Polymer Gels for Oil Drilling and Enhanced Recovery

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.5	5.5	2011	16 Days	CHF 2400	Submit
ChemEngineering ChemEngineering	3.4	4.9	2017	32.8 Days	CHF 1800	Submit
Energies energies	3.2	7.3	2008	16.8 Days	CHF 2600	Submit
Gels gels	5.3	7.6	2015	13.5 Days	CHF 2100	Submit
Polymers polymers	4.9	9.7	2009	14.4 Days	CHF 2700	Submit
Processes processes	2.8	5.5	2013	14.9 Days	CHF 2400	Submit

17 pages, 2975 KB

Open AccessArticle

Study on Synthesis and Performance of a Hybrid Crosslinked Composite Gel for High-Temperature Lost Circulation Control

by Jiangang Shi, Xuyang Yao, Chaofei Wang, Tao Ren, Kecheng Liu, Huijun Hao, Zhangkun Ren and Jingbin Yang

Gels 2026, 12(4), 325; https://doi.org/10.3390/gels12040325 - 11 Apr 2026

Viewed by 401

Abstract

Conventional chemical gel plugging materials often suffer from poor high-temperature stability and inadequate mechanical properties. To address these issues, this study developed a high-performance composite gel material using a multi-component hybrid crosslinking strategy. The material employs γ-methacryloxypropyltrimethoxysilane (MPTMS) as the silica source, which [...] Read more.

Conventional chemical gel plugging materials often suffer from poor high-temperature stability and inadequate mechanical properties. To address these issues, this study developed a high-performance composite gel material using a multi-component hybrid crosslinking strategy. The material employs γ-methacryloxypropyltrimethoxysilane (MPTMS) as the silica source, which hydrolyzes in situ to generate SiO₂, thereby enhancing temperature resistance. Laponite nanoplatelets are incorporated as a toughening agent and physical crosslinking points, while a self-synthesized reactive microgel (BWL) serves as the organic crosslinking core. Through copolymerization with monomers such as acrylamide (AM) and methacrylic acid (MAA), a triple-crosslinked network structure is constructed. Compared with conventional gels, the synthesized hybrid crosslinked composite gel maintains a high storage modulus and loss modulus after aging at 140 °C and exhibits excellent tensile and compressive properties. Furthermore, the gel was processed into particle-based lost circulation materials with different particle sizes. High-temperature and high-pressure plugging experiments demonstrate that when using a mixed system of 40–60 mesh, 20–40 mesh, and 10–20 mesh gel particles with a total concentration of 2%, it can effectively seal highly permeable sand beds and fractures with apertures up to 5 mm. This meets the engineering requirements for lost circulation materials with high strength and high stability in deep, high-temperature formations. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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17 pages, 2995 KB

Open AccessArticle

Preparation and Performance Evaluation of a Supramolecular Gel Plugging Agent for Severe Lost Circulation Gas Reservoirs

by Yingbiao Liu, Kecheng Liu, Tao Zeng, Xuyang Yao, Weiju Wang, Huijun Hao, Zhangkun Ren and Jingbin Yang

Gels 2026, 12(3), 256; https://doi.org/10.3390/gels12030256 - 18 Mar 2026

Viewed by 311

Abstract

The plugging of fractured gas reservoirs with severe lost circulation during oil and gas drilling and production has long been challenged by technical issues such as low plugging strength and short effective duration. This paper reports the preparation of a high-strength supramolecular gel [...] Read more.

The plugging of fractured gas reservoirs with severe lost circulation during oil and gas drilling and production has long been challenged by technical issues such as low plugging strength and short effective duration. This paper reports the preparation of a high-strength supramolecular gel plugging agent via micellar copolymerization based on the synergistic effects of hydrophobic association and hydrogen bonding. Systematic optimization determined the optimal synthesis formula: acrylamide (AM) 12%, 2-acrylamido-2-methylpropanesulfonic acid (AMPS) 2%, stearyl methacrylate (SMA) 0.4%, sodium dodecyl sulfate (SDS) 1.5%, and potassium persulfate 0.3%, with a reaction temperature of 60 °C. Performance evaluations revealed that the gel possesses a controllable gelation time (120 min) and excellent viscoelastic recovery properties. At a compressive strain of 87%, the compressive stress reached 1.43 MPa while maintaining structural integrity. Swelling behavior analysis indicated that the gel follows a non-Fickian diffusion mechanism, with its swelling process governed by the synergistic interplay of water molecule diffusion and polymer network relaxation. Core plugging experiments demonstrated that the gel achieved plugging efficiencies exceeding 95% for cores with permeabilities ranging from 0.18 to 0.90 μm², with a maximum breakthrough pressure gradient of up to 11.48 MPa/m. These results highlight the gel’s efficient and broad-spectrum plugging capability for fractured lost circulation zones. This preliminary study provides experimental foundations for the material design and performance optimization of supramolecular gel-based long-lasting plugging agents for severe lost circulation gas reservoirs, and further field-scale validation is required for engineering application. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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20 pages, 2749 KB

