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Gels for Oil and Gas Industry Applications (2nd Edition)

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

Deadline for manuscript submissions: closed (29 February 2024) | Viewed by 13751

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Prof. Dr. Qing You

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Guest Editor

School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, China
Interests: gel; conformance control; temporary plugging; enhanced oil recovery
Special Issues, Collections and Topics in MDPI journals

Prof. Dr. Guang Zhao

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Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qindao 266580, China
Interests: profile control; water shutoff; chemical materials; enhanced oil recovery
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Dr. Xindi Sun

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Guest Editor

Physics and Engineering Department, College of Health, Engineering and Science, Slippery Rock University of Pennsylvania, Slippery Rock, PA 16057, USA
Interests: gel conformance control; CO₂ EOR; CO₂ sequestration; chemical EOR
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

We are grateful to all authors, reviewers and readers for their responses to the first volume of our Special Issue on "Gels for Oil and Gas Industry Applications". You can access these articles for free via the link:

Gels for Oil and Gas Industry Applications (1st Edition)

This volume of the Special Issue is focused on the application of gels in oil and gas fields to improve hydrocarbon recovery. A broad range of topics will be discussed, including but not limited to field application cases, novel gel development, the experimental evaluation of gel performance for conformance control, fracturing, lab- and field-scale numerical simulations, etc.

Gels, such as in-situ gels and preformed particle gels, have been widely used in the oil and gas industry to control excess water production and gas channeling, which contributes significantly to improving hydrocarbon recovery. Based on different application conditions, many novel gels have been developed. The evaluation of novel gels is crucial since the properties of some polymers can be altered under high temperatures, high salinity, or high CO2 conditions. In addition, due to the complexity of the reservoirs, some gels may perform differently in the field than in the lab. In this case, the experiences gained from field application studies are very valuable for future gel development, evaluation, and application. As a cost-effective method, numerical simulation is used widely in the oil and gas industry to simulate gel treatment, analyze production data, and predict future production after gel treatment. Any studies related to gels for oil and gas field applications can advance the understanding of the gel performance in porous media and large channels, which is of significant importance to the oil and gas industry.

We look forward to the submission of new studies on gel development or gel application in the oil and gas industry. Submissions of experimental or field studies are welcomed.

Dr. Qing You
Prof. Dr. Guang Zhao
Dr. Xindi Sun
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

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. Gels is an international peer-reviewed open access monthly 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 2600 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.

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15 pages, 10854 KiB

Open AccessArticle

Micro and Macro Flooding Mechanism and Law of a Gel Particle System in Strong Heterogeneous Reservoirs

by Rongjun Ye, Lei Wang, Wenjun Xu, Jianpeng Zhang and Zhengbang Chen

Gels 2024, 10(2), 151; https://doi.org/10.3390/gels10020151 - 19 Feb 2024

Viewed by 1027

Abstract

To address the issue of ineffective injection resulting from the consistent channeling of injected water through highly permeable channels in ultra-deep, high-temperature, high-salinity, and strongly heterogeneous reservoirs during the production process, a gel particle profile control agent suitable for high-temperature and high-salinity conditions was chosen. With the help of the glass etching visual microscopic model and the heterogeneous long core model, the formation mechanism of a water flooding channeling path and the distribution law of the remaining oil were explored, the microscopic profile control mechanism of the different parameters was clarified, and the profile control effect of macroscopic core displacement was analyzed. The research shows that the formation mechanism of a water flooding channeling path is dominated by the distribution law of the permeability section and the connection mode between different penetration zones. The remaining oil types after water flooding are mainly contiguous block, parallel throats, and multi-branch clusters. The profile control effect of gel particles on reservoir vertical heterogeneity is better than that of reservoir lateral heterogeneity. It was found that 10 wt% submicron particles with a median diameter of 600 nm play a good role in profiling and plugging pores of 5–20 μm. In addition, 10 wt% micron-sized particles with a median diameter of 2.63 μm mainly play a strong plugging role in the pores of 20–30 μm, and 5 wt% micron-sized particles with a median diameter of 2.63 μm mainly form a weak plugging effect on the pores of 10–20 μm. The overall profile control effect of 10 wt% submicro particles is the best, and changes in concentration parameters have a more significant effect on the profile control effect. In the macroscopic core profile control, enhanced oil recovery (EOR) can reach 16%, and the gel particles show plugging, deformation migration, and re-plugging. The research results provide theoretical guidance for tapping the potential of the remaining oil in strong heterogeneous reservoirs. To date, the gel particles have been applied in the Tahe oilfield and have produced an obvious profile control effect; the oil production has risen to the highest value of 26.4 t/d, and the comprehensive water content has fallen to the lowest percentage of 32.1%. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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15 pages, 6085 KiB

