Gels | Special Issue : Gels for Oil Drilling and Enhanced Recovery

Research

Jump to: Review

14 pages, 2887 KiB

Open AccessArticle

Synthesis and Plugging Performance of Nano-Micron Polymeric Gel Microsphere Plugging Agents for Oil-Based Drilling Fluids

by Kecheng Liu, Ren Wang, Kesheng Rong, Zebin Yin, Tiemei Lu, Yongsheng Yu, Yingying Li, Zexing Yang, Jie Yang and Zhen Zhao

Gels 2023, 9(4), 290; https://doi.org/10.3390/gels9040290 - 1 Apr 2023

Cited by 5 | Viewed by 2006

Abstract

As shale gas recovery progresses to deep layers, the wellbore instability during drilling in applications of oil-based drilling fluids (OBFs) becomes increasingly severe. This research developed a plugging agent of nano-micron polymeric microspheres based on inverse emulsion polymerization. Through the single-factor analysis with [...] Read more.

As shale gas recovery progresses to deep layers, the wellbore instability during drilling in applications of oil-based drilling fluids (OBFs) becomes increasingly severe. This research developed a plugging agent of nano-micron polymeric microspheres based on inverse emulsion polymerization. Through the single-factor analysis with respect to the permeability plugging apparatus (PPA) fluid loss of drilling fluids, the optimal synthesis conditions of polymeric microspheres (AMN) were determined. Specifically, the optimal synthesis conditions are as follows: the monomer ratio of 2-acrylamido-2-methylpropanesulfonic acid (AMPS): Acrylamide (AM): N-vinylpyrrolidone (NVP) were 2:3:5; the total monomer concentration was 30%; the concentrations and HLB values of emulsifier (Span 80: Tween 60) were 10% and 5.1, respectively; the oil–water ratio of the reaction system was 1:1; the cross-linker concentration was 0.4%. The polymeric microsphere (AMN) produced via the optimal synthesis formula had the corresponding functional groups and good thermal stability. The size distribution of AMN ranged mainly from 0.5 to 10 μm. The introduction of AMND in OBFs can increase the viscosity and yield point of oil-based drilling fluids and slightly decrease the demulsification voltage but significantly reduce high temperature and high pressure (HTHP) fluid loss and permeability plugging apparatus (PPA) fluid loss. The OBFs with 3% polymeric microsphere dispersion (AMND) reduced the HTHP and PPA fluid loss by 42% and 50% at 130 °C, respectively. In addition, The AMND maintained good plugging performance at 180 °C. The AMN particles can block leakoff channels of artificial cores, effectively prevent the invasion of oil-based drilling fluids into formations and suppress pressure transfer. OBFs with 3% AMND enabled the corresponding equilibrium pressure to decrease by 69%, compared with that of the OBFs. The polymeric microspheres had a wide particle size distribution. Thus, they can well match leakage channels at various scales and form plugging layers via compression–deformation and packed accumulation, so as to prevent oil-based drilling fluid from invading formations and improve wellbore stability. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

15 pages, 5403 KiB

Open AccessArticle

Investigation of Polymer Gel Reinforced by Oxygen Scavengers and Nano-SiO₂ for Flue Gas Flooding Reservoir

by Wenli Qiao, Guicai Zhang, Ping Jiang and Haihua Pei

Gels 2023, 9(4), 268; https://doi.org/10.3390/gels9040268 - 24 Mar 2023

Cited by 2 | Viewed by 1531

Abstract

Polymer gel plugging is an effective technique for gas mobility control in flue gas flooding reservoirs. However, the performance of polymer gels is extremely susceptible to the injected flue gas. A reinforced chromium acetate/partially hydrolyzed polyacrylamide (HPAM) gel, using thiourea as the oxygen [...] Read more.

Polymer gel plugging is an effective technique for gas mobility control in flue gas flooding reservoirs. However, the performance of polymer gels is extremely susceptible to the injected flue gas. A reinforced chromium acetate/partially hydrolyzed polyacrylamide (HPAM) gel, using thiourea as the oxygen scavenger and nano-SiO₂ as the stabilizer, was formulated. The related properties were evaluated systematically, including gelation time, gel strength, and long-term stability. The results indicated that the degradation of polymers was effectively suppressed by oxygen scavengers and nano-SiO₂. The gel strength would be increased by 40% and the gel kept desirable stability after aging for 180 days at elevated flue gas pressures. Dynamic light scattering (DLS) analysis and Cryo-scanning electron microscopy (Cryo-SEM) revealed that nano-SiO₂ was adsorbed on polymer chains by hydrogen bonding, which improved the homogeneity of gel structure and thus enhanced the gel strength. Besides, the compression resistance of gels was studied by creep and creep recovery tests. The failure stress of gel with the addition of thiourea and nanoparticles could reach up to 35 Pa. The gel retained a robust structure despite extensive deformation. Moreover, the flow experiment indicated that the plugging rate of reinforced gel still maintained up to 93% after flue gas flooding. It is concluded that the reinforced gel is applicable for flue gas flooding reservoirs. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

17 pages, 2885 KiB

Open AccessArticle

Preparation and Performance Evaluation of a Plugging Agent with an Interpenetrating Polymer Network

by Zengbao Wang, Yitian Liu, Weian Huang, Xiong Yang, Ziao Liu and Xushuo Zhang

Gels 2023, 9(3), 205; https://doi.org/10.3390/gels9030205 - 7 Mar 2023

Cited by 4 | Viewed by 1981

Abstract

In view of the problems of polymer cross-linked elastic particle plugging agents commonly used in oilfields, including easy shear, poor temperature resistance, and weak plugging strength for large pores, the introduction of particles with certain rigidity and network structure, and cross-linking with a [...] Read more.

In view of the problems of polymer cross-linked elastic particle plugging agents commonly used in oilfields, including easy shear, poor temperature resistance, and weak plugging strength for large pores, the introduction of particles with certain rigidity and network structure, and cross-linking with a polymer monomer can improve the structural stability, temperature resistance, and plugging effect, and the preparation method is simple and low-cost. An interpenetrating polymer network (IPN) gel was prepared in a stepwise manner. The conditions of IPN synthesis were optimized. The IPN gel micromorphology was analyzed by SEM and the viscoelasticity, temperature resistance, and plugging performance were also evaluated. The optimal polymerization conditions included a temperature of 60 °C, a monomer concentration of 10.0–15.0%, a cross-linker concentration of 1.0–2.0% of monomer content, and a first network concentration of 20%. The IPN showed good fusion degree with no phase separation, which was the prerequisite for the formation of high-strength IPN, whereas particle aggregates reduced the strength. The IPN had better cross-linking strength and structural stability, with a 20–70% increase in the elastic modulus and a 25% increase in temperature resistance. It showed better plugging ability and erosion resistance, with the plugging rate reaching 98.9%. The stability of the plugging pressure after erosion was 3.8 times that of a conventional PAM-gel plugging agent. The IPN plugging agent improved the structural stability, temperature resistance, and plugging effect of the plugging agent. This paper provides a new method for improving the performance of a plugging agent in an oilfield. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

12 pages, 4395 KiB

Open AccessArticle

Synthesis and Characterization of an Novel Intercalated Polyacrylamide/Clay Nanocomposite

by Song Zhang, Falin Wei, Pingde Liu, Cheng Cai, Zhihui Zeng, Zhentao Yu, Zengbao Wang and Yingrui Bai

Gels 2023, 9(2), 104; https://doi.org/10.3390/gels9020104 - 24 Jan 2023

Cited by 2 | Viewed by 1912

Abstract

Solving the problem of the low temperature and low salt resistances of conventional polyacrylamide and the high cost of functional monomers, and thus, introducing it to the interlayer space provided by a layered structure for polymer modification, is a promising option. In this [...] Read more.