Open AccessArticle

Low-Field Nuclear Magnetic Resonance Characterization of Drilling Fluid Systems Sealing Performance and Mechanism in Fractured Coal Seams

by Wei Wang, Zongkai Qi, Jinliang Han, Qiang Miao, Xinwei Liu, Youhui Guang, Zongxiao Ren, Zonglun Wang, Jiacheng Lei and Sixiang Zhu

Processes 2026, 14(6), 940; https://doi.org/10.3390/pr14060940 - 16 Mar 2026

Viewed by 387

Abstract

To address the critical challenge of drilling fluid invasion in deep coalbed methane (CBM) reservoirs, this study provides novel insight into the micro-scale sealing mechanism and pore structure evolution by leveraging Low-Field Nuclear Magnetic Resonance (LF-NMR) as a quantitative probe. Unlike traditional macroscopic [...] Read more.

To address the critical challenge of drilling fluid invasion in deep coalbed methane (CBM) reservoirs, this study provides novel insight into the micro-scale sealing mechanism and pore structure evolution by leveraging Low-Field Nuclear Magnetic Resonance (LF-NMR) as a quantitative probe. Unlike traditional macroscopic evaluations, we utilized dynamic NMR T₂ spectral analysis to decipher the synergistic behavior of a proposed “Bridging–Filling–Densifying” ternary sealing system, which integrates a nano-plugging agent, micro-fillers, and size-matched skeletal agents. The results demonstrate a significant improvement in sealing efficiency. The optimized hierarchical architecture reduced the NMR signal intensity of the invaded cores by over 99.8% under a differential pressure of 10 MPa, effectively eliminating fluid invasion channels. Crucially, the study reveals that while multi-scale particle size matching is the precondition for sealing, the mechanical rigidity of the skeletal particles is the determinant for maintaining filter cake integrity against high-pressure deformation. These findings elucidate the transition from a “macropore-dominated” structure to a “zero-detectable” sealed state, establishing a robust theoretical framework for designing non-damaging drilling fluids tailored to the complex geomechanics of deep CBM exploration. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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23 pages, 6021 KB

Open AccessArticle

Effect of Sodium Acetate on High-Temperature Gelation Characteristics of Sodium-Modified Calcium-Based Bentonite Water-Based Drilling Fluids

by Rui Liu, Yu Zhao, Huan Wang, Wenjun Long, Junge Zhu and Fengshan Zhou

Gels 2026, 12(3), 238; https://doi.org/10.3390/gels12030238 - 13 Mar 2026

Viewed by 369

Abstract

As global oil and gas exploration extends to deep and ultra-deep wells, high bottom-hole temperature is prone to deteriorating the gelation and rheological properties of water-based drilling fluids, which manifests as undesirable thickening or thinning at elevated temperatures. Therefore, the development of high-temperature [...] Read more.

As global oil and gas exploration extends to deep and ultra-deep wells, high bottom-hole temperature is prone to deteriorating the gelation and rheological properties of water-based drilling fluids, which manifests as undesirable thickening or thinning at elevated temperatures. Therefore, the development of high-temperature resistant and stable drilling fluids is crucial for ensuring safe and efficient drilling operations, and the enhancement of high-temperature performance is typically achieved by adding drilling fluid treatment agents. The main objective of this study is to apply sodium acetate (SA) to drilling fluid systems, developing an economical and efficient non-polymer treatment agent with dual functions as a composite sodium-modifier and a rheological regulator. By-product sodium acetate (TRSA) is adopted to provide better cost-effectiveness while maintaining equivalent performance, and its universality across seven types of bentonites is verified. Three grades of sodium acetate were added to the bentonites as either composite sodium-modifiers or rheological regulators. After high-temperature aging, rheological parameters, including mud density, plastic viscosity (PV), yield point (YP), and gel strength, were measured in accordance with standard API methods. The results indicate that adding 2 wt.% TRSA to drilling fluid and subjecting it to hot rolling at 180 °C for 16 h keeps the viscosity at a high shear rate (1022 s⁻¹) nearly unchanged (from 36 mPa·s to 37.5 mPa·s), while increasing the viscosity at a low shear rate (5.11 s⁻¹) from 250 mPa·s to 1400 mPa·s, thereby effectively improving the shear thinning effect of the sodium-modified calcium-based bentonite water-based drilling fluid. Although TRSA increases the filtration loss from 21.8 mL to 30 mL, this can be reduced to 20–25 mL by co-extrusion sodium modification with sodium carbonate or by adding additional TRSA to sodium-modified bentonite. This study provides a novel perspective for significantly improving the gelation characteristics and rheological properties of bentonite suspensions at high temperatures through a special inorganic substance, while realizing resource reuse and cost reduction. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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22 pages, 6365 KB

Open AccessArticle

Synthesis and Performance Evaluation of Polyamine Boron Crosslinker for Gel Fracturing Fluid

by Quande Wang, Tengfei Dong, Qi Feng, Shengming Huang, Xuanrui Zhang and Guancheng Jiang

Gels 2026, 12(3), 236; https://doi.org/10.3390/gels12030236 - 12 Mar 2026

Viewed by 309

Abstract

The fracturing development of low-permeability and ultra-low-permeability oil and gas reservoirs urgently requires a fracturing fluid that combines high performance and low damage. To overcome this challenge, this study synthesized a novel polyamine boron crosslinker (PBC) suitable for 0.2% guar gum. The molecular [...] Read more.

