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Polymers
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Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities
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Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities

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

Deadline for manuscript submissions: closed (25 June 2023) | Viewed by 13660

Special Issue Editor

Dr. Emad W. Al Shalabi

E-Mail Website
Guest Editor
Assistant Professor, Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi 127788, United Arab Emirates
Interests: polymer flooding; chemical enhanced oil recovery; enhanced/improved oil recovery; reservoir simulation and modeling; reservoir engineering; special core analysis

Special Issue Information

Dear Colleagues,

Polymer flooding is one of the promising and well-established chemical enhanced oil recovery (CEOR) methods to improve oil sweep efficiency. This can be achieved through both mobility and conformance controls. Recent studies showed that polymers are even capable of improving microscopic displacement efficiency as well. Polymer applications have been mainly focused on sandstone reservoirs with mild conditions of reservoir heterogeneity, salinity, and temperature. 

Polymer flooding in carbonate reservoirs is very limited due to the related harsh conditions of high heterogeneity, low permeability, as well as high temperature and high salinity (HTHS). Conventional polymers fail under these conditions due to precipitation, viscosity loss, and polymer adsorption. However, researchers have been investigating the possibility of expanding the envelope of polymer flooding to carbonate reservoirs.

Therefore, to overcome these challenges, several novel polymers have been introduced to withstand the harsh reservoir conditions in carbonates including, but not limited to, ATBS, AMPS, NVP-based polymers, and hydrophobic associative polymers, along with bio-polymers, e.g., Scleroglucan. These polymers have shown low shear sensitivity, low adsorption, and robust thermal/salinity tolerance. Moreover, low-salinity water can precondition high-salinity reservoirs before polymer flooding to decrease polymer adsorption and viscosity loss.

In this Special Issue, we aim to collect reasonable and comprehensive findings regarding polymer enhanced oil recovery applications for both mobility control, as well as conformance control. The targeted applications are focused in sandstones and carbonates from experimental, numerical, and field works. The content of this collection will cover diverse fields of synthetic polymers vs. biopolymers, associative polymers, polymers under harsh reservoir conditions, polymer gels, polymer viscoelastic effects, novel polymers, low-salinity polymer, hybrid techniques, and others.

Dr. Emad W. Al Shalabi
Guest Editor

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Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Polymers is an international peer-reviewed open access semimonthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2700 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • synthetic polymers
  • biopolymers
  • associative polymers
  • polymer enhanced oil recovery
  • novel polymers
  • polymer gels
  • polymer viscoelasticity
  • polymers under HTHS
  • low-salinty polymer flooding
  • hybrid polymer techniques

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Published Papers (6 papers)

