rate. The types of rheology studied vary from Newtonian and shear thinning behavior to complex rheology involving shear thinning and thickening behavior. The core flood experiments show a significantly higher oil recovery with polyacrylamide (HPAM), which exhibits shear thinning/thickening behavior compared to biopolymers like Xanthan, which is purely shear thinning. Various reasons for these observed oil recovery results have been conjectured, but, to date, a clear explanation has not been conclusively established. In this paper, we have investigated the theoretical rationale for these results by using a dynamic pore scale network model (DPNM), which can model imbibition processes (water injection) in porous media and also polymer injection. In the DPNM, the polymer rheology can be shear thinning, shear thinning/thickening, or Newtonian (constant viscosity). Thus, the local effective viscosity in a pore within the DPNM depends on the local shear rate in that pore. The predicted results using this DPNM show that the polymer causes changes in the local flow velocity field, which, as might be expected, are different for different rheological models, and the changes in the velocity profile led to local diversion of flow. This, in turn, led to different oil recovery levels in imbibition. However, the critical result is that the DPNM modelling shows exactly the same trend as was observed in the experiments, viz. that the shear thinning/thickening polymer gave the highest oil recovery, followed by the Newtonian Case and the purely shear thinning polymer gave the lowest recover, but this latter case was still above the waterflood result. The DPNM simulations showed that the shear-thinning/thickening polymer show a stabilized frontal velocity and increased oil mobilization, as observed in the experiments. Simulations for the shear-thinning polymer show that, in high-rate bonds, the average viscosity is greatly reduced, and this causes enhanced water fingering compared to the Newtonian polymer case. No other a priori model of the two-phase fluid physics of imbibition, coupled with the polymer rheology, has achieved this degree of predictive explanation, of these experimental observations, to our knowledge. Full article

(This article belongs to the Special Issue Polymer Flooding and Rheology)

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