The fracturing development of low-permeability and ultra-low-permeability oil and gas reservoirs urgently requires a fracturing fluid that combines high performance and low damage. To overcome this challenge, this study synthesized a novel polyamine boron crosslinker (PBC) suitable for 0.2% guar gum. The molecular structure was characterized by Fourier transform infrared spectroscopy (FT-IR) and nuclear magnetic resonance hydrogen spectroscopy (¹H NMR). Meanwhile, this study introduced the response surface methodology and established a second-order regression model to determine the optimal synthesis conditions (polyetheramine 10.8 g, n-butanol 7.4 g, and ethylene glycol 20.7 g) with a model prediction error of only 0.7%. The results indicated that PBC exhibited excellent performance in 0.2% guar gum. The viscosity of crosslinked gel fracturing fluid remained stable at approximately 100 mPa·s under 60 °C and 100 s⁻¹ shear. The wall forming filtration coefficient was 2.30 × 10⁻⁴ m/s^1/2, and the initial filtration was 1.30 × 10⁻³ m³/m². The static settling rate was 2.4 cm·min⁻¹, demonstrating good suspended sand capacity. Furthermore, the synergistic interaction between borate ester bond and polyetheramine in the PBC conferred dynamic reversible crosslinking and uniform network formation. This enabled high-strength, low-damage crosslinking effects at low concentrations. This study provides an efficient crosslinker solution for 0.2% guar gum, holding both theoretical and engineering significance for advancing the low-cost development of fracturing fluid. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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25 pages, 4355 KB

Open AccessArticle

Preparation and Applicability Evaluation of High-Temperature-Resistant, Breakable Resin–Gel Plugging Agent

by Tao Wang, Jinzhi Zhu, Yingrui Bai, Yanming Yin, Qisheng Jiang, Zhangkun Ren and Jingbin Yang

Gels 2026, 12(2), 164; https://doi.org/10.3390/gels12020164 - 13 Feb 2026

Viewed by 522

Abstract

This study addresses the challenge of high-temperature gas channeling in injection–production wells of karst-fractured reservoirs by developing a high-temperature-resistant resin–gel plugging system capable of withstanding up to 150 °C. The system employs an AMPS/NVP copolymer (molar ratio 3:1) as the polymer matrix, reinforced [...] Read more.

This study addresses the challenge of high-temperature gas channeling in injection–production wells of karst-fractured reservoirs by developing a high-temperature-resistant resin–gel plugging system capable of withstanding up to 150 °C. The system employs an AMPS/NVP copolymer (molar ratio 3:1) as the polymer matrix, reinforced with phenolic resin to enhance the crosslinked network. Additionally, a polyamide microcapsule was utilized to encapsulate the gel breaker, enabling controlled release. The optimized formulation consists of 0.5% NEP, 0.5% DEP, 0.6% HMTA, 0.3% catechol, and 25% resin curing agent. Experimental results demonstrate that the system exhibits excellent stability at 150 °C, with a G′ ≥ 125 Pa and compressive strength > 18 MPa. It also displays strong contamination resistance, showing a viscosity reduction of <9.7% and a storage modulus retention rate > 87% after mixing with drilling fluid. Furthermore, the gel-breaking performance is controllable, achieving a gel-breaking rate ≥ 99.7% within 21 days. Under high-temperature and high-pressure conditions (150 °C), the system demonstrates a plugging efficiency > 92% for simulated fractures with widths ranging from 0.1 to 2 mm. This technology effectively suppresses gas channeling in complex high-temperature formations, making it suitable for gas injection wells in karst-fractured reservoirs. It also holds promise for extension to shale gas wells and geothermal reservoir sealing applications. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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18 pages, 3154 KB

Open AccessArticle

Study on Improvement of Acidizing Fracturing Formula in Carbonate Reservoir

by Leyan Shi and Fengpeng Lai

Processes 2026, 14(3), 563; https://doi.org/10.3390/pr14030563 - 5 Feb 2026

Viewed by 549

Abstract

Addressing the challenges of poorly developed fractures and low individual well water yields within the Tianjin Ordovician–Wumishan carbonate thermal reservoir, alongside the rapid reaction rates and short effective distances observed during conventional acid fracturing operations, this study employed an XRD core analysis to [...] Read more.

