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Advanced Gels for Oil Recovery
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Advanced Gels for Oil Recovery

A special issue of Gels (ISSN 2310-2861). This special issue belongs to the section "Gel Applications".

Deadline for manuscript submissions: closed (31 July 2023) | Viewed by 18395

Special Issue Editors

Prof. Dr. Han Jia

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: surfactant; nanomaterial; self-assembly; molecular simulation; improved oil recovery
Special Issues, Collections and Topics in MDPI journals
Prof. Dr. Mingwei Zhao

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: improved oil recovery; fracturing fluid; surfactant; polymer; nanoparticle
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Various gels have been used in oil fields for many years to control fluid flow in reservoirs. Viscoelastic gels can effectively block reservoirs with a high permeability, resulting in a greatly increased sweep efficiency. Many research groups focused on improvements of the strength, elastic modulus, dewatering rate, breakthrough pressure and microstructure of gels, and systematically evaluated the performances of these gels in terms of their temperature, salt resistance, blocking and long-term stability. Recently, many studies further modified the viscosity and reduced the filtration loss of gel-forming fluids, controlling the gel-forming time of these gels to achieve deep and stable water plugging. Moreover, gels with a high viscosity, good shear recovery and facile gel breaking can also be used as fracturing fluids. Their significant properties, such as retardation, sand-carrying capability, temperature resistance, shear resistance, gel-breaking capability and so on, were widely investigated to meet the requirements of the practical applications. With the exploration and development of unconventional oil and gas, gels are beginning to play increasingly essential roles in various fields of research, and advanced gels are still highly desired for use in harsh conditions. We look forward to submissions of the latest research achievements on the advanced gels for oil recovery, for which theoretical, experimental, and application studies are welcome.

Dr. Han Jia
Dr. Mingwei Zhao
Guest Editors

Manuscript Submission Information

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Keywords

  • application of polymer gels in improved oil recovery
  • theory of polymer gels in improved oil recovery
  • synthesis and characterization of advanced polymer gels
  • structure-property relationships of novel polymer
  • unconventional oil and gas exploration and development

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Published Papers (10 papers)