Solving the problem of the low temperature and low salt resistances of conventional polyacrylamide and the high cost of functional monomers, and thus, introducing it to the interlayer space provided by a layered structure for polymer modification, is a promising option. In this study, montmorillonite was used as the inorganic clay mineral, and an intercalated polyacrylamide/clay nanocomposite was synthesized via in situ intercalation polymerization. The optimal synthesis conditions were a clay content of 10.7%, preparation temperature of 11 °C, initiator concentration of 2.5 × 10⁻⁴ mol/L, and chain extender concentration of 5%. The IR results showed that the polymer was successfully introduced to the nanocomposite. The synthesized intercalated polyacrylamide/clay nanocomposite exhibited a better thickening effect, good viscoelasticity, and better salt resistance and thermal stability than polyacrylamide. In addition, the thickening capacity and thermal stability were superior to the salt-resistant polymer, with a 16.0% higher thickening viscosity and a 15.1% higher viscosity retention rate at 85 °C for 60 d. The intercalated polyacrylamide/clay nanocomposite further expanded the application of polyacrylamide in petroleum exploitation. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

14 pages, 3561 KiB

Open AccessArticle

Preparation of MOF-Based Core-Shell Gel Particles with Catalytic Activity and Their Plugging Performance

by Fengbao Liu, Jinsheng Sun and Xiao Luo

Gels 2023, 9(1), 44; https://doi.org/10.3390/gels9010044 - 4 Jan 2023

Cited by 1 | Viewed by 2071

Abstract

Drilling fluid systems for deep and ultra-deep wells are hampered by both high-temperature downhole environments and lengthy cycle periods. Suppose that the gel particle-plugging agent, the primary treatment agent in the system, fails to offer durable and stable plugging performance. In such a [...] Read more.

Drilling fluid systems for deep and ultra-deep wells are hampered by both high-temperature downhole environments and lengthy cycle periods. Suppose that the gel particle-plugging agent, the primary treatment agent in the system, fails to offer durable and stable plugging performance. In such a scenario, the borehole wall is susceptible to instability and landslide after prolonged immersion, leading to downhole accidents. In this study, novel core-shell gel particles (modified ZIF) with ZIF particles employed as the core material and organosilicon-modified polyethylene polyamine (PEPA) as the polymer shell were fabricated using PEPA, in-house synthesized (3-aminopropyl) triethoxysilane (APTS), and the ZIF-8 metal-organic framework (MOF) as the raw materials to enhance the long-term plugging performance of gel plugging agents. The modified ZIF particles are nanoscale polygonal crystals and differ from conventional core-shell gel particles in that they feature high molecular sieve catalytic activity due to the presence of numerous interior micropores and mesopores. As a result, modified ZIF exhibits the performance characteristics of both rigid and flexible plugging agents and has an excellent catalytic cross-linking effect on the sulfonated phenolic resin (SMP-3) and sulfonated lignite resin (SPNH) in drilling fluids. Consequently, a cross-linking reaction occurs when SMP-3 and SPNH flow through the spacings in the plugging layer formed by the modified ZIF particles. This increases the viscosity of the liquid phase and simultaneously generates an insoluble gel, forming a particle-gel composite plugging structure with the modified ZIF and significantly enhancing the long-term plugging performance of the drilling fluid. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

19 pages, 8364 KiB

Open AccessArticle

Styrene-Lauryl Acrylate Rubber Nanogels as a Plugging Agent for Oil-Based Drilling Fluids with the Function of Improving Emulsion Stability

by Hongyan Du, Kaihe Lv, Jinsheng Sun, Xianbin Huang and Haokun Shen

Gels 2023, 9(1), 23; https://doi.org/10.3390/gels9010023 - 28 Dec 2022

Cited by 7 | Viewed by 2443

Abstract

With the exploration and development of unconventional oil and gas, the use frequency of oil-based drilling fluid (ODF) is increasing gradually. During the use of ODFs, wellbore instability caused by invasion of drilling fluid into formation is a major challenge. To improve the [...] Read more.

With the exploration and development of unconventional oil and gas, the use frequency of oil-based drilling fluid (ODF) is increasing gradually. During the use of ODFs, wellbore instability caused by invasion of drilling fluid into formation is a major challenge. To improve the plugging property of ODFs, nano-sized poly(styrene-lauryl acrylate) (PSL) rubber nanogels were synthesized using styrene and lauryl acrylate through soap-free emulsion polymerization method and were characterized using FTIR, NMR, SEM, TEM, particle size analysis and TGA. The results show that, due to good dispersion stability and oil-absorbing expansion ability, the PSL rubber nanogels have a wide range of adaptations for nano-scale pores to deposit a layer of dense filter cake on the surface of filter paper with various pore diameters, reducing the filtration of mineral oil and W/O emulsion significantly. Due to the unique wettability, the PSL rubber nanogels can be adsorbed stably at the oil–water interface and form a dense granular film to prevent droplets coalescing, which improves the emulsification stability of W/O emulsion. Furthermore, the PSL rubber nanogels are soap-free and compatible with ODFs without foaming problems. The PSL rubber nanogels can increase the hole-cleaning performance of ODFs by raising viscosity and yield point. The PSL rubber nanogels outperformed hydrophobic modified nano silica and polystyrene nanospheres in plugging and filtration reduction. Therefore, the PSL rubber nanogels are expected to be used as a new plugging agent in oil-based drilling fluid. This research provide important insights for the use of organic nanogels in ODFs and the optimization of plugging conditions. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

15 pages, 7365 KiB

Open AccessArticle

A Thermal-Responsive Zwitterionic Polymer Gel as a Filtrate Reducer for Water-Based Drilling Fluids

by Kaihe Lv, Hongyan Du, Jinsheng Sun, Xianbin Huang and Haokun Shen

Gels 2022, 8(12), 832; https://doi.org/10.3390/gels8120832 - 16 Dec 2022

Cited by 11 | Viewed by 2525

Abstract

It is crucial to address the performance deterioration of water-based drilling fluids (WDFs) in situations of excessive salinity and high temperature while extracting deep oil and gas deposits. The focus of research in the area of drilling fluid has always been on filter [...] Read more.

It is crucial to address the performance deterioration of water-based drilling fluids (WDFs) in situations of excessive salinity and high temperature while extracting deep oil and gas deposits. The focus of research in the area of drilling fluid has always been on filter reducers that are temperature and salt resistant. In this study, a copolymer gel (PAND) was synthesized using acrylamide, N-isopropyl acrylamide, and 3-dimethyl (methacryloyloxyethyl) ammonium propane sulfonate through free-radical polymerization. The copolymer gel was then studied using FTIR, NMR, TGA, and element analysis. The PAND solution demonstrated temperature and salt stimulus response characteristics on rheology because of the hydrophobic association effect of temperature-sensitive monomers and the anti-polyelectrolyte action of zwitterionic monomers. Even in conditions with high temperatures (180 °C) and high salinities (30 wt% NaCl solution), the water-based drilling fluid with 1 wt% PAND displayed exceptional rheological and filtration properties. Zeta potential and scanning electron microscopy (SEM) were used to investigate the mechanism of filtration reduction. The results indicated that PAND could enhance bentonite particle colloidal stability, prevent bentonite particle aggregation, and form a compact mud cake, all of which are crucial for reducing the filtration volume of water-based drilling fluid. The PAND exhibit excellent potential for application in deep and ultra-deep drilling engineering, and this research may offer new thoughts on the use of zwitterionic polymer gel in the development of smart water-based drilling fluid. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

16 pages, 4194 KiB

Open AccessArticle

Investigation on Filtration Control of Zwitterionic Polymer AADN in High Temperature High Pressure Water-Based Drilling Fluids

by Ren Wang, Jie Yang, Luman Liu, Jianlong Wang, Zhenbo Feng, Die Zhang, Shan Gao, Jiao Wang, Han Ren and Baotong Hui

Gels 2022, 8(12), 826; https://doi.org/10.3390/gels8120826 - 14 Dec 2022

Cited by 5 | Viewed by 2630

Abstract

With the exploration and development of high-temperature and high-salt deep oil and gas, more rigorous requirements are warranted for the performance of water-based drilling fluids (WBDFs). In this study, acrylamide, 2-acrylamide-2-methylpropanesulfonic acid, diallyl dimethyl ammonium chloride, and N-vinylpyrrolidone were synthesized by free radical [...] Read more.