Addressing the challenges of poorly developed fractures and low individual well water yields within the Tianjin Ordovician–Wumishan carbonate thermal reservoir, alongside the rapid reaction rates and short effective distances observed during conventional acid fracturing operations, this study employed an XRD core analysis to confirm reservoir calcite contents exceeding 90%. Based on this finding, an acid formulation incorporating a 2% SPR-12 retarder was developed. High-temperature high-pressure reactor experiments demonstrated that this system successfully reduced the acid–rock reaction rate from 0.122 g·min⁻¹·cm⁻² to 0.037 g·min⁻¹·cm⁻² and increased the retardation efficiency from 34.07% to 68%. This significantly extended the acid penetration distance and enhanced the fracture network connectivity within the reservoir. The field trial conditions informed the parameter optimization via E-StimPlan^® 3D simulations, ultimately determining that a fracture extension of 400 m could be achieved with a 20 MPa breakdown pressure. Conductivity experiments validated that a flow rate of 1.3 m³/min generated pillar-supported wormhole structures, yielding a final conductivity of 46.8 μm²·cm. The pumping pressure plummeted from 20 MPa to 1 MPa, confirming effective fracture network communication. Gas lift backflow for 20 h mitigated secondary precipitation risks. After implementation, the water production rate of this well increased from 12.33 m³/h to 95 m³/h, with a dynamic water level of 158.85 m. The water temperature rose from 62 °C to 88 °C and remained stable. Compared to current acidizing and fracturing methods applied in geothermal wells, the new acid fluid system and process have increased the geothermal production capacity by 275.8%, while reducing acid consumption by 50%, providing critical technological support for the efficient development of carbonate thermal reservoirs. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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23 pages, 6373 KB

Open AccessReview

Polyacrylamide-Based Polymers for Slickwater Fracturing Fluids: A Review of Molecular Design, Drag Reduction Mechanisms, and Gelation Methods

by Wenbin Cai, Weichu Yu, Fei Ding, Kang Liu, Wen Xin, Zhiyong Zhao and Chao Xiong

Gels 2026, 12(2), 101; https://doi.org/10.3390/gels12020101 - 26 Jan 2026

Viewed by 1151

Abstract

Slickwater fracturing has become an adopted technology for enhancing hydrocarbon recovery from unconventional, low-permeability reservoirs such as shale and tight formations, owing to its ability to generate complex fracture networks at a low cost. Polyacrylamide and polyacrylamide-based gels serve as key additives in [...] Read more.

Slickwater fracturing has become an adopted technology for enhancing hydrocarbon recovery from unconventional, low-permeability reservoirs such as shale and tight formations, owing to its ability to generate complex fracture networks at a low cost. Polyacrylamide and polyacrylamide-based gels serve as key additives in these fluids, primarily functioning as drag reducers and thickeners. However, downhole environments of high-temperature (>120 °C) and high-salinity (>1 × 10⁴ mg/L) reservoirs pose challenges, leading to thermal degradation and chain collapse of conventional polyacrylamide, which results in performance loss. To address these limitations, synthesis methods including aqueous solution polymerization, inverse emulsion polymerization, and aqueous dispersion polymerization have been developed. This review provides an overview of molecular design methods aimed at enhancing performance stability of polyacrylamide-based polymers under extreme conditions. Approaches for improving thermal stability involve synthesis of ultra-high-molecular-weight polyacrylamide, copolymerization with resistant monomers, and incorporation of nanoparticles. Methods for enhancing salt tolerance focus on grafting anionic, cationic, or zwitterionic side chains onto the polymer backbone. The drag reduction mechanisms and gelation methods of these polymers in slickwater fracturing fluids are discussed. Finally, this review outlines research directions for developing next-generation polyacrylamide polymers tailored for extreme reservoir conditions, offering insights for academic research and field applications. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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18 pages, 2564 KB

Open AccessArticle

Mechanism Study on Enhancing Fracturing Efficiency in Coalbed Methane Reservoirs Using Highly Elastic Polymers

by Penghui Bo, Qingfeng Lu, Wenfeng Wang and Wenlong Wang

Processes 2026, 14(2), 191; https://doi.org/10.3390/pr14020191 - 6 Jan 2026

Viewed by 440

Abstract

Coalbed methane development is constrained by reservoir characteristics including high gas adsorption, high salinity, and high closure pressure, which impose significant limitations on conventional polymer fracturing fluids regarding viscosity enhancement, proppant transport, and fracture maintenance. In this study, a novel polymer fracturing fluid [...] Read more.

Coalbed methane development is constrained by reservoir characteristics including high gas adsorption, high salinity, and high closure pressure, which impose significant limitations on conventional polymer fracturing fluids regarding viscosity enhancement, proppant transport, and fracture maintenance. In this study, a novel polymer fracturing fluid system, Z-H-PAM, was designed and synthesized to achieve strong salt tolerance, low adsorption affinity, and high elasticity to withstand closure pressure. This was accomplished through the molecular integration of a zwitterionic monomer ZM-1 and a hydrophobic associative monomer HM-2, forming a unified structure that combines rigid hydrated segments with a hydrophobic elastic network. The results indicate that ZM-1 provides a stable hydration layer and low adsorption tendency under high-salinity conditions, while HM-2 contributes to a high-storage-modulus, three-dimensional physically cross-linked network via reversible hydrophobic association. Their synergistic interaction enables Z-H-PAM to retain viscoelasticity that is significantly superior to conventional HPAM and to achieve rapid structural recovery in high-mineralization environments. Systematic evaluation shows that this system achieves a static sand-suspension rate exceeding 95% in simulated flowback fluid, produces broken gel residues below 90 mg/L, and results in a core damage rate of only 10.5%. Moreover, it maintains 88.8% of its fracture conductivity under 30 MPa closure pressure. Notably, Z-H-PAM can be prepared directly using high-salinity flowback water, maintaining high elasticity and sand-carrying capacity while enabling fluid recycling and reducing reservoir damage. This work clarifies the multi-scale mechanisms of strongly hydrated and highly elastic polymers in coalbed methane reservoirs, offering a theoretical and technical pathway for developing efficient and low-damage fracturing materials. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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21 pages, 3487 KB