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Research

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16 pages, 4415 KiB  
Article
Insights into the Injectivity and Propagation Behavior of Preformed Particle Gel (PPG) in a Low–Medium-Permeability Reservoir
by Hong He, Yuhang Tian, Lianfeng Zhang, Hongsheng Li, Yan Guo, Yu Liu and Yifei Liu
Gels 2024, 10(7), 475; https://doi.org/10.3390/gels10070475 - 18 Jul 2024
Viewed by 732
Abstract
Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low–medium-permeability reservoir porous media is crucial for HPCF treatment in a low–medium-permeability [...] Read more.
Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low–medium-permeability reservoir porous media is crucial for HPCF treatment in a low–medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low–medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55–72 and β is 3.4–6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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21 pages, 14687 KiB  
Article
Preparation and Degradation Performance Study of P(AM/GG/PEGDA) Nanocomposite Self-Degradation Gel Plugging Material
by Dan Bao, Siyuan Liu, Xianli Zhang, Feng Li, Jiaqin Wang, Huan Jia, Shanghao Liu and Peng Zhang
Gels 2023, 9(9), 735; https://doi.org/10.3390/gels9090735 - 9 Sep 2023
Cited by 2 | Viewed by 1352
Abstract
Lost circulation is a world-class problem, and the contradiction between plugging and unplugging in reservoirs is a problem that needs to be solved urgently. The traditional LCM is not suitable for reservoirs and the complex subsequent operations. Currently, a self-degrading plugging material is [...] Read more.
Lost circulation is a world-class problem, and the contradiction between plugging and unplugging in reservoirs is a problem that needs to be solved urgently. The traditional LCM is not suitable for reservoirs and the complex subsequent operations. Currently, a self-degrading plugging material is proposed. In this paper, a new self-degradation plugging material, CKS-DPPG, was prepared by AM, GG, nano silica, and PEGDA. The effects of reactant concentration, pH, mineralization, etc., on the swelling and degradation performance of CKS-DPPG were investigated. The plugging capacity was tested by fracture plugging equipment, and the mechanism of self-degradation was revealed. The results show that the CKS-DPPG reached a 50% degradation rate in 54 h and complete degradation in 106 h at 80 °C and pH = 8. Low temperatures, high mineralization, and weak alkaline conditions prolong the complete degradation time of CKS-DPPG, which facilitates subsequent operations. The simulation of the 3 mm opening fracture plugging experiment showed that the pressure-bearing capacity reached 6.85 MPa and that a 0.16 MPa pressure difference could unplug after degradation. The ester bond of PEGDA is hydrolyzed under high-temperature conditions, and the spatial three-dimensional structure of CKS-DPPG becomes linear. The CKS-DPPG can effectively reduce subsequent unplugging operations and lower production costs. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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23 pages, 11850 KiB  
Article
Dynamic Sweep Experiments on a Heterogeneous Phase Composite System Based on Branched-Preformed Particle Gel in High Water-Cut Reservoirs after Polymer Flooding
by Xianmin Zhang, Yiming Zhang, Haicheng Liu, Shanshan Li and Lijie Liu
Gels 2023, 9(5), 364; https://doi.org/10.3390/gels9050364 - 25 Apr 2023
Cited by 8 | Viewed by 1410
Abstract
Heterogeneous phase composite (HPC) flooding technology that is based on branched-preformed particle gel (B-PPG) is an important technology for enhancing oil recovery in high water-cut reservoirs. In this paper, we conducted a series of visualization experiments under the condition of developed high-permeability channels [...] Read more.
Heterogeneous phase composite (HPC) flooding technology that is based on branched-preformed particle gel (B-PPG) is an important technology for enhancing oil recovery in high water-cut reservoirs. In this paper, we conducted a series of visualization experiments under the condition of developed high-permeability channels after polymer flooding, with respect to well pattern densification and adjustment, and HPC flooding and its synergistic regulation. The experiments show that for polymer-flooded reservoirs, HPC flooding can significantly reduce the water cut and increase oil recovery, but that the injected HPC system mainly advances along the high-permeability channel with limited sweep expansion. Furthermore, well pattern densification and adjustment can divert the original mainstream direction, which has a positive effect on HPC flooding, and can effectively expand the sweeping range under the synergistic effect of residual polymers. Due to the synergistic effect of multiple chemical agents in the HPC system, after well pattern densification and adjustment, the production time for HPC flooding with the water cut lower than 95% was significantly prolonged. In addition, conversion schemes, in which the original production well is converted into the injection well, are better than non-conversion schemes in terms of expanding sweep efficiency and enhancing oil recovery. Therefore, for well groups with obvious high-water-consuming channels after polymer flooding, the implementation of HPC flooding can be combined with well pattern conversion and intensification in order to further improve oil displacement. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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19 pages, 8417 KiB  