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Research

19 pages, 10787 KiB  
Article
Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments
by Guodong Zou, Bin Pan, Weiyao Zhu, Yuwei Liu, Shou Ma and Mingming Liu
Polymers 2023, 15(6), 1560; https://doi.org/10.3390/polym15061560 - 21 Mar 2023
Cited by 3 | Viewed by 1633
Abstract
Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. [...] Read more.
Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development. Full article
(This article belongs to the Special Issue Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities)
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13 pages, 3375 KiB  
Article
Research on Adaptability Evaluation Method of Polymer by Nuclear Magnetic Resonance Technology
by Xiaocong Wang, Qun Lei, Jianhui Luo, Peiwen Xiao, Pingmei Wang, Yinzhu Ye, Sunan Cong, Xue Han and Lipeng He
Polymers 2023, 15(4), 930; https://doi.org/10.3390/polym15040930 - 13 Feb 2023
Cited by 1 | Viewed by 1375
Abstract
In order to study the matching relationship between polymer(HPAM) molecular weight and reservoir permeability, in this paper, the injection performance of polymers with different molecular weights in rock cores with different permeability is studied. Using nuclear magnetic resonance technology combined with conventional core [...] Read more.
In order to study the matching relationship between polymer(HPAM) molecular weight and reservoir permeability, in this paper, the injection performance of polymers with different molecular weights in rock cores with different permeability is studied. Using nuclear magnetic resonance technology combined with conventional core displacement equipment, the change law of the displacement process was analyzed from three aspects of nuclear magnetic resonance T2 spectrum, core layering, and imaging. Finally, the fluidity of the polymer solution in the core was analyzed by injection pressure control features. The experimental results show that the polymer solution with a molecular weight of 25 million has the best retention effect in the core flooding experiment and can stay in the dominant channel of the core for a long time to control the water flooding mobility. In rocks with a permeability of 500, 1000, and 2000 mD, subsequent water flooding can expand the swept volume by about 25% compared with polymer flooding. This method can effectively establish the adaptability matching relationship between the polymer molecular weight and the reservoir permeability. Full article
(This article belongs to the Special Issue Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities)
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16 pages, 3282 KiB  
Article
Rheological Assessment of Oil-Xanthan Emulsions in Terms of Complex, Storage, and Loss Moduli
by Mamdouh Taha Ghannam, Mohamed Y. E. Selim, Abdulrazag Y. Zekri and Nabil Esmail
Polymers 2023, 15(2), 470; https://doi.org/10.3390/polym15020470 - 16 Jan 2023
Cited by 4 | Viewed by 1838
Abstract
This experimental assessment was carried out to study the viscoelastic performance of crude oil-xanthan emulsions employing a RheoStress RS100 rheometer. Crude oil with a concentration range of 0–75% by volume was used to prepare the oil-gum emulsions. Two xanthan gums of Sigma and [...] Read more.
This experimental assessment was carried out to study the viscoelastic performance of crude oil-xanthan emulsions employing a RheoStress RS100 rheometer. Crude oil with a concentration range of 0–75% by volume was used to prepare the oil-gum emulsions. Two xanthan gums of Sigma and Kelzan were added in the emulsions with concentration ranges of 0–104 ppm. The linear viscoelastic ranges of all the tested oil-gum emulsions were found in the range of 0.1–10 Pa. Thus, the experimental tests were completed within the linear viscoelastic range of 1 Pa. The complex modulus increased gradually and steadily with frequency and gum concentration for all the examined emulsions. The addition of crude oil into the lighter xanthan concentration of <103 ppm provided almost the same behavior as the xanthan solution, whereas the presence of crude oil within the higher xanthan concentrations significantly stimulated the measured values of the complex modulus. For lower gum concentrations of up to 1000 ppm, oil concentration displayed no effect on both the storage and loss moduli, whereas for gum concentrations higher than 1000 ppm, both moduli increased gradually with crude oil concentration. Full article
(This article belongs to the Special Issue Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities)
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16 pages, 4119 KiB  
Article
Effect of Rheological Properties of Polymer Solution on Polymer Flooding Characteristics
by Farhood Navaie, Ehsan Esmaeilnezhad and Hyoung-Jin Choi
Polymers 2022, 14(24), 5555; https://doi.org/10.3390/polym14245555 - 19 Dec 2022
Cited by 13 | Viewed by 4518
Abstract
Polymer flooding is an appropriate enhanced oil recovery (EOR) process that can increase macroscopic sweep efficiency. We examined two polymeric superpushers at different salinities (10,000 and 42,000 ppm of NaCl and 18,000 ppm of CaCl2) and temperatures (30 to 75 °C) [...] Read more.
Polymer flooding is an appropriate enhanced oil recovery (EOR) process that can increase macroscopic sweep efficiency. We examined two polymeric superpushers at different salinities (10,000 and 42,000 ppm of NaCl and 18,000 ppm of CaCl2) and temperatures (30 to 75 °C) as polymer-flooding agents for the EOR process. Rheological and thixotropic tests were attempted to find shear viscosity change when the polymer solutions were introduced under different salinity and temperatures, followed by describing the rheological behavior with the two most common rheological models used for polymer solutions, and then a quadratic model with Design-Expert to detect the effective parameters. Core flooding tests were conducted afterward to determine the final proposed fluid. An increase in the concentration of monovalent ions and the addition of divalent ions adversely affected both types of polymers used, which was similar to the effects of a temperature increase. The Flopaam 3630S at 1000 ppm has more stability under harsh conditions and enables 22% and 38% oil recovery in carbonate and sandstone core rocks, respectively. Consequently, Flopaam 3630S can be the perfect polymer agent for different chemical flooding procedures in high-salinity oil reservoirs. Full article
(This article belongs to the Special Issue Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities)
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20 pages, 7236 KiB  
Article
A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging
by Bergit Brattekås, Martine Folgerø Sandnes, Marianne Steinsbø and Jacquelin E. Cobos
Polymers 2022, 14(22), 5050; https://doi.org/10.3390/polym14225050 - 21 Nov 2022
Cited by 1 | Viewed by 1429
Abstract
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 [...] Read more.
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. Full article
(This article belongs to the Special Issue Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities)
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11 pages, 2189 KiB  
Article
Experimental Study on the Application of Cellulosic Biopolymer for Enhanced Oil Recovery in Carbonate Cores under Harsh Conditions
by Afeez Gbadamosi, Xianmin Zhou, Mobeen Murtaza, Muhammad Shahzad Kamal, Shirish Patil, Dhafer Al Shehri and Assad Barri
Polymers 2022, 14(21), 4621; https://doi.org/10.3390/polym14214621 - 31 Oct 2022
Cited by 7 | Viewed by 1675
Abstract
Polymer flooding is used to improve the viscosity of an injectant, thereby decreasing the mobility ratio and improving oil displacement efficiency in the reservoir. Thanks to their environmentally benign nature, natural polymers are receiving prodigious attention for enhanced oil recovery. Herein, the rheology [...] Read more.
Polymer flooding is used to improve the viscosity of an injectant, thereby decreasing the mobility ratio and improving oil displacement efficiency in the reservoir. Thanks to their environmentally benign nature, natural polymers are receiving prodigious attention for enhanced oil recovery. Herein, the rheology and oil displacement properties of okra mucilage were investigated for its enhanced oil recovery potential at a high temperature and high pressure (HTHP) in carbonate cores. The cellulosic polysaccharide used in the study is composed of okra mucilage extracted from okra (Abelmoschus esculentus) via a hot water extraction process. The morphological property of okra mucilage was characterized with Fourier transform infrared (FTIR), while the thermal stability was investigated using a thermogravimetric analyzer (TGA). The rheological property of the okra mucilage was investigated for seawater salinity and high-temperature conditions using a TA rheometer. Finally, an oil displacement experiment of the okra mucilage was conducted in a high-temperature, high-pressure core flooding equipment. The TGA analysis of the biopolymer reveals that the polymeric solution was stable over a wide range of temperatures. The FTIR results depict that the mucilage is composed of galactose and rhamnose constituents, which are essentially found in polysaccharides. The polymer exhibited pseudoplastic behavior at varying shear rates. The viscosity of okra mucilage was slightly reduced when aged in seawater salinity and at a high temperature. Nonetheless, the cellulosic polysaccharide exemplified sufficiently good viscosity under high-temperature and high-salinity (HTHS) conditions. Finally, the oil recovery results from the carbonate core plug reveal that the okra mucilage recorded a 12.7% incremental oil recovery over waterflooding. The mechanism of its better displacement efficiency is elucidated Full article
(This article belongs to the Special Issue Polymer Applications for Enhanced Oil Recovery: Challenges and Opportunities)
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