Open AccessArticle

Preparation and Performance Evaluation of Gelled Composite Plugging Agent Suitable for Fractured Formation

by Kecheng Liu, Kaihe Lv, Weiju Wang, Tao Ren, Jing He and Zhangkun Ren

Gels 2026, 12(1), 36; https://doi.org/10.3390/gels12010036 - 31 Dec 2025

Viewed by 347

Abstract

Lost circulation in fractured formations is a common yet challenging technical problem in drilling engineering. Conventional plugging methods often form sealing layers with poor stability and low pressure-bearing capacity. This study developed an efficient composite plugging agent composed of calcite particles (rigid particles), [...] Read more.

Lost circulation in fractured formations is a common yet challenging technical problem in drilling engineering. Conventional plugging methods often form sealing layers with poor stability and low pressure-bearing capacity. This study developed an efficient composite plugging agent composed of calcite particles (rigid particles), elastic gel particles, and polypropylene fibers. Utilizing a laboratory-scale fracture plugging evaluation apparatus and standard comparative experimental methods, the synergistic plugging effects of different composite systems were investigated. The results indicate that while single rigid particles can form a basic bridging structure, the pressure-bearing capacity of the resulting sealing layer is limited. Single elastic gel particles or fibrous materials struggle to effectively plug fractures of varying widths. Composite use of the plugging agents significantly enhanced the plugging performance, with the rigid/elastic/fiber ternary composite system demonstrating the best results. The optimal formulation (5% calcite particles + 3% elastic gel particles + 2% polypropylene fibers) achieved a plugging pressure-bearing capacity of 13 MPa for 2 mm-wide fractures, with a fluid loss of only 50 mL and temperature resistance up to 180 °C. Furthermore, the composite plugging agent exhibited good compatibility with the drilling fluid system and demonstrated excellent adaptability and plugging performance for fractures with different roughness levels, indicating promising potential for field application. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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16 pages, 1848 KB

Open AccessArticle

Rheological Investigation of Water-Based Drilling Fluids Using Synthesized ZnO with TiO₂ and Activated Carbon

by Chunping Liu, Tingting Wang, Zeeshan Ali Lashari and Wanchun Zhao

Processes 2026, 14(1), 81; https://doi.org/10.3390/pr14010081 - 25 Dec 2025

Viewed by 1021

Abstract

The primary goal of this study was to improve the rheological properties of water-based drilling mud using a combination of TiO₂-coated ZnO nanoparticles and activated carbon (AC) from banana peels. The TiO₂/ZnO nanocomposites were prepared using polyvinyl alcohol (PVA) [...] Read more.

The primary goal of this study was to improve the rheological properties of water-based drilling mud using a combination of TiO₂-coated ZnO nanoparticles and activated carbon (AC) from banana peels. The TiO₂/ZnO nanocomposites were prepared using polyvinyl alcohol (PVA) as a binder under magnetic stirring and ultrasonic sonication to ensure uniform coating, followed by washing and controlled thermal treatment. NaOH-assisted chemical activation of banana peel produced activated carbon with better porosity and surface functionality than raw banana peel. The base water-based mud used in this study had different concentrations of both additives mixed in, and rheological parameters such as mud density, plastic viscosity (PV), yield point (YP), and gel strength were measured according to standard API methods. X-ray diffraction (XRD) and scanning electron microscopy (SEM) were used for structural and morphological characterization, which proved the successful coating and uniform dispersion of TiO₂ on ZnO nanoparticles. The use of mixed additives resulted in a significant improvement in mud properties, such as viscosity, gel strength, and yield point, proving to be more effective in suspension capacity and overall rheological stability. The use of this hybrid bio-nanocomposite mud system is a very economical and eco-friendly way of enhancing the drilling fluid performance, thus proving to be a supporting factor in conducting drilling operations that are both safe and efficient. Additionally, this study provides a sustainable hybrid TiO₂-ZnO and activated carbon additive that results in synergistic improvement of drilling-mud rheology and stability. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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21 pages, 8560 KB

Open AccessArticle

Hydrocarbon Displacement Efficiency by Water and Polymer and Optimization of Multiple Parameters in Porous Media: Experiments and Numerical Simulation

by Kaijin Zheng, Binshan Ju, Emmanuel Karikari Duodu, Kaiyuan Fu, Jinyang Yu and Zihao Fang

Processes 2026, 14(1), 34; https://doi.org/10.3390/pr14010034 - 21 Dec 2025

Cited by 1 | Viewed by 605

Abstract

Polymers are effective agents for EOR due to their water solubility, which improves water viscosity, sweep volume, and displacement efficiency. To elucidate their mechanisms in EOR and optimize polymer–water synergistic flooding parameters, this study combined core and core network experimental research with numerical [...] Read more.