Article
Rheological Performance of High-Temperature-Resistant, Salt-Resistant Fracturing Fluid Gel Based on Organic-Zirconium-Crosslinked HPAM
by Hui Xin, Bo Fang, Luyao Yu, Yongjun Lu, Ke Xu and Kejing Li
Gels 2023, 9(2), 151; https://doi.org/10.3390/gels9020151 - 11 Feb 2023
Cited by 9 | Viewed by 2421
Abstract
Development of low-cost, high-temperature-resistant and salt-resistant fracturing fluids is a hot and difficult issue in reservoir fluids modification. In this study, an organic zirconium crosslinker that was synthesized and crosslinked with partially hydrolyzed polyacrylamide (HPAM) was employed as a cost-effective polymer thickener to [...] Read more.
Development of low-cost, high-temperature-resistant and salt-resistant fracturing fluids is a hot and difficult issue in reservoir fluids modification. In this study, an organic zirconium crosslinker that was synthesized and crosslinked with partially hydrolyzed polyacrylamide (HPAM) was employed as a cost-effective polymer thickener to synthesize a high-temperature-resistant and salt-resistant fracturing fluid. The rheological properties of HPAM in tap water solutions and 2 × 104 mg/L salt solutions were analyzed. The results demonstrated that addition of salt reduced viscosity and viscoelasticity of HPAM solutions. Molecular dynamics (MD) simulation results indicated that, due to electrostatic interaction, the carboxylate ions of HPAM formed an ionic bridge with metal cations, curling the conformation, decreasing the radius of rotation and thus decreasing viscosity. However, optimizing fracturing fluids formulation can mitigate the detrimental effects of salt on HPAM. The rheological characteristics of the HPAM fracturing fluid crosslinking process were analyzed and a crosslinking rheological kinetic equation was established under small-amplitude oscillatory shear (SAOS) test. The results of a large-amplitude oscillation shear (LAOS) test indicate that the heating effect on crosslinking is stronger than the shear effect on crosslinking. High-temperature-resistant and shear-resistant experiments demonstrated good performance of fracturing fluids of tap water and salt solution at 200 °C and 180 °C. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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18 pages, 50087 KiB  
Article
Visualized Study on a New Preformed Particle Gels (PPG) + Polymer System to Enhance Oil Recovery by Oil Saturation Monitoring Online Flooding Experiment
by Yanfu Pi, Jinxin Liu, Ruibo Cao, Li Liu, Yingxue Ma, Xinyang Gu, Xianjie Li, Xinyu Fan and Mingjia Zhao
Gels 2023, 9(2), 81; https://doi.org/10.3390/gels9020081 - 18 Jan 2023
Cited by 9 | Viewed by 2012
Abstract
After tertiary recovery from the oilfields, improving the production of the remaining hydrocarbon is always challenging. To significantly improve oil recovery, a heterogeneous composite flooding system has been developed with preformed particle gels (PPG) and polymers according to the technical approach of plugging [...] Read more.
After tertiary recovery from the oilfields, improving the production of the remaining hydrocarbon is always challenging. To significantly improve oil recovery, a heterogeneous composite flooding system has been developed with preformed particle gels (PPG) and polymers according to the technical approach of plugging and flooding combination. In addition, an oil saturation monitoring device and a large-scale 3D physical model were designed to better evaluate the performance of the technique. The evaluation results show that the viscosity, stability, and elasticity of the heterogeneous composite flooding system are better than the single polymer system. In addition, both systems exhibit pseudoplastic fluid characteristics and follow the principle of shear thinning. The results of seepage experiments showed that PPG migrates alternately in porous media in the manner of “piling plugging-pressure increasing-deformation migration”. The heterogeneous composite system can migrate to the depths of the oil layer, which improves the injection profile. In the visualization experiment, the heterogeneous composite system preferentially flowed into the high-permeability layer, which increased the seepage resistance and forced the subsequent fluid to flow into the medium and low permeability layers. The average saturation of the high, medium, and low permeability layers decreased by 4.74%, 9.51%, and 17.12%, respectively, and the recovery factor was further improved by 13.56% after the polymer flooding. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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21 pages, 4004 KiB  
Article
Synthesis of a Low-Molecular-Weight Filtrate Reducer and Its Mechanism for Improving High Temperature Resistance of Water-Based Drilling Fluid Gel System
by Xiaodong Dong, Jinsheng Sun, Xianbin Huang, Jian Li, Kaihe Lv and Pengxin Zhang
Gels 2022, 8(10), 619; https://doi.org/10.3390/gels8100619 - 28 Sep 2022
Cited by 19 | Viewed by 2329
Abstract
During the exploitation of deep and ultradeep oil and gas resources, the high-temperature problem of deep reservoirs has become a major challenge for water-based drilling fluids. In this study, a novel high-temperature-resistant filtrate reducer (LDMS) with low molecular weight was synthesized using N, [...] Read more.