With the exploration and development of high-temperature and high-salt deep oil and gas, more rigorous requirements are warranted for the performance of water-based drilling fluids (WBDFs). In this study, acrylamide, 2-acrylamide-2-methylpropanesulfonic acid, diallyl dimethyl ammonium chloride, and N-vinylpyrrolidone were synthesized by free radical copolymerization in an aqueous solution to form a temperature and salt-resistant zwitterionic polymer gel filtration loss reducer (AADN). The zwitterionic polymer had excellent adsorption and hydration groups, which could effectively combine with bentonite through hydrogen bonds and electrostatic attraction, strengthening the hydration film thickness on the surface of bentonite, and promoting the stable dispersion of drilling fluid. In addition, the reverse polyelectrolyte effect of zwitterionic polymers strengthened the drilling fluid’s ability to resist high-temperature and high-salt. The AADN-based drilling fluid showed excellent rheological and filtration control properties (FL_API < 8 mL, FL_HTHP < 29.6 mL) even after aging at high-temperature (200 °C) and high-salt (20 wt% NaCl) conditions. This study provides a new strategy for simultaneously improving the high-temperature and high-salt tolerance of WBDFs, presenting the potential for application in drilling in high-temperature and high-salt deep formations. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

17 pages, 6022 KiB

Open AccessArticle

Probing the Effect and Mechanism of Flue Gas on the Performance of Resorcinol/Hexamethylenetetramine-Based Polymer Gel in Flue Gas Flooding Reservoir

by Wenli Qiao, Guicai Zhang, Jianda Li, Ping Jiang and Haihua Pei

Gels 2022, 8(12), 772; https://doi.org/10.3390/gels8120772 - 26 Nov 2022

Cited by 1 | Viewed by 1644

Abstract

Polymer gel plugging is an effective method for gas mobility control in flue gas flooding reservoirs. However, the effect and mechanism of flue gas on the performance of polymer gels have rarely been reported. In this study, a polymer gel was prepared by [...] Read more.

Polymer gel plugging is an effective method for gas mobility control in flue gas flooding reservoirs. However, the effect and mechanism of flue gas on the performance of polymer gels have rarely been reported. In this study, a polymer gel was prepared by cross-linking hydrolyzed polyacrylamide (HPAM) and resorcinol/ hexamethylenetetramine (HMTA) to illuminate the influencing mechanism of flue gas composition on gel. The gel rheological testing results showed that flue gas promoted gelation performance, whereas it seriously threatened gel long-term stability, especially at high pressure conditions. The influence of CO₂ on the polymer gel had the characteristic of multiplicity. The hydrodynamic radius (R_h) and the initial viscosity of HPAM solution decreased in the presence of CO₂. Nonetheless, the dissolved CO₂ expedited the decomposition rate of HMTA into formaldehyde, which promoted the cross-linking process of the HPAM, leading to a shorter gelation time. Oxidation–reduction potential (ORP) tests and Fourier transform infrared spectroscopy (FTIR) analysis indicated that O₂ played a leading role in the oxidative degradation of HPAM compared to CO₂ and threatened the gel long-term stability at elevated gas pressures. To address the adverse effects caused by flue gas, it is highly desirable to develop polymer gels by adding oxygen scavengers or strengthening additives. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

14 pages, 4980 KiB

Open AccessArticle

Kinetic Hydrate Inhibition of Natural Gels in Complex Sediment Environments

by Jianlong Wang, Jinsheng Sun, Hang Bian, Qibing Wang, Zhenbo Feng, Cheng Lu, Han Ren, Rongchao Cheng, Jintang Wang and Ren Wang

Gels 2022, 8(12), 758; https://doi.org/10.3390/gels8120758 - 22 Nov 2022

Cited by 2 | Viewed by 1616

Abstract

Natural gels are emerging as a hotspot of global research for their greenness, environmental-friendliness, and good hydrate inhibition performance. However, previous studies mostly performed experiments for simple pure water systems and the inhibition mechanism in the sediment environment remains unclear. Given this, the [...] Read more.

Natural gels are emerging as a hotspot of global research for their greenness, environmental-friendliness, and good hydrate inhibition performance. However, previous studies mostly performed experiments for simple pure water systems and the inhibition mechanism in the sediment environment remains unclear. Given this, the inhibition performance of xanthan gum and pectin on hydrate nucleation and growth in sediment environments was evaluated via hydrate formation inhibition tests, and the inhibition internal mechanisms were revealed via a comprehensive analysis integrating various methods. Furthermore, the influences of natural gels on sediment dispersion stability and low-temperature fluid rheology were investigated. Research showed that the sediments of gas hydrate reservoirs in the South China Sea are mainly composed of micro-nano quartz and clay minerals. Xanthan gum and pectin can effectively inhibit the hydrate formation via the joint effects of the binding, disturbing, and interlayer mass transfer suppression processes. Sediments promote hydrate nucleation and yet inhibit hydrate growth. The interaction of sediments with active groups of natural gels weakens the abilities of gels to inhibit hydrate nucleation and reduce hydrate formation. Nonetheless, sediments help gels to slow down hydrate formation. Our comprehensive analysis pointed out that pectin with a concentration of 0.5 wt% can effectively inhibit the hydrate nucleation and growth while improving the dispersion stability and low-temperature rheology of sediment-containing fluids. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

15 pages, 2872 KiB

Open AccessArticle

New Zwitterionic Polymer as a Highly Effective Salt- and Calcium-Resistant Fluid Loss Reducer in Water-Based Drilling Fluids

by Luman Liu, Jinsheng Sun, Ren Wang, Fan Liu, Shifeng Gao, Jie Yang, Han Ren, Yuanzhi Qu, Rongchao Cheng, Yuan Geng and Zhenbo Feng

Gels 2022, 8(11), 735; https://doi.org/10.3390/gels8110735 - 11 Nov 2022

Cited by 16 | Viewed by 2703

Abstract

To control the filtration loss of drilling fluids in salt–gypsum formations, a novel type of zwitterionic polymer gel (DNDAP) was synthesized by free radical polymerization, which was used as a salt- and calcium-resistant fluid loss reducer for water-based drilling fluids (WBDF). DNDAP was [...] Read more.

To control the filtration loss of drilling fluids in salt–gypsum formations, a novel type of zwitterionic polymer gel (DNDAP) was synthesized by free radical polymerization, which was used as a salt- and calcium-resistant fluid loss reducer for water-based drilling fluids (WBDF). DNDAP was prepared with N, N-dimethylacrylamide (DMAA), N-vinylpyrrolidone (NVP), Diallyl dimethyl ammonium chloride (DMDAAC), 2-acrylamide-2-methylpropaneonic acid (AMPS), and isopentenol polyether (TPEG) as raw materials. Fourier transform infrared spectroscopy (FT-IR) and proton nuclear magnetic resonance (¹H-NMR) were used to characterize the composition and structure of the DNDAP copolymer. The thermal stability of DNDAP was evaluated by the use of thermogravimetric analysis (TGA). WBDF with DNDAP was analyzed for zeta potential and particle size and the corresponding filter cake underwent energy dispersive spectrum (EDS) analysis and scanning electron microscope (SEM) analysis. The results showed that the thermal decomposition of DNDAP mainly occurred above 303 °C. DNDAP exhibits excellent rheological and filtration properties in water-based drilling fluids, even under high-temperature aging (up to 200 °C) and high salinity (20 wt% NaCl or 5 wt% CaCl₂) environments. The strong adsorption effect of DNDAP makes the particle size of bentonite reasonably distributed to form a dense mud cake that reduces filtration losses. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

18 pages, 4294 KiB

Open AccessArticle

Comparative Studies on Thickeners as Hydraulic Fracturing Fluids: Suspension versus Powder

by Shenglong Shi, Jinsheng Sun, Kaihe Lv, Jingping Liu, Yingrui Bai, Jintang Wang, Xianbin Huang, Jiafeng Jin and Jian Li

Gels 2022, 8(11), 722; https://doi.org/10.3390/gels8110722 - 8 Nov 2022

Cited by 5 | Viewed by 1758

Abstract

To overcome the problems of long dissolution time and high investment in surface facilities of powder thickeners in hydraulic fracturing, a novel suspension of a thickener as a fracturing fluid was prepared using powder polyacrylamide, nano-silica, and polyethylene glycol by high-speed mixing. The [...] Read more.