Polymers are effective agents for EOR due to their water solubility, which improves water viscosity, sweep volume, and displacement efficiency. To elucidate their mechanisms in EOR and optimize polymer–water synergistic flooding parameters, this study combined core and core network experimental research with numerical simulations. Experimental flooding results demonstrated that polymer–water synergistic flooding reduces residual oil saturation by 13.79% compared to water flooding. Key parameters such as well pattern, well spacing, bottom-hole pressure, polymer viscosity, and injection slug size were optimized through numerical simulation of a conceptual model based on actual oilfield data. A bottom-hole flowing pressure of 10.6 MPa, well pattern density of 84 wells/km², staggered line drive pattern, and polymer viscosity of 21 cp are recommended for EOR. Numerical simulation data showed that polymer–water synergistic flooding enhances displacement efficiency by 5–11% over conventional water flooding. The findings from the experimental research and numerical simulations indicate that the total recovery factor may be increased by implementing the recommended parameters in an actual oilfield. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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24 pages, 5702 KB

Open AccessArticle

Preparation and Performance Characterization of Thixotropic Gelling Materials with High Temperature Stability and Wellbore Sealing Properties

by Yingbiao Liu, Xuyang Yao, Chuanming Xi, Kecheng Liu and Tao Ren

Polymers 2025, 17(24), 3343; https://doi.org/10.3390/polym17243343 - 18 Dec 2025

Viewed by 853

Abstract

In response to the requirements of wellbore plugging and lost circulation control, this study designed and prepared a new type of thixotropic polymer gel system. The optimal formula was obtained through systematic screening of the types and concentrations of high molecular polymers, cross-linking [...] Read more.

In response to the requirements of wellbore plugging and lost circulation control, this study designed and prepared a new type of thixotropic polymer gel system. The optimal formula was obtained through systematic screening of the types and concentrations of high molecular polymers, cross-linking agents, flow pattern regulators, and resin curing agents. Comprehensive characterization of the gel’s gelling performance, thixotropic properties, high-temperature stability, shear resistance, and plugging capacity was conducted using methods such as the Sydansk bottle test, rheological testing, high-temperature aging experiments, plugging performance evaluation, as well as infrared spectroscopy, nuclear magnetic resonance, and thermogravimetric analysis, and its mechanism of action was revealed. The results show that the optimal formula is 1.2% AM-AA-AMPS terpolymer + 0.5% hydroquinone + 0.6% S-Trioxane + 0.8% modified montmorillonite + 14% modified phenolic resin. This gel system has a gelling time of 6 h, a gel strength reaching grade H, and a storage modulus of 62 Pa. It exhibits significant shear thinning characteristics in the shear rate range of 0.1~1000 s⁻¹, with a viscosity recovery rate of 97.7% and a thixotropic recovery rate of 90% after shearing. It forms a complete gel at a high temperature of 160 °C, with a dehydration rate of only 8.5% and a storage modulus retention rate of 80% after aging at 140 °C for 7 days. Under water flooding conditions at 120 °C, the converted pressure-bearing capacity per 100 m reaches 24.0 MPa. Mechanism analysis confirms that the system forms a stable composite network through the synergistic effect of “covalent cross-linking—hydrogen bonding—physical adsorption”, providing a high-performance material solution for wellbore plugging in high-temperature and high-salt environments. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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36 pages, 3413 KB

Open AccessArticle

Toward Sustainable Green and Intelligent Profile Control Gels: An ETI–CFI-Based Structure–Environment Evaluation Framework

by Qiang Chen, Hanmin Xiao, Zhihua Chen, Tong Wu, Hao Chen and Keqiang Wei

Gels 2025, 11(12), 952; https://doi.org/10.3390/gels11120952 - 27 Nov 2025

Viewed by 941

Abstract

In the context of the “dual-carbon” strategy and the escalating challenges posed by ultra-high water-cut reservoirs, the development of green and intelligent profile control gels (PCGs) has become essential for balancing enhanced oil recovery (EOR) efficiency with environmental sustainability. In this study, a [...] Read more.

In the context of the “dual-carbon” strategy and the escalating challenges posed by ultra-high water-cut reservoirs, the development of green and intelligent profile control gels (PCGs) has become essential for balancing enhanced oil recovery (EOR) efficiency with environmental sustainability. In this study, a green performance evaluation framework integrating the Environmental Toxicity Index (ETI) and Carbon Footprint Intensity (CFI) is established to quantitatively assess the environmental friendliness of polymer gel systems. Representative gel types—including conventional chromium(III)–polyacrylamide(Cr(III)–PAM), citric acid–chitosan, and pH-responsive nanogels—are evaluated to reveal their structure–environment interactions. Comparative analysis shows that the Cr(III)–PAM system exhibits strong plugging capability but imposes the highest environmental burden (ETI = 1.45; CFI = 9.1 kg CO₂e/kg), whereas the citric acid–chitosan system significantly reduces both toxicity (ETI = 0.42) and carbon footprint (CFI = 2.1). Meanwhile, pH-responsive nanogels demonstrate superior reservoir stability and sustainability under harsh conditions. The proposed ETI–CFI evaluation framework not only enables quantitative benchmarking of green performance but also provides a unified criterion for molecular design, material screening, and engineering application of intelligent green gels. This framework offers practical guidance for the low-carbon transformation of oilfield chemical systems, aligning innovation with sustainability objectives and supporting the realization of dual-carbon goals. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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21 pages, 2725 KB