Open AccessArticle

A Supramolecular Reinforced Gel Fracturing Fluid with Low Permeability Damage Applied in Deep Reservoir Hydraulic Fracturing

by Yongping Huang, Xinlong Yao, Caili Dai, Yining Wu, Lin Li and Bin Yuan

Gels 2024, 10(1), 2; https://doi.org/10.3390/gels10010002 - 20 Dec 2023

Viewed by 1014

Abstract

Gel fracturing fluid is the optimum fracturing fluid for proppant suspension, which is commonly applied in deep reservoir hydraulic fracturing. The content of polymers and crosslinkers in gel fracturing fluid is usually high to meet the needs of high-temperature resistance, leading to high costs and reservoir permeability damage caused by incomplete gel-breaking. In this paper, a supramolecular reinforced gel (SRG) fracturing fluid was constructed by strengthening the supramolecular force between polymers. Compared with single network gel (SNG) fracturing fluid, SRG fracturing fluid could possess high elasticity modulus (G′ = 12.20 Pa) at lower polymer (0.4 wt%) and crosslinker (0.1 wt%) concentrations. The final viscosity of SRG fracturing fluid was 72.35 mPa·s, meeting the temperature resistance requirement of gel fracturing fluid at 200 °C. The gel-breaking time could be extended to 90–120 min using an encapsulated gel breaker. Gel particles are formed after the gel fracturing fluid is broken. The median particle size of gel particles in the SRG-breaking solution was 126 nm, which was much smaller than that in the industrial gel (IDG) breaking fluid (587 nm). The damage of the SRG-breaking solution to the core permeability was much less than the IDG-breaking solution. The permeability damage of cores caused by the SRG-breaking solutions was only about half that of IDG-breaking solutions at 1 mD. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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22 pages, 8010 KiB

Open AccessArticle

Alkaline Hydrolysis of Waste Acrylic Fibers Using the Micro-Water Method and Its Application in Drilling Fluid Gel Systems

by Wenjun Long, Zhongjin Wei, Fengshan Zhou, Shaohua Li, Kang Yin, Yu Zhao, Siting Yu and Hang Qi

Gels 2023, 9(12), 974; https://doi.org/10.3390/gels9120974 - 13 Dec 2023

Cited by 1 | Viewed by 1290

Abstract

Filtrate reducer is a drilling fluid additive that can effectively control the filtration loss of drilling fluid to ensure the safe and efficient exploitation of oilfields. It is the most widely used treatment agent in oilfields. Due to its moderate conditions and controllable procedure, alkaline hydrolysis of high-purity waste polyacrylonitrile has been utilized for decades to produce filtrate reducer on a large scale in oilfields. However, the issues of long hydrolysis time, high viscosity of semi-finished products, high drying cost, and tail gas pollution have constrained the development of the industry. In this study, low-purity waste acrylic fiber was first separated and purified using high-temperature hydroplastization, and the hydrolyzed product was obtained using alkaline hydrolysis with the micro-water method, which was called MW−HPAN. The hydrolysis reaction was characterized using X-ray diffraction, scanning electron microscopy, infrared spectroscopy, and thermogravimetric analysis, and the elemental analysis showed a hydrolysis degree of 73.21%. The experimental results showed that after aging at 180 °C for 16 h, the filtration volume of the freshwater base slurry with 0.30% dosage and 4% brine base slurry with 1.20% dosage was 12.7 mL and 18.5 mL, respectively. The microstructure and particle size analysis of the drilling fluid gel system showed that MW−HPAN could prevent the agglomeration of clay and maintain a reasonable particle size distribution even under the combined deteriorating effect of high temperature and inorganic cations, thus forming a dense filter cake and achieving a low filtrate volume of the drilling fluid gel system. Compared with similar commercially available products, MW−HPAN has better resistance to temperature and salt in drilling fluid gel systems, and the novel preparation method is promising to be extended to practical production. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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17 pages, 6782 KiB