To overcome the problems of long dissolution time and high investment in surface facilities of powder thickeners in hydraulic fracturing, a novel suspension of a thickener as a fracturing fluid was prepared using powder polyacrylamide, nano-silica, and polyethylene glycol by high-speed mixing. The suspension and powder were compared in terms of properties of solubility, rheological behavior, sand carrying, drag reduction, and gel breaking. The results showed that the suspension could be quickly diluted in brine within 5 min, whereas the dissolution time of powder was 120 min. The suspension exhibited better performance in salt resistance, temperature resistance, shear resistance, viscoelasticity, sand carrying, and drag reduction than powder. The powder solution was broken more easily and had a lower viscosity than suspension diluent. These improvements in properties of the suspension were due to the dispersion of nano-silica in the polymer matrix; the mobility of thickener chains was inhibited by the steric hindrance of the nano-silica. Nano-silica particles acted as crosslinkers by attaching thickener chains, which strengthened the network structure of the thickener solution. The presence of hydrogen bonds between the thickener matrix and the nano-silica restricted the local movement of thickener chains, leading to a stronger spatial network. Therefore, this novel suspension showed good potential for fracturing applications. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

14 pages, 3523 KiB

Open AccessArticle

Gel Stability of Calcium Bentonite Suspension in Brine and Its Application in Water-Based Drilling Fluids

by Zhenhua Zhao, Sinan Chen, Fengshan Zhou and Zhongjin Wei

Gels 2022, 8(10), 643; https://doi.org/10.3390/gels8100643 - 10 Oct 2022

Cited by 6 | Viewed by 2493

Abstract

With the development of the oil industry and the increasingly complex drilling environment, the performance of drilling fluids has to be constantly improved. In order to solve the problem of bentonite dispersion and hydration in a saline medium, a drilling fluid additive with [...] Read more.

With the development of the oil industry and the increasingly complex drilling environment, the performance of drilling fluids has to be constantly improved. In order to solve the problem of bentonite dispersion and hydration in a saline medium, a drilling fluid additive with good performance and acceptable cost was sought. The effects of several water-soluble polymers, such as cellulose polymers, synthetic polymers and natural polymers, on the rheology and gel suspension stability of calcium-based bentonite were compared in this study. Among the examined polymers, the xanthan gum biopolymer (XC) was the least negatively affected in the saline medium used. However, its high price limits its industrial application in oil and gas drilling fluids. In this study, a salt-tolerant polymer, modified vegetable gum (MVG), was prepared by a cross-linking modification of a natural plant gum, which is abundant and cheap. Then, a salt-tolerant polymer mixture called SNV was prepared, composed of the salt-resistant natural polymer MVG and the biopolymer XC. The salt tolerance and slurry ability of SNV and common water-soluble polymers were evaluated and compared. We then selected the most suitable Herschel–Bulkley model to fit the rheological curve of the SNV–bentonite aqueous suspension system. SNV improved the rheological properties of the calcium-based bentonite slurry and the dispersion stability of bentonite. In an SNV concentration of 0.35%, the apparent viscosity (AV) of the base slurry increased from 2 mPa·s to 32 mPa·s, and the low shear reading value at 3 rpm increased from 0 dia to 5 dia. This could greatly improve the viscosity and cutting carrying capacity of the bentonite drilling fluid. The bentonite drilling fluid prepared with SNV could be directly slurried with brine and even seawater; this means that when drilling in ocean, coastal saline water and high-salinity-surface saline water areas, the slurry preparation cost and preparation time can be conveniently reduced. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

12 pages, 3671 KiB

Open AccessArticle

Improving the Weak Gel Structure of an Oil-Based Drilling Fluid by Using a Polyamide Wax

by Xianbin Huang, Xu Meng, Mao Li, Jinsheng Sun, Kaihe Lv and Chongyang Gao

Gels 2022, 8(10), 631; https://doi.org/10.3390/gels8100631 - 6 Oct 2022

Cited by 5 | Viewed by 4166

Abstract

Oil-based drilling fluids (OBDFs) are widely used, but there are common problems associated with them, such as low yield point and poor cutting–carrying and hole cleaning ability. In this paper, a polyamide wax (TQ-1) was synthesized from dimeric acid and 1,6-hexanediamine to improve [...] Read more.

Oil-based drilling fluids (OBDFs) are widely used, but there are common problems associated with them, such as low yield point and poor cutting–carrying and hole cleaning ability. In this paper, a polyamide wax (TQ-1) was synthesized from dimeric acid and 1,6-hexanediamine to improve the weak gel structure of OBDFs. The TQ-1 was characterized by Fourier transform infrared spectroscopy (FTIR) and thermogravimetric analysis (TGA). Then the effect of the TQ-1 on the stability of the water-in-oil emulsion was studied by sedimentation observation, stability analysis, an electrical stability test, and particle size measurement. The effect of the TQ-1 on the rheological properties of the water-in-oil emulsion was analyzed by viscosity vs. shear rate test and the three-interval thixotropic test. Finally, the performance of the TQ-1 in OBDFs was comprehensively evaluated. The experimental results showed that the initial thermal decomposition temperature of the TQ-1 was 195 °C, indicating that the TQ-1 had good thermal stability. After adding the TQ-1, the emulsion became more stable since the emulsion stability index (TSI) value decreased when the emulsions were placed for a period of time and the demulsification voltage was increased. The TQ-1 could form a weak gel structure in the water-in-oil emulsions, which made the emulsions show excellent shear thinning and thixotropy. TQ-1 can improve the demulsification voltage of OBDFs, greatly improve the yield point and gel strength, and largely reduce the sedimentation factor (SF). In addition, TQ-1 has good compatibility with OBDFs, and in our study the high-temperature and high-pressure (HTHP) filtration decreased slightly after adding the TQ-1. According to theoretical analysis, the mechanism of TQ-1 of improving the weak gel structure of OBDFs is that the polar amide group can form a spatial network structure in nonpolar solvents through hydrogen bonding. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

21 pages, 5198 KiB

Open AccessArticle

Compatibility Evaluation of In-Depth Profile Control Agents for Low-Permeability Fractured Reservoirs

by Xuanran Li, Jincai Wang, Jun Ni, Libing Fu, Anzhu Xu and Lun Zhao

Gels 2022, 8(9), 575; https://doi.org/10.3390/gels8090575 - 9 Sep 2022

Cited by 3 | Viewed by 1712

Abstract

Under the background that the in-depth profile control technology is gradually applied in low-permeability fractured reservoirs, this paper regards block H of Changqing Oilfield as the research object, referring to the range of its physical parameters and field application data. Three common in-depth [...] Read more.

Under the background that the in-depth profile control technology is gradually applied in low-permeability fractured reservoirs, this paper regards block H of Changqing Oilfield as the research object, referring to the range of its physical parameters and field application data. Three common in-depth profile control agents (PCAs), nanosphere suspension, poly(ethylene glycol) single-phase gel particle (PEG) and cross-linked bulk gel and swelling particle (CBG-SP), are selected to investigate the compatibility between the fractured channels and the PCAs through a series of experiments. The experimental results show that the nanospheres with particle sizes of 100 nm and 300 nm have good injectivity and deep migration ability, which remains the overall core plugging rate at a high level. The residual resistance coefficient of 800 nm nanospheres decreases in a “cliff” manner along the injection direction due to the formation of blockage in the front section, resulting in a very low plugging rate in the rear section. The injection rate is an important parameter that affects the effect of PEG in the fractured channels. When the injection rate is lower than 0.1 mL/min, the plugging ability will be weakened, and if the injection rate is higher than 0.2 mL/min, the core plugging will occur. The appropriate injection rate will promote the better effect of PEG with the plugging rate > 90%. The average plugging rate of CBG-SP in fractured rock core is about 80%, and the overall control and displacement effect is good. Based on the experimental data of PCAs, the optimization criteria of slug configuration and pro-duction parameters are proposed. According to the principle “blocking, controlling and displacing”, references are provided for PCAs screening and parameters selection of field implementation. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

11 pages, 3258 KiB

Open AccessArticle

Formation-Damage Mechanism and Gel-Breaker-Free Drill-In Fluid for Carbonate Reservoir

by Qingchao Fang, Xin Zhao, Hao Sun, Zhiwei Wang, Zhengsong Qiu, Kai Shan and Xiaoxia Ren

Gels 2022, 8(9), 565; https://doi.org/10.3390/gels8090565 - 6 Sep 2022

Cited by 2 | Viewed by 2349

Abstract

Abundant oil and gas reserves have been proved in carbonates, but formation damage affects their production. In this study, the characteristics and formation-damage mechanism of the carbonate reservoir formation of the MS Oilfield in the Middle East were analyzed—utilizing X-ray diffraction, a scanning [...] Read more.