During the exploitation of deep and ultradeep oil and gas resources, the high-temperature problem of deep reservoirs has become a major challenge for water-based drilling fluids. In this study, a novel high-temperature-resistant filtrate reducer (LDMS) with low molecular weight was synthesized using N, N-dimethylacrylamide; sodium p-styrene sulfonate; and maleic anhydride, which can maintain the performance of a drilling fluid gel system under high temperature. Unlike the conventional high-temperature-resistant polymer filtrate reducer, LDMS does not significantly increase the viscosity and yield point of the drilling fluid gel systems. After aging at 210 °C, the filtrate volume of a drilling fluid with 2 wt% LDMS was only 8.0 mL. The mechanism of LDMS was studied by particle size distribution of a drilling fluid gel system, Zeta potential change, adsorption experiment, change of bentonite interlayer spacing, filter cake scanning electron microscope, and related theoretical analysis. The mechanism study revealed that LDMS could be adsorbed on the surface of bentonite particles in large quantities and intercalated into the interlayer of bentonite. Thus, it can improve the hydration degree of bentonite particles and the colloidal stability of the drilling fluid gel system, maintain the content of fine particles in the drilling fluid gel system, form a compact mud cake, and significantly reduce the filtrate volume of the drilling fluid gel system. Therefore, this work will promote the application of a low-molecular-weight polymer filtrate reducer in high-temperature-resistant water-based drilling fluid gel systems. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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11 pages, 1510 KiB  
Article
Selective Penetration and Profile Control Performance of Preformed Particle Gels for Heterogeneous Oil Reservoirs
by Kang Zhou, Dejun Wu, Zhibin An and Shuai Liu
Gels 2022, 8(10), 601; https://doi.org/10.3390/gels8100601 - 21 Sep 2022
Cited by 5 | Viewed by 1507
Abstract
The preformed particle gel (PPG) has been proved to be an effective chemical agent to reduce fluid channeling and increase the sweeping efficiency. However, we still lack a clear understanding of the field-scale matching relationship between PPG size, elastic modulus and a heterogeneous [...] Read more.
The preformed particle gel (PPG) has been proved to be an effective chemical agent to reduce fluid channeling and increase the sweeping efficiency. However, we still lack a clear understanding of the field-scale matching relationship between PPG size, elastic modulus and a heterogeneous reservoir. In this respect, the paper carried out various sand pack displacement experiments. The results indicated that an excessively large PPG or elastic modulus would plug a low-permeability sand pack and even increase the severity of fluid channeling. On the contrary, an excessively small PPG or elastic modulus allowed a certain degree of profile control, but the PPG could easily migrate out of high-permeability sand packs with water. If the elastic modulus remained unchanged, the suitable PPG size increased as the reservoir permeability ratio increased. On the other hand, the suitable elastic modulus increased with the increase of the reservoir permeability ratio when the PPG size was kept the same. By using regression analysis, quantitative expressions were established in order to determine the best suitable PPG size for a certain heterogeneous reservoir. When the elastic modulus was fixed, the best suitable PPG mesh exhibited a linear relation with the permeability ratio. This paper provides a useful reference to select the most convenient PPG size and elastic modulus for a potential heterogeneous reservoir, suitable to enhance oil recovery. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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15 pages, 3590 KiB  
Article
Development of the Gemini Gel-Forming Surfactant with Ultra-High Temperature Resistance to 200 °C
by Peng Liu, Caili Dai, Mingwei Gao, Xiangyu Wang, Shichun Liu, Xiao Jin, Teng Li and Mingwei Zhao
Gels 2022, 8(10), 600; https://doi.org/10.3390/gels8100600 - 20 Sep 2022
Cited by 7 | Viewed by 2084
Abstract
In order to broaden the application of clean fracturing fluid in ultra-high temperature reservoirs, a surfactant gel for high-temperature-resistant clean fracturing fluid was developed with a gemini cationic surfactant as the main agent in this work. As the fracturing fluid, the rheological property, [...] Read more.
In order to broaden the application of clean fracturing fluid in ultra-high temperature reservoirs, a surfactant gel for high-temperature-resistant clean fracturing fluid was developed with a gemini cationic surfactant as the main agent in this work. As the fracturing fluid, the rheological property, temperature resistance, gel-breaking property, filtration property, shear recovery performance and core damage property of surfactant gel were systematically studied and evaluated. Results showed the viscosity of the system remained at 25.2 mPa·s for 60 min under a shear rate of 170 s−1 at 200 °C. The observed core permeability damage rate was only 6.23%, indicating low formation damage after fracturing. Due to micelle self-assembly properties in surfactant gel, the fluid has remarkable shear self-repairability. The filtration and core damage experimental results meet the national industry standard for fracturing fluids. The gel system had simple formulation and excellent properties, which was expected to enrich the application of clean fracturing fluid in ultra-high temperature reservoirs. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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Review