Open AccessArticle

Field and Experimental Investigations on the Effect of Reservoir Drill-In Fluids on Penetration Rate and Drilling Cost in Horizontal Wells

by Neamat Jameel and Jagar A. Ali

Gels 2023, 9(7), 510; https://doi.org/10.3390/gels9070510 - 24 Jun 2023

Cited by 3 | Viewed by 1737

Abstract

In this study, the reservoir drill-in fluid (RDF) was modified and optimized to improve the rheological properties and reduce the filtration properties of the drilling fluid used for drilling the oil-bearing zone horizontally. In polymer science, degradation generally refers to a complex process, by which a polymeric material exposed to the environment and workload loses its original properties. Degradation is usually an unwanted process. In certain cases, however, controlled polymer degradation is useful. For instance, it can improve the processability of the polymer or can be used in recycling or natural decomposition of waste polymer. Thus, the drilling fluid and parameter data of 30 horizontal wells that were drilled in the south of Iraq were collected using several reservoir drill-in fluids (RDFs), including FLOPRO, salt polymer mud (SPM), non-damaged fluid (NDF), and FLOPRO_PTS-200 (including the polymer thermal stabilizer). The obtained results showed that the polymer temperature stabilizer (PTS-200) enabled reducing the filtration rate by 44.33% and improved the rheological properties by 19.31% as compared with FLOPRO. Additionally, the average cost of NDF and SPM drilling fluids for drilling the horizontal section of the selected wells is around USD 96,000 and USD 91,000, respectively. However, FLOPRO-based drilling fluid showed less cost for drilling the horizontal section, which is USD 45,000. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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11 pages, 2925 KiB

Open AccessArticle

Study on Water-Soluble Phenolic Resin Gels for High-Temperature and High-Salinity Oil Reservoir

by Yunling Ran, Guicai Zhang, Ping Jiang and Haihua Pei

Gels 2023, 9(6), 489; https://doi.org/10.3390/gels9060489 - 14 Jun 2023

Cited by 4 | Viewed by 1125

Abstract

High water cut of produced fluid is one of the most common problems in reservoir development. At present, injecting plugging agents and other profile control and water plugging technologies are the most widely used solutions. With the development of deep oil and gas resources, high-temperature and high-salinity (HTHS) reservoirs are becoming increasingly common. Conventional polymers are prone to hydrolysis and thermal degradation under HTHS conditions, making polymer flooding or polymer-based gels less effective. Phenol–aldehyde crosslinking agent gels can be applied to different reservoirs with a wide range of salinity, but there exist the disadvantage of high cost of gelants. The cost of water-soluble phenolic resin gels is low. Based on the research of former scientists, copolymers consisting of acrylamide (AM) and 2-Acrylamido-2-Methylpropanesulfonic acid (AMPS) and modified water-soluble phenolic resin were used to prepare gels in the paper. The experimental results show that the gelant with 1.0 wt% AM-AMPS copolymer (AMPS content is 47%), 1.0 wt% modified water-soluble phenolic resin and 0.4 wt% thiourea has gelation time of 7.5 h, storage modulus of 18 Pa and no syneresis after aging for 90 days at 105 °C in simulated Tahe water of 22 × 10⁴ mg/L salinity. By comprehensively comparing the effectiveness of the gels prepared by a kind of phenolic aldehyde composite crosslinking agent and modified water-soluble phenolic resin, it is found that the gel constructed by the modified water-soluble phenolic resin not only reduces costs, but also has shorter gelation time and higher gel strength. The oil displacement experiment with a visual glass plate model proves that the forming gel has good plugging ability and thus improves the sweep efficiency. The research expands the application range of water-soluble phenolic resin gels, which has an important implication for profile control and water plugging in the HTHS reservoirs. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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13 pages, 4458 KiB