Open AccessArticle

Study on Self-Healing and Sealing Technology of Fractured Geothermal Reservoir

by Wenxi Wang and Yang Tian

Processes 2025, 13(12), 3817; https://doi.org/10.3390/pr13123817 - 26 Nov 2025

Cited by 1 | Viewed by 635

Abstract

Geothermal energy, recognized as a sustainable and clean resource, is playing an increasingly critical role in the global shift toward low-carbon energy systems. Nevertheless, the exploitation of fractured geothermal reservoirs is often impeded by severe lost circulation during drilling, where conventional plugging materials [...] Read more.

Geothermal energy, recognized as a sustainable and clean resource, is playing an increasingly critical role in the global shift toward low-carbon energy systems. Nevertheless, the exploitation of fractured geothermal reservoirs is often impeded by severe lost circulation during drilling, where conventional plugging materials fail under high-temperature, high-salinity, and high-pressure conditions due to inadequate mechanical strength, poor thermal resistance, and lack of self-adaptive sealing behavior. In response, self-healing materials have emerged as an innovative strategy for developing intelligent lost circulation control technologies. Herein, we report a novel self-healing gel (XFFD) synthesized via inverse emulsion polymerization using acrylamide (AM), acrylic acid (AA), p-nitroblue tetrazolium (PNBT), and modified silica nanoparticles (PAS). The resulting material exhibits exceptional thermal stability, with decomposition onset above 356 °C, as determined by thermogravimetric analysis. Rheological and mechanical assessments reveal outstanding viscoelasticity, moderate swelling capacity (4.17-fold in deionized water), and a high self-recovery efficiency of 91.15%, accompanied by a bearing strength of 3.65 MPa. Mechanistic investigations indicate that the autonomous repair capability stems from dynamic non-covalent interactions—primarily hydrogen bonding and ionic associations—enabled by amide and carboxyl groups within the polymer network. Sand bed filtration tests under simulated geothermal conditions (150 °C, 8% salinity) demonstrate that XFFD forms a robust sealing barrier with significantly shallower invasion depth compared to conventional materials such as sulfonated asphalt and calcium carbonate. This work presents an effective self-healing gel system that ensures reliable wellbore strengthening and fluid loss control in challenging high-temperature, high-salinity geothermal drilling operations. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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23 pages, 3792 KB

Open AccessArticle

Optimization of the Synthesis of Low Viscosity and High Shear Sulfonated Guar Gum for Enhancing Its Performance in Drilling Fluids

by Yifei Zhao, Yansong Pan, Le Xue, Yongfei Li, Weichao Du and Gang Chen

Gels 2025, 11(12), 939; https://doi.org/10.3390/gels11120939 - 22 Nov 2025

Viewed by 920

Abstract

Guar gum (GG) is a classic polysaccharide gel former in drilling fluids, but its native network is hindered by high water-insoluble residue, modest yield-point (YP) build-up and poor tolerance to temperature ≥ 120 °C and salinity ≥ 12 wt% NaCl. Here we transformed [...] Read more.

Guar gum (GG) is a classic polysaccharide gel former in drilling fluids, but its native network is hindered by high water-insoluble residue, modest yield-point (YP) build-up and poor tolerance to temperature ≥ 120 °C and salinity ≥ 12 wt% NaCl. Here we transformed GG into a sulfonated guar gum (SGG) hydrogel via alkaline etherification with sodium 3-chloro-2-hydroxy-propane sulfonate. FTIR, EA and TGA corroborate the grafting of –SO₃⁻ groups (DS = 0.18), while rheometry shows that a 0.3 wt% SGG aqueous gel exhibits 34% higher YP/PV ratio and stronger shear-thinning than native GG, indicating a denser yet still reversible three-dimensional network. In 4 wt% Ca-bentonite mud the SGG gel film reduces API fluid loss by 12% and maintains YP/PV = 0.33 after hot-rolling at 120 °C, a retention 4.7-fold that of GG; likewise, in 12 wt% NaCl brine the gel still affords YP/PV = 0.44, evidencing electrostatically reinforced hydration layers that resist ionic compression. Linear-swell tests reveal shale inhibition improved by 14%. The introduced –SO₃⁻ functions strengthen inter-chain repulsion and water binding, yielding a thermally robust, salt-tolerant polysaccharide gel network. As a green, high-performance gel additive, SGG offers a promising route for next-generation water-based drilling fluids subjected to high temperature and high salinity. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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23 pages, 1275 KB

Open AccessReview

Research Progress of Micro-Nano Bubbles (MNBs) in Petroleum Engineering

by Yubo Lan, Dongyan Qi, Jiawei Li, Tong Yu, Tianyang Liu, Wenting Guan, Min Yuan, Kunpeng Wan and Zhengxiao Xu

Gels 2025, 11(11), 866; https://doi.org/10.3390/gels11110866 - 29 Oct 2025

Cited by 2 | Viewed by 1715

Abstract

Micro-nano bubbles (MNBs), typically characterized by diameters ranging from tens of micrometers to hundreds of nanometers, have gained significant attention in recent years due to advancements in nanotechnology and related characterization methods. This technology has shown great promise in the field of petroleum [...] Read more.