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20 pages, 6551 KiB  
Review
A Review of Weak Gel Fracturing Fluids for Deep Shale Gas Reservoirs
by Shichu Yang, Weichu Yu, Mingwei Zhao, Fei Ding and Ying Zhang
Gels 2024, 10(5), 345; https://doi.org/10.3390/gels10050345 - 18 May 2024
Cited by 2 | Viewed by 1358
Abstract
Low-viscosity slickwater fracturing fluids are a crucial technology for the commercial development of shallow shale gas. However, in deep shale gas formations with high pressure, a higher sand concentration is required to support fractures. Linear gel fracturing fluids and crosslinked gel fracturing fluids [...] Read more.
Low-viscosity slickwater fracturing fluids are a crucial technology for the commercial development of shallow shale gas. However, in deep shale gas formations with high pressure, a higher sand concentration is required to support fractures. Linear gel fracturing fluids and crosslinked gel fracturing fluids have a strong sand-carrying capacity, but the drag reduction effect is poor, and it needs to be pre-prepared to decrease the fracturing cost. Slick water fracturing fluids have a strong drag reduction effect and low cost, but their sand-carrying capacity is poor and the fracturing fluid sand ratio is low. The research and development of viscous slick water fracturing fluids solves this problem. It can be switched on-line between a low-viscosity slick water fracturing fluid and high-viscosity weak gel fracturing fluid, which significantly reduces the cost of single-well fracturing. A polyacrylamide drag reducer is the core additive of slick water fracturing fluids. By adjusting its concentration, the control of the on-line viscosity of fracturing fluid can be realized, that is, ‘low viscosity for drag reduction, high viscosity for sand-carrying’. Therefore, this article introduces the research and application status of a linear gel fracturing fluid, crosslinked gel fracturing fluid, and slick water fracturing fluid for deep shale gas reservoirs, and focuses on the research status of a viscous slick water fracturing fluid and viscosity-controllable polyacrylamide drag reducer, with the aim of providing valuable insights for the research on water-based fracturing fluids in the stimulation of deep shale gas reservoirs. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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28 pages, 7786 KiB  
Review
Exploring Potential of Gellan Gum for Enhanced Oil Recovery
by Iskander Gussenov, Ramza Zh. Berzhanova, Togzhan D. Mukasheva, Gulnur S. Tatykhanova, Bakyt A. Imanbayev, Marat S. Sagyndikov and Sarkyt E. Kudaibergenov
Gels 2023, 9(11), 858; https://doi.org/10.3390/gels9110858 - 29 Oct 2023
Cited by 3 | Viewed by 1965
Abstract
Extensive laboratory and field tests have shown that the gelation response of gellan gum to saline water makes it a promising candidate for enhanced oil recovery (EOR). The objective of this mini-review is to evaluate the applicability of gellan gum in EOR and [...] Read more.
Extensive laboratory and field tests have shown that the gelation response of gellan gum to saline water makes it a promising candidate for enhanced oil recovery (EOR). The objective of this mini-review is to evaluate the applicability of gellan gum in EOR and compare its efficiency to other precursors, in particular, hydrolyzed polyacrylamide (HPAM). At first, the “sol-gel” phase transitions of gellan gum in aqueous-salt solutions containing mono- and divalent cations are considered. Then the rheological and mechanical properties of gellan in diluted aqueous solutions and gel state are outlined. The main attention is paid to laboratory core flooding and field pilot tests. The plugging behavior of gellan in laboratory conditions due to “sol-gel” phase transition is discussed in the context of conformance control and water shut-off. Due to its higher strength, gellan gum gel provided ~6 times greater resistance to the flow of brine in a 1 mm-width fracture compared to HPAM gel. The field trials carried out in the injection and production wells of the Kumkol oilfield, situated in Kazakhstan, demonstrated that over 6 and 11 months, there was an incremental oil recovery of 3790 and 5890 tons, respectively. To put it into perspective, using 1 kg of dry gellan resulted in the incremental production of 3.52 m3 (or 22 bbls) of oil. The treatment of the production well with 1 wt.% gellan solution resulted in a considerable decrease in the water cut up to 10–20% without affecting the oil flow rate. The advantages and disadvantages of gellan compared to HPAM are analyzed together with the economic feasibility of gellan over HPAM. The potential for establishing gellan production in Kazakhstan is emphasized. It is anticipated that gellan gum, manufactured through fermentation using glucose–fructose syrup from Zharkent and Burunday corn starch plants, could be expanded in the future for applications in both the food industry and oil recovery. Full article
(This article belongs to the Special Issue Advanced Gels for Oil Recovery)
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