Open AccessArticle

Synthesis and Performance Evaluation of a Novel Nanoparticle Coupling Expanded Granule Plugging Agent

by Xuejiao Li, Qi Li, Meilong Fu, Li Li, Lingyang Su and Yingyang Wang

Gels 2023, 9(6), 479; https://doi.org/10.3390/gels9060479 - 12 Jun 2023

Viewed by 909

Abstract

This study focuses on the characteristics of fractured and vuggy high-temperature and high-salt reservoirs in the Tahe Oilfield. The Acrylamide/2-acrylamide-2-methylpropanesulfonic copolymer salt was selected as a polymer; the hydroquinone and hexamethylene tetramine was selected as the crosslinking agent with a ratio of 1:1; the nanoparticle SiO₂ was selected, and its dosage was optimized to 0.3%; Additionally, a novel nanoparticle coupling polymer gel was independently synthesized. The surface of the gel was a three-dimensional network structure, with grids arranged in pieces and interlaced with each other, and the structure was very stable. The SiO₂ nanoparticles were attached to the gel skeleton, forming effective coupling and enhancing the strength of the gel skeleton. To solve the problem of complex gel preparation and transportation, the novel gel is compressed, pelletized, and dried into expanded particles through industrial granulation, and the disadvantage of the rapid expansion of expanded particles is optimized through physical film coating treatment. Finally, a novel nanoparticle coupling expanded granule plugging agent was developed. Evaluation of the performance of the novel nanoparticle coupling expanded granule plugging agent. With an increase in temperature and mineralization, the expansion multiplier of granules decreases; aged under high-temperature and high-salt conditions for 30 days, the expansion multiplier of granules can still reach 3.5 times, the toughness index is 1.61, and the long-term stability of the granules can be good; the water plugging rate of granules is 97.84%, which is superior to other widely used particle-based plugging agents. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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15 pages, 2736 KiB

Open AccessArticle

Injection of Gelling Systems to a Layered Reservoir for Conformance Improvement

by Konstantin Fedorov, Alexander Shevelev, Alexander Gilmanov, Andrey Arzhylovskiy, Denis Anuriev, Ivan Vydysh and Nikita Morozovskiy

Gels 2022, 8(10), 621; https://doi.org/10.3390/gels8100621 - 29 Sep 2022

Cited by 1 | Viewed by 1239

Abstract

The paper describes the introduction and estimation of performance criteria for the gelling agent injection technology based on a general approach to modeling physical and chemical enhanced oil recovery (EOR) methods. The current mathematical models do not include performance criteria for the process of gelling agent injection and do not allow for assessing the level of success of a treatment job in production wells. The paper introduces such criteria for the first time. To simulate the effect on injection wells, the mass conservation laws and the generalized flow law are used, and closing relations for the gelling rate are taken into account. A conformance control coefficient is introduced which characterizes the positive effect of well treatments and injectivity drop which characterizes the negative effect. The performance criteria allow for identifying the wells where the treatment jobs were the most successful. The model verification, based on the comparison of post-treatment injectivity estimated in the developed model, with Rosneft’s field data showed a satisfactory match. The developed correlations can be used as the basis for a surrogate model that allows for avoiding building sector geological and flow simulation models of the treated zone. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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23 pages, 5873 KiB

Open AccessArticle

Experimental Evaluation of the Rheological Properties and Influencing Factors of Gel Fracturing Fluid Mixed with CO₂ for Shale Gas Reservoir Stimulation

by Mingwei Wang, Wen Wu, Shuyang Chen, Song Li, Tao Li, Gensheng Ni, Yu Fu and Wen Zhou

Gels 2022, 8(9), 527; https://doi.org/10.3390/gels8090527 - 23 Aug 2022

Cited by 7 | Viewed by 1548

Abstract

Foam gel fracturing fluid has the characteristics of low formation damage, strong flowback ability, low fluid loss, high fluid efficiency, proper viscosity, and strong sand-carrying capacity, and it occupies a very important position in fracturing fluid systems. The rheological properties of gel fracturing fluid with different foam qualities of CO₂, under different experimental temperatures and pressures, have not been thoroughly investigated, and their influence on it was studied. To simulate the performance of CO₂ foam gel fracturing fluid under field operation conditions, the formula of the gel fracturing fluid was obtained through experimental optimization in this paper, and the experimental results show that the viscosity of gel fracturing fluid is 2.5 mPa·s (after gel breaking at a shear rate of 500 s⁻¹), the residue content is 1.3 mg/L, the surface tension is 25.1 mN/m, and the interfacial tension is 1.6 mN/m. The sand-carrying fluid has no settlement in 3 h with a 40% sand ratio of 40–70-mesh quartz sand. The core damage rate of foam gel fracturing fluid is less than 19%, the shear time is 90 min at 170 s⁻¹ and 90 °C, the viscosity of fracturing fluid is >50 mPa·s, and the temperature resistance and shear resistance are excellent. The gel fracturing fluid that was optimized was selected as the base fluid, which was mixed with liquid CO₂ to form the CO₂ foam fracturing fluid. This paper studied the rheological properties of CO₂ foam gel fracturing fluid with different CO₂ foam qualities under high temperature (65 °C) and high pressure (30 MPa) and two states of supercooled liquid (unfoamed) and supercritical state (foamed) through indoor pipe flow experiments. The effects of temperature, pressure, shear rate, foam quality, and other factors on the rheological properties of CO₂ foam gel fracturing fluid were considered, and it was confirmed that among all the factors, foam quality and temperature are the main influencing factors, which is of great significance for us to better understand and evaluate the flow characteristics of CO₂ foam gel fracturing fluid and the design of shale gas reservoir fracturing operations. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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16 pages, 7066 KiB

Open AccessArticle

Simulated Investigation in Wormhole Expansion Law of Gelling Acid Etching and Its Influencing Factors in Deep Carbonate Reservoirs

by Mingwei Wang, Wen Zhou, Song Li and Wen Wu

Gels 2022, 8(8), 470; https://doi.org/10.3390/gels8080470 - 27 Jul 2022

Cited by 5 | Viewed by 1841

Abstract

Acidizing with gelling acid is the key technology in developing a carbonate reservoir successfully. It is difficult for the laboratory to carry out the radial displacement experiment with a large rock core. It is necessary to establish the gelling acid wormhole expansion model under the radial conditions, simulate the gelling acid wormhole expansion law under the radial conditions, optimize the construction parameters, and provide the basis for the optimal design of carbonate reservoir matrix acidizing. The research objective is to simulate the gelling acid etching wormhole expansion in a deep carbonate reservoir and make clear its influencing factors, which are helpful for reservoir stimulation. The mathematical model of gelling acid wormhole expansion was established, considering the influence of pore microscopic characteristics on acid flow and acid rock reaction. The simulation results indicated that viscosity, surface reaction rate, and hydrogen ion diffusion coefficient have different effects on gelling acid etching wormhole. The spatial distribution of pores determines the trend of gelling acid solution and thus the shape of the armhole. Perforation completion has a significant impact on the expansion of gelling acid etching wormhole. The wormhole extends forward along the perforation hole, and perforation increases the length of the wormhole. This wormhole expansion law is very suitable in situations where a deep carbonate reservoir is needed for gelling acid fracturing. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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Review

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24 pages, 2021 KiB

Open AccessReview

Development and Applications of CO₂-Responsive Gels in CO₂ Flooding and Geological Storage

by Yanxu Ding, Yang Zhao, Xin Wen, Yueliang Liu, Ming Feng and Zhenhua Rui

Gels 2023, 9(12), 936; https://doi.org/10.3390/gels9120936 - 29 Nov 2023

Cited by 1 | Viewed by 932

Abstract

Gel systems are widely used as plugging materials in the oil and gas industry. Gas channeling can be mitigated by reducing the heterogeneity of the formation and the mobility ratio of CO₂ to crude oil. Cracks and other CO₂ leaking pathways can be plugged during the geological storage of CO₂ to increase the storage stability. By adding CO₂-responsive groups to the classic polymer gel’s molecular chain, CO₂ responsive gel is able to seal and recognize CO₂ in the formation while maintaining the superior performance of traditional polymer gel. The application of CO₂ responsive gels in oil and gas production is still in the stage of laboratory testing on the whole. To actually achieve the commercial application of CO₂ responsive gels in the oil and gas industry, it is imperative to thoroughly understand the CO₂ responsive mechanisms of the various types of CO₂ responsive gels, as well as the advantages and drawbacks of the gels and the direction of future development prospects. This work provides an overview of the research progress and response mechanisms of various types of CO₂ responsive groups and CO₂ responsive gels. Studies of the CO₂ responsive gel development, injectivity, and plugging performance are comprehensively reviewed and summarized. The shortcomings of the existing CO₂ responsive gels system are discussed and the paths for future CO₂ responsive gel development are suggested. Full article

(This article belongs to the Special Issue Gels for Oil and Gas Industry Applications (2nd Edition))

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