Micro-nano bubbles (MNBs), typically characterized by diameters ranging from tens of micrometers to hundreds of nanometers, have gained significant attention in recent years due to advancements in nanotechnology and related characterization methods. This technology has shown great promise in the field of petroleum engineering. Among the various applications, the integration of MNBs with gel technology plays a critical role in enhancing drilling safety. This paper aims to systematically review the current status, challenges, and optimization strategies for the application of MNBs in petroleum engineering, with a particular focus on their combined use with gel technology in oilfield applications. The paper first introduces the preparation methods and physicochemical properties of MNBs tailored for oilfield applications. It then systematically reviews the use of MNBs in the following three key areas of petroleum engineering: drilling, enhanced oil recovery (EOR), and oil–water separation. The paper also compares domestic and international technological approaches, highlighting the challenges associated with the large-scale application of MNBs in China. Notably, in the areas of drilling and enhanced oil recovery, the synergistic use of MNBs and gel technology has demonstrated significant potential. The gel–MNB combined technology demonstrates particular promise for China’s special reservoirs, as gel’s high molecular weight compensates for MNBs’ sedimentation defects, while their synergistic effects on interfacial tension reduction and drilling fluid stabilization provide an eco-efficient approach for extreme conditions. Additionally, focusing on the combined application of gel and MNB technology, along with adjustments in gel stability and MNB size, could offer a promising solution for the efficient and sustainable development of special reservoirs (such as those with high temperature, pressure, and salinity) in China. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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22 pages, 4279 KB

Open AccessArticle

Development and Mechanism of the Graded Polymer Profile-Control Agent for Heterogeneous Heavy Oil Reservoirs Under Water Flooding

by Tiantian Yu, Wangang Zheng, Xueqian Guan, Aifen Li, Dechun Chen, Wei Chu and Xin Xia

Gels 2025, 11(11), 856; https://doi.org/10.3390/gels11110856 - 26 Oct 2025

Cited by 2 | Viewed by 742

Abstract

During water flooding processes, the high viscosity of heavy oil and significant reservoir heterogeneity often lead to severe water channeling and low sweep efficiency. Addressing the limitations of traditional hydrophobically associating polymer-based profile-control agents—such as significant adsorption loss, mechanical degradation during reservoir migration, [...] Read more.

During water flooding processes, the high viscosity of heavy oil and significant reservoir heterogeneity often lead to severe water channeling and low sweep efficiency. Addressing the limitations of traditional hydrophobically associating polymer-based profile-control agents—such as significant adsorption loss, mechanical degradation during reservoir migration, resulting in a limited effective radius and short functional duration—this study developed a polymeric graded profile-control agent suitable for highly heterogeneous conditions. The physicochemical properties of the system were comprehensively evaluated through systematic testing of its apparent viscosity, salt tolerance, and anti-aging performance. The microscopic oil displacement mechanisms in porous media were elucidated by combining CT scanning and microfluidic visual displacement experiments. Experimental results indicate that the agent exhibits significant hydrophobic association behavior, with a critical association concentration of 1370 mg·L⁻¹, and demonstrates a “low viscosity at low temperature, high viscosity at high temperature” rheological characteristic. At a concentration of 3000 mg·L⁻¹, the apparent viscosity of the solution is 348 mPa·s at 30 °C, rising significantly to 1221 mPa·s at 70 °C. It possesses a salinity tolerance of up to 50,000 mg·L⁻¹, and a viscosity retention rate of 95.4% after 90 days of high-temperature aging, indicating good injectivity, reservoir compatibility, and thermal stability. Furthermore, within a concentration range of 500–3000 mg·L⁻¹, the agent can effectively emulsify Gudao heavy oil, forming O/W emulsion droplets with sizes ranging from 40 to 80 μm, enabling effective plugging of pore throats of corresponding sizes. CT scanning and microfluidic displacement experiments further reveal that the agent possesses a graded control function: in the near-wellbore high-concentration zone, it primarily relies on its aqueous phase viscosity-increasing capability to control the mobility ratio; upon entering the deep reservoir low-concentration zone, it utilizes “emulsion plugging” to achieve fluid diversion, thereby expanding the sweep volume and extending the effective treatment period. This research outcome provides a new technical pathway for the efficient development of highly heterogeneous heavy oil reservoirs. Full article

(This article belongs to the Topic Polymer Gels for Oil Drilling and Enhanced Recovery)

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