Abundant oil and gas reserves have been proved in carbonates, but formation damage affects their production. In this study, the characteristics and formation-damage mechanism of the carbonate reservoir formation of the MS Oilfield in the Middle East were analyzed—utilizing X-ray diffraction, a scanning electron microscope, slice identification, and mercury intrusion—and technical measures for preventing formation damage were proposed. An ‘improved ideal filling for temporary plugging’ theory was introduced, to design the particle size distribution of acid-soluble temporary plugging agents; a water-based drill-in fluid, which did not require gel-breaker treatment, was formed, and the properties of the drill-in fluid were tested. The results showed that the overall porosity and permeability of the carbonate reservoir formation were low, and that there was a potential for water-blocking damage. There were micro-fractures with a width of 80–120 μm in the formation, which provided channels for drill-in fluid invasion. The average content of dolomite is 90.25%, and precipitation may occur under alkaline conditions. The polymeric drill-in fluid had good rheological and filtration properties, and the removal rate of the filter cake reached 78.1% in the chelating acid completion fluid without using gel breakers. In the permeability plugging test, the drill-in fluid formed a tight plugging zone on the surface of the ceramic disc with a pore size up to 120 μm, and mitigated the fluid loss. In core flow tests, the drill-in fluid also effectively plugged the formation core samples by forming a thin plugging layer, which could be removed by the chelating acid completion fluid, indicated by return permeability higher than 80%. The results indicated that the drill-in fluid could mitigate formation damage without the treatment of gel breakers, thus improving the operating efficiency and safety. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

14 pages, 5818 KiB

Open AccessArticle

Nano-Modified Polymer Gels as Temperature- and Salt-Resistant Fluid-Loss Additive for Water-Based Drilling Fluids

by Jian Li, Jinsheng Sun, Kaihe Lv, Yuxi Ji, Jintao Ji and Jingping Liu

Gels 2022, 8(9), 547; https://doi.org/10.3390/gels8090547 - 29 Aug 2022

Cited by 19 | Viewed by 3073

Abstract

With the continuous exploration and development of oil and gas resources to deep formations, the key treatment agents of water-based drilling fluids face severe challenges from high temperatures and salinity, and the development of high temperature and salt resistance filtration reducers has always [...] Read more.

With the continuous exploration and development of oil and gas resources to deep formations, the key treatment agents of water-based drilling fluids face severe challenges from high temperatures and salinity, and the development of high temperature and salt resistance filtration reducers has always been the focus of research in the field of oilfield chemistry. In this study, a nano-silica-modified co-polymer (NS-ANAD) gel was synthesized by using acrylamide, isopropylacrylamide, 2-acrylamide-2-methyl propane sulfonic acid, diallyl dimethyl ammonium chloride, and double-bond-modified inorganic silica particles (KH570-SiO₂) through free radical co-polymerization. The introduction of nanotechnology enhances the polymer’s resistance to high temperature degradation, making it useful as a high-temperature-resistant fluid loss reducer. Moreover, the anions (sulfonates) and cations (quaternary ammonium) enhance the extension of the polymer and the adsorption on the surface of bentonite particles in a saline environment, which in turn improves the salt resistance of the polymer. The drilling fluids containing 2.0 wt% NS-ANAD co-polymer gels still show excellent rheological and filtration performance, even after aging in high temperature (200 °C) and high salinity (saturated salt) environments, showing great potential for application in deep and ultra-deep drilling engineering. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

10 pages, 5675 KiB

Open AccessArticle

Experimental Study on Matched Particle Size and Elastic Modulus of Preformed Particle Gel for Oil Reservoirs

by Kang Zhou, Dejun Wu and Zhibin An

Gels 2022, 8(8), 506; https://doi.org/10.3390/gels8080506 - 14 Aug 2022

Cited by 7 | Viewed by 1779

Abstract

Suitable elastic modulus and particle size of preformed particle gel are the keys to both diverting water flow and avoiding permanent impairment to reservoirs. Therefore, the paper aims at finding the best matched preformed particle gel for given reservoirs using sand-pack displacement experiments. [...] Read more.

Suitable elastic modulus and particle size of preformed particle gel are the keys to both diverting water flow and avoiding permanent impairment to reservoirs. Therefore, the paper aims at finding the best matched preformed particle gel for given reservoirs using sand-pack displacement experiments. The results show that the injection pressure of preformed particle gel with excessively small size and elastic modulus is relatively low, indicating poor capacity to increase flow resistance and reduce water channeling. On the other hand, if the particle size and elastic modulus of preformed particle gel are excessively large, the reservoir may be plugged and irreversibly damaged, affecting oil development performance. In fact, the best matched particle size and elastic modulus of preformed particle gel increase with the increase in reservoir permeability. Furthermore, the paper establishes a quantitative logarithmic model between the particle size of preformed particle gel and reservoir permeability. Finally, the established matching relationship is validated via microscopic visualization oil displacement experiments using a glass etching model. The validation experiments indicate that the preformed particle gel (60–80 mesh; 2–4 Pa) selected according to the matching relationship can effectively reduce water channeling and increase sweeping efficiency by as much as 55% compared with water flooding in the glass etching model with an average permeability of 2624 × 10⁻³ μm². Therefore, the established matching relationship can provide an effective guide when selecting the best suitable preformed particle gel for a given reservoir in more future applications. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

12 pages, 4378 KiB

Open AccessArticle

Experimental Study on Profile Control of Polymer and Weak Gel Molecules in Porous Media

by Xuanran Li, Jing Wei, Lun Zhao, Jun Ni, Libing Fu and Jincai Wang

Gels 2022, 8(8), 467; https://doi.org/10.3390/gels8080467 - 26 Jul 2022

Cited by 3 | Viewed by 1629

Abstract

Weak gel is a gel system formed by the mixing and crosslinking of a low-concentration polymer and a slow-release crosslinker. It can be used for profile control in deep reservoir, but its effect is greatly affected by mechanical shearing. Currently, the shearing effect [...] Read more.

Weak gel is a gel system formed by the mixing and crosslinking of a low-concentration polymer and a slow-release crosslinker. It can be used for profile control in deep reservoir, but its effect is greatly affected by mechanical shearing. Currently, the shearing effect on weak gel is mainly studied by way of mechanical stirring, while the effect of porous media shear on weak gel molecules and properties has been rarely discussed. In this paper, polymer solution, aluminum gel and phenolic gel were prepared. The molecular coil size, viscoelastic modulus and microscopic aggregation morphology in water solution of three systems before and after core shearing were investigated, and the injection performance of the three systems in cores with different permeabilities was tested by physical simulation experiments. The study results show that at equivalent permeability, the system with a larger equivalent sphere diameter of molecular coil is more seriously sheared and suffers greater viscosity loss. In the core with permeability of 1.0 D, polymer solution remains as the aggregation, while phenolic gel and aluminum gel cannot form network aggregations and they are inferior to polymer solution in migration capacity in the mid-deep part of the core. In the core with permeability of 1–5.8 D, the polymer solution remains as a Newtonian fluid, while phenolic gel and aluminum gel become purely viscous non-Newtonian fluids. The elastic modulus of aluminum gel and phenolic gel is four times more than that of a polymer. In the core with permeability higher than 8.5 D, aluminum gel and phenolic gel migrate with less effect by core shearing, and their profile control capacity in deep reservoir is higher than that of the polymer. In the core with permeability lower than 8.5 D, because the monomolecular activity of weak gels becomes poor, they migrate in porous media with more effect by core shearing, and their profile control and oil displacement capacity in deep reservoir is lower than that of the polymer. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

11 pages, 5335 KiB

Open AccessArticle

Molecular Simulation of Interactions between High-Molecular-Polymer Flocculation Gel for Oil-Based Drilling Fluid and Clay Minerals

by Zhijun He, Jintang Wang, Bo Liao, Yujing Bai, Zihua Shao, Xianbin Huang, Qi Wang and Yiyao Li

Gels 2022, 8(7), 442; https://doi.org/10.3390/gels8070442 - 15 Jul 2022

Cited by 7 | Viewed by 2316

Abstract

China has abundant shale gas resources with great potential, which may serve as a significant support for the development of a “low-carbon economy”. Domestic shale gas resources are buried deeply and difficult to exploit due to some prevalent issues, such as long horizontal [...] Read more.

China has abundant shale gas resources with great potential, which may serve as a significant support for the development of a “low-carbon economy”. Domestic shale gas resources are buried deeply and difficult to exploit due to some prevalent issues, such as long horizontal sections, severe development of reservoir fractures, strong sensitivity to water, borehole instability, etc. Compared to water-based drilling fluids, oil-based drilling fluid exhibits better inhibition and good lubricity and is thus broadly used in shale gas drilling, but it is confronted with the challenge of removing the harmful solid phase. Selective chemical flocculation is one of the most effective methods of removing the harmful solid phase in oil-based drilling fluid. In this study, interactions between the flocculation gel for oil-based drilling fluid and clay minerals were investigated by molecular simulation, which revealed the molecular-scale selectivity of the flocculation gel for rock cuttings with negative charges. Calculations showed that the flocculation gel is highly effective for the flocculation of negatively charged cuttings, but it is ineffective for flocculating neutral cuttings. The flocculation gel is not very effective for cuttings with high hydrophilicity, and it is totally ineffective for flocculating cuttings with poor hydrophilicity. Within a limited concentration range, the flocculation effect can be enhanced by increasing the flocculation gel concentration. The performance of the flocculation gel declined at elevated temperatures. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

17 pages, 6309 KiB

Open AccessArticle

Study on Screening Criteria of Gel-Assisted Polymer and Surfactant Binary Combination Flooding after Water Flooding in Strong Edge Water Reservoirs: A Case of Jidong Oilfield

by Fuquan Luo, Xiao Gu, Wenshuang Geng, Jian Hou and Changcheng Gai

Gels 2022, 8(7), 436; https://doi.org/10.3390/gels8070436 - 11 Jul 2022

Cited by 1 | Viewed by 1607

Abstract

Strong edge water reservoirs have sufficient natural energy. After long-term natural water flooding development, it is in the stage of ultrahigh water cut. There is an urgent need to change the development mode and improve the development effect. Taking Jidong Oilfield as an [...] Read more.

Strong edge water reservoirs have sufficient natural energy. After long-term natural water flooding development, it is in the stage of ultrahigh water cut. There is an urgent need to change the development mode and improve the development effect. Taking Jidong Oilfield as an example, the mechanism model of strong edge water reservoirs is established by using the method of numerical simulation. Then, the factors and rules affecting the effects of gel-assisted polymer and surfactant binary combination flooding are studied. The screening criteria of gel-assisted polymer and surfactant binary combination flooding in strong edge water reservoirs are obtained. The results show that the existence of edge water is not conducive to binary combination flooding. Smaller water volumetric multiples and larger oil-bearing areas are more suitable for binary combination flooding. Compared with closed reservoirs, binary combination flooding in strong edge water reservoirs is more difficult to establish a displacement pressure gradient. The reservoir with high crude oil viscosity is not suitable for binary combination flooding. Gel-assisted polymer and surfactant binary combination flooding can be adopted for reservoirs with an oil-bearing area greater than 0.2 km², a water volumetric multiple less than 200, and oil viscosity less than 100 mPa·s. The research results are of guiding significance for the reservoir selection of gel-assisted polymer and surfactant binary combination flooding after natural water flooding. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

15 pages, 2627 KiB

Open AccessArticle

Gene Expression and Characterization of Iturin A Lipopeptide Biosurfactant from Bacillus aryabhattai for Enhanced Oil Recovery

by Deepak A. Yaraguppi, Zabin K. Bagewadi, Nilkamal Mahanta, Surya P. Singh, T. M. Yunus Khan, Sanjay H. Deshpande, Chaitra Soratur, Simita Das and Dimple Saikia

Gels 2022, 8(7), 403; https://doi.org/10.3390/gels8070403 - 25 Jun 2022

Cited by 9 | Viewed by 3510

Abstract

Biosurfactants are eco-friendly surface-active molecules recommended for enhanced oil recovery techniques. In the present study, a potential lipopeptide (biosurfactant) encoding the iturin A gene was synthesized from Bacillus aryabhattai. To improvise the yield of the lipopeptide for specific applications, current research tends [...] Read more.

Biosurfactants are eco-friendly surface-active molecules recommended for enhanced oil recovery techniques. In the present study, a potential lipopeptide (biosurfactant) encoding the iturin A gene was synthesized from Bacillus aryabhattai. To improvise the yield of the lipopeptide for specific applications, current research tends toward engineering and expressing recombinant peptides. An iturin A gene sequence was codon-optimized, amplified with gene-specific primers, and ligated into the pET-32A expression vector to achieve high-level protein expression. The plasmid construct was transformed into an E. coli BL21 DE3 host to evaluate the expression. The highly expressed recombinant iturin A lipopeptide was purified on a nickel nitrilotriacetic acid (Ni-NTA) agarose column. Sodium dodecyl sulfate polyacrylamide gel electrophoresis (SDS-PAGE) revealed that the purity and molecular mass of iturin A was 41 kDa. The yield of recombinant iturin A was found to be 60 g/L with a 6.7-fold increase in comparison with our previously published study on the wild strain. The approach of cloning a functional fragment of partial iturin A resulted in the increased production of the lipopeptide. When motor oil was used, recombinant protein iturin A revealed a biosurfactant property with a 74 ± 1.9% emulsification index (E24). Purified recombinant protein iturin A was characterized by mass spectrometry. MALDI-TOF spectra of trypsin digestion (protein/trypsin of 50:1 and 25:1) showed desired digested mass peaks for the protein, further confirming the identity of iturin A. The iturin A structure was elucidated based on distinctive spectral bands in Raman spectra, which revealed the presence of a peptide backbone and lipid. Recombinant iturin A was employed for enhanced oil recovery through a sand-packed column that yielded 61.18 ± 0.85% additional oil. Hence, the novel approach of the high-level expression of iturin A (lipopeptide) as a promising biosurfactant employed for oil recovery from Bacillus aryabhattai is not much reported. Thus, recombinant iturin A demonstrated its promising ability for efficient oil recovery, finding specific applications in petroleum industries. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

17 pages, 7296 KiB

Open AccessArticle

A Novel Numerical Model of Gelant Inaccessible Pore Volume for In Situ Gel Treatment

by Jianqiao Leng, Xindi Sun, Mingzhen Wei and Baojun Bai

Gels 2022, 8(6), 375; https://doi.org/10.3390/gels8060375 - 13 Jun 2022

Cited by 3 | Viewed by 1782

Abstract

Inaccessible pore volume (IAPV) can have an important impact on the placement of gelant during in situ gel treatment for conformance control. Previously, IAPV was considered to be a constant factor in simulators, yet it lacked dynamic characterization. This paper proposes a numerical [...] Read more.

Inaccessible pore volume (IAPV) can have an important impact on the placement of gelant during in situ gel treatment for conformance control. Previously, IAPV was considered to be a constant factor in simulators, yet it lacked dynamic characterization. This paper proposes a numerical simulation model of IAPV. The model was derived based on the theoretical hydrodynamic model of gelant molecules. The model considers both static features, such as gelant and formation properties, and dynamic features, such as gelant rheology and retention. To validate our model, we collected IAPV from 64 experiments and the results showed that our model fit moderately into these lab results, which proved the robustness of our model. The results of the sensitivity test showed that, considering rheology and retention, IAPV in the matrix dramatically increased when flow velocity and gelant concentration increased, but IAPV in the fracture maintained a low value. Finally, the results of the penetration degree showed that the high IAPV in the matrix greatly benefited gelant placement near the wellbore situation with a high flow velocity and gelant concentration. By considering dynamic features, this new numerical model can be applied in future integral reservoir simulators to better predict the gelant placement of in situ gel treatment for conformance control. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

19 pages, 9579 KiB

Open AccessArticle

Identification of Gas Channeling and Construction of a Gel-Enhanced Foam Plugging System for Oxygen-Reduced Air Flooding in the Changqing Oilfield

by Tengfei Wang, Liangliang Wang, Haoliang Qin, Cong Zhao, Zongxian Bai and Xingbang Meng

Gels 2022, 8(6), 373; https://doi.org/10.3390/gels8060373 - 13 Jun 2022

Cited by 5 | Viewed by 2390

Abstract

The accurate identification of gas channeling channels during foam-assisted oxygen-reduced air flooding (FAORAF) and the analysis of the main controlling factors are essential to propose reasonable and effective countermeasures to enhance oil recovery (EOR). However, there are few comprehensive studies on identifying gas [...] Read more.

The accurate identification of gas channeling channels during foam-assisted oxygen-reduced air flooding (FAORAF) and the analysis of the main controlling factors are essential to propose reasonable and effective countermeasures to enhance oil recovery (EOR). However, there are few comprehensive studies on identifying gas channeling channels, the influencing factors, and the corresponding plugging EOR systems in FAORAF. The channeling channels of the injection and production wells of the Changqing Oilfield, China, under varying development schemes are identified utilizing fuzzy membership function theory in this work to obtain their primary distribution. The characteristics and influence factors of gas channeling channels are analyzed by numerical simulation using CMG. The recovery performance of each foam blocking system is evaluated by twin-tube sand pack models. As well, based on the features of reservoir fractures, a new gel-enhanced foam plugging system is developed. The results show that channeling channels chiefly develop along NE 60–70° and that foam could reduce gas channeling. Natural and artificial fractures are the principal factors causing gas channeling, followed by the injection method and gas injection rate. Under the premise of the injection and migration efficiency, the optimal gel system is a 0.1% HPAM + 0.1% organic chromium crosslinking agent. The addition of gel increases the viscosity of the liquid phase and strengthens the mechanical strength of the foam liquid film. At a permeability ratio of 12, the recovery factors of the binary plugging systems composed of microspheres, PEG, and gel combined with foam are 40.89%, 45.85%, and 53.33%, respectively. The movable gel foam system has a short breaking time (only 18 days) and a recovery factor of about 40% at a permeability ratio of 20. To be suitable for oil reservoirs with microfractures, an improved ternary gel foam system—0.1% HPAM + 0.1% chromium crosslinking agent + 0.05–0.1% nano-SiO₂—is developed. Compared with the binary gel foam system, the recovery rate of the new nano-SiO₂ gel foam system after 15 days of ageing using the core splitting test is 25.24% during the FAORAF process, increasing by 12.38%. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

13 pages, 4578 KiB

Open AccessArticle

Use of Betaine-Based Gel and Its Potential Application in Enhanced Oil Recovery

by Yuman Wu, Jie Zhang, Sanbao Dong, Yongfei Li, Michal Slaný and Gang Chen

Gels 2022, 8(6), 351; https://doi.org/10.3390/gels8060351 - 3 Jun 2022

Cited by 12 | Viewed by 2481

Abstract

In this paper, a betaine-based gel containing 2.0% erucamide propyl betaine (EAPB), 0.5% oleic acid amide propyl betaine (OAPB), and 0.1% KCl was prepared for use as a fracturing fluid. The performance evaluation showed that KCl may improve the temperature resistance and increase [...] Read more.

In this paper, a betaine-based gel containing 2.0% erucamide propyl betaine (EAPB), 0.5% oleic acid amide propyl betaine (OAPB), and 0.1% KCl was prepared for use as a fracturing fluid. The performance evaluation showed that KCl may improve the temperature resistance and increase the viscosity of the optimized fracturing fluid. At 80 °C, the apparent viscosity of the viscoelastic surfactant (VES)-based fracturing fluid was approximately 50 mPa·s. Furthermore, the gel had high shear resistance, good viscosity stability, and high sand-carrying performance. After being sheared at 170 s⁻¹ for 60 min, the reduction in viscosity was 13.6%. The viscosity of the gel was relatively stable at room temperature (27 °C) for one week. In a suspension containing 10% sand (particle size < 0.45 mm, density = 2.75 g cm⁻³), the settling velocity of proppant particles was 1.15 cm h⁻¹. In addition, we detected that the critical micelle concentration of this gel was approximately 0.042 wt%. The viscosity could be reduced to <5 mPa·s at 60 °C within 1 h when 6.0% crude oil was present, and oil displacement experiments showed that the broken fracturing fluid can enhance the oil displacement rate up to 14.5%. This work may facilitate research on fracturing fluids and oil recovery. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

21 pages, 4364 KiB

Open AccessArticle

A Temperature-Sensitive Polymeric Rheology Modifier Used in Water-Based Drilling Fluid for Deepwater Drilling

by Zhongyi Wang, Jinsheng Sun, Kun Zhang, Kaihe Lv, Xianbin Huang, Jintang Wang, Ren Wang and Xu Meng

Gels 2022, 8(6), 338; https://doi.org/10.3390/gels8060338 - 30 May 2022

Cited by 10 | Viewed by 3378

Abstract

Rheology modifiers are essential for the flat rheology of water-based drilling fluids in deepwater. The low temperature thickening of deepwater water-based drilling fluids results in dramatic rheological changes in the 20–30 °C range. To address such problems, NIPAM with a self-polymerized product LCST [...] Read more.

Rheology modifiers are essential for the flat rheology of water-based drilling fluids in deepwater. The low temperature thickening of deepwater water-based drilling fluids results in dramatic rheological changes in the 20–30 °C range. To address such problems, NIPAM with a self-polymerized product LCST of 32–35 °C was selected as the main body for synthesis. While introducing the hydrophilic monomer AM to enhance the thickening properties, the hydrophobic monomer BA was selected to reduce the LCST of the product. In this paper, a temperature-sensitive polymeric rheology modifier (PNBAM) was synthesized by emulsion polymerization using N-isopropyl acrylamide, acrylamide, and butyl acrylate as monomers. The PNBAM was characterized using infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), and nuclear magnetic resonance hydrogen spectroscopy (NMR). The rheological properties, temperature resistance, and salt resistance of PNBAM in the base fluid (BF) were tested. The performance of PNBAM in the drilling fluid system was also evaluated, and a water-based drilling fluid system of flat rheology for deepwater was formulated. The rheological modification mechanism of PNBAM was analyzed by turbidity analysis, particle size analysis, and zeta analysis. Experimental results show that PNBAM has good rheological properties. PNBAM is temperature resistant to 150 °C, salt-resistant to 30 wt%, and calcium resistant to 1.0 wt%. PNBAM also has good flat rheology characteristics in drilling fluid systems: AV_4°C:AV_25°C = 1.27, PV_4°C:PV_25°C = 1.19. Mechanistic analysis showed that the LCST (Lower Critical Solution Temperature) of 0.2 wt% PNBAM in an aqueous solution was 31 °C. Through changes in hydrogen bonding forces with water, PNBAM can regulate its hydrophilic and hydrophobic properties before and after LCST, which thus assists BF to achieve a flat rheological effect. In summary, the temperature-sensitive effect of PNBAM has the property of enhancing with increasing temperature. While the tackifying effect of conventional rheology modifiers diminishes with increasing temperature, the temperature-sensitive effect of PNBAM gives it an enhanced thickening effect with increasing temperature, making it a more novel rheology modifier compared to conventional treatment additives. After LCST, compared to conventional rheology modifiers (XC), PNBAM has a more pronounced thermo-thickening effect, improving the main rheological parameters of BF by more than 100% or even up to 200% (XC less than 50%). This contributes to the flat rheology of drilling fluids. PNBAM has good application prospects and serves as a good reference for the development of other rheology modifiers. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

13 pages, 3407 KiB

Open AccessArticle

Temperature- and Salt-Resistant Micro-Crosslinked Polyampholyte Gel as Fluid-Loss Additive for Water-Based Drilling Fluids

by Jian Li, Jinsheng Sun, Kaihe Lv, Yuxi Ji, Jingping Liu, Xianbin Huang, Yingrui Bai, Jintang Wang, Jiafeng Jin and Shenglong Shi

Gels 2022, 8(5), 289; https://doi.org/10.3390/gels8050289 - 6 May 2022

Cited by 34 | Viewed by 3187

Abstract

With increasing global energy consumption, oil/gas drilling has gradually expanded from conventional shallow reservoirs to deep and ultra-deep reservoirs. However, the harsh geological features including high temperature and high salinity in ultra-deep reservoirs have become a critical challenge faced by water-based drilling fluids [...] Read more.

With increasing global energy consumption, oil/gas drilling has gradually expanded from conventional shallow reservoirs to deep and ultra-deep reservoirs. However, the harsh geological features including high temperature and high salinity in ultra-deep reservoirs have become a critical challenge faced by water-based drilling fluids (WDFs), which seriously deteriorate the rheology and fluid loss properties, causing drilling accidents, such as wellbore instability and formation collapse. In this study, a novel temperature- and salt-resistant micro-crosslinked polyampholyte gel was synthesized using N,N-dimethylacrylamide, diallyldimethyl ammonium chloride, 2-acrylamido-2-methylpropanesulfonic acid, maleic anhydride and chemical crosslinking agent triallylamine through free radical copolymerization. Due to the synergistic effect of covalent micro-crosslinking and the reverse polyelectrolyte effect of amphoteric polymers, the copolymer-based drilling fluids exhibit outstanding rheological and filtration properties even after aging at high temperatures (up to 200 °C) and high salinity (saturated salt) environments. In addition, the zeta potential and particle size distribution of copolymer-based drilling fluids further confirmed that the copolymer can greatly improve the stability of the base fluid suspension, which is important for reducing the fluid-loss volume of WDFs. Therefore, this work will point out a new direction for the development of temperature- and salt-resistant drilling fluid treatment agents. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

23 pages, 8356 KiB

Open AccessArticle

Experimental Study on Physicochemical Properties of a Shear Thixotropic Polymer Gel for Lost Circulation Control

by Jingbin Yang, Yingrui Bai, Jinsheng Sun, Kaihe Lv, Jinliang Han and Liyao Dai

Gels 2022, 8(4), 229; https://doi.org/10.3390/gels8040229 - 7 Apr 2022

Cited by 19 | Viewed by 3662

Abstract

Polymer gel lost circulation control technology is a common and effective technique to control fractured lost circulation. The performance of a lost circulation control agent is the key to the success of lost circulation control techniques. In this study, rheological tests were used [...] Read more.

Polymer gel lost circulation control technology is a common and effective technique to control fractured lost circulation. The performance of a lost circulation control agent is the key to the success of lost circulation control techniques. In this study, rheological tests were used to study the physical and chemical properties of a shear thixotropic polymer gel system, such as anti-dilution, high temperature resistance and high salt resistance. The results showed that the shear thixotropic polymer gel system had the ability of anti-dilution, and the gel could be formed under a mixture of 3 times volume of heavy salt water and 3/7 volume white oil, and could keep the structure and morphology stable. Secondly, the gel formation time of shear thixotropic polymer gel system could be controlled and had good injection performance under the condition of 140 °C and different initiator concentrations. Meanwhile, the shear thixotropic polymer gel system had the ability of high temperature and high salt resistance, and the gel formation effect was good in salt water. When the scanning frequency was 4 Hz and the temperature was 140 °C, the storage modulus (G′) of the gel was 4700 Pa. The gel was dominated by elasticity and had excellent mechanical properties. By scanning electron microscope observation, it was found that the shear thixotropic polymer gel system had a stable three-dimensional reticular space skeleton under the condition of high salt, indicating that it had excellent ability to tolerate high salt. Therefore, the shear thixotropic polymer gel had high temperature and high salt resistance, dilution resistance and good shear responsiveness. It is believed that the results presented in this work are of importance for extending real-life applications of shear thixotropic polymer gel systems. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

Review

Jump to: Research

17 pages, 1435 KiB

Open AccessReview

Research Progress of High-Temperature Resistant Functional Gel Materials and Their Application in Oil and Gas Drilling

by Junwei Fang, Xiong Zhang, Liang Li, Jianjun Zhang, Xin Shi and Guangqiang Hu

Gels 2023, 9(1), 34; https://doi.org/10.3390/gels9010034 - 30 Dec 2022

Cited by 9 | Viewed by 3387

Abstract

With the development of oil exploration, the number of complex situations encountered in the drilling process is continuously increasing. During the operation of large displacement and horizontal wells, the safe density window of drilling fluid is narrow in complex formations and the lost [...] Read more.

With the development of oil exploration, the number of complex situations encountered in the drilling process is continuously increasing. During the operation of large displacement and horizontal wells, the safe density window of drilling fluid is narrow in complex formations and the lost circulation problem is becoming increasingly prominent. This can easily cause the drilling fluid to enter the formation from inside the well through lost circulation channels, which will prolong the drilling cycle, increase drilling costs, affect geological logging, and could cause a series of malignant accidents (such as blowout, sticking of a drilling tool, borehole collapse, and well abandoned). According to the severity, common lost circulation can be classified into three types: fractured lost circulation, karst cave lost circulation, and permeability lost circulation. Currently, researchers are developing different types of lost circulation materials (LCMs) for various lost circulation situations. Compared with conventional lost circulation control methods, the polymer gel lost circulation control technique applies a three-dimensional cage-like viscoelastic body formed via the crosslinking reaction of polymer gels. These materials have strong deformability and can enter fractures and holes through extrusion and deformation without being restricted by lost circulation channels. They then settle in the lost circulation formation and form a plugging layer through a curing reaction or swelling effect. Among the polymer gel LCMs, high-temperature resistant polymer gels can either be used alone or in combination with other LCMs, bringing the advantages of adjustable gelation time, strong lost circulation control ability, and strong filtration ability of the plugging slurry. Moreover, they are suitable for the lost circulation control of microporous leaky layer and have limited influence on the performance of drilling fluids. Therefore, the high-temperature resistant polymer gel lost circulation control technique is increasingly becoming a hot spot in the research of LCMs nowadays. This paper summarizes the research progress into high-temperature resistant functional gels for profile control and water shutoff, lost circulation prevention and control, and hydraulic fracturing. Furthermore, the current application status of high-temperature resistant gels and high-temperature resistant gel temporary plugging agents is demonstrated, followed by a detailed overview of the gel-breaking methods. Overall, this research lays the theoretical foundation for the application and promotion of high-temperature resistant gels. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

30 pages, 10868 KiB

Open AccessEditor’s ChoiceReview

Polymer Gels Used in Oil–Gas Drilling and Production Engineering

by Jinliang Han, Jinsheng Sun, Kaihe Lv, Jingbin Yang and Yuhong Li

Gels 2022, 8(10), 637; https://doi.org/10.3390/gels8100637 - 7 Oct 2022

Cited by 18 | Viewed by 7327

Abstract

Polymer gels are widely used in oil–gas drilling and production engineering for the purposes of conformance control, water shutoff, fracturing, lost circulation control, etc. Here, the progress in research on three kinds of polymer gels, including the in situ crosslinked polymer gel, the [...] Read more.

Polymer gels are widely used in oil–gas drilling and production engineering for the purposes of conformance control, water shutoff, fracturing, lost circulation control, etc. Here, the progress in research on three kinds of polymer gels, including the in situ crosslinked polymer gel, the pre-crosslinked polymer gel and the physically crosslinked polymer gel, are systematically reviewed in terms of the gel compositions, crosslinking principles and properties. Moreover, the advantages and disadvantages of the three kinds of polymer gels are also comparatively discussed. The types, characteristics and action mechanisms of the polymer gels used in oil-gas drilling and production engineering are systematically analyzed. Depending on the crosslinking mechanism, in situ crosslinked polymer gels can be divided into free-radical-based monomer crosslinked gels, ionic-bond-based metal cross-linked gels and covalent-bond-based organic crosslinked gels. Surface crosslinked polymer gels are divided into two types based on their size and gel particle preparation method, including pre-crosslinked gel particles and polymer gel microspheres. Physically crosslinked polymer gels are mainly divided into hydrogen-bonded gels, hydrophobic association gels and electrostatic interaction gels depending on the application conditions of the oil–gas drilling and production engineering processes. In the field of oil–gas drilling engineering, the polymer gels are mainly used as drilling fluids, plugging agents and lost circulation materials, and polymer gels are an important material that are utilized for profile control, water shutoff, chemical flooding and fracturing. Finally, the research potential of polymer gels in oil–gas drilling and production engineering is proposed. The temperature resistance, salinity resistance, gelation strength and environmental friendliness of polymer gels should be further improved in order to meet the future technical requirements of oil–gas drilling and production. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

22 pages, 8408 KiB

Open AccessReview

Types and Performances of Polymer Gels for Oil-Gas Drilling and Production: A Review

by Shaofei Lei, Jinsheng Sun, Kaihe Lv, Qitao Zhang and Jingbin Yang

Gels 2022, 8(6), 386; https://doi.org/10.3390/gels8060386 - 17 Jun 2022

Cited by 26 | Viewed by 4551

Abstract

Polymer gels with suitable viscoelasticity and deformability have been widely used for formation plugging and lost circulation control, profile control, and water shutoff. This article systematically reviews the research progress on the preparation principle, temperature resistance, salt resistance, and mechanical properties of the [...] Read more.

Polymer gels with suitable viscoelasticity and deformability have been widely used for formation plugging and lost circulation control, profile control, and water shutoff. This article systematically reviews the research progress on the preparation principle, temperature resistance, salt resistance, and mechanical properties of the ground and in situ crosslinked polymer gels for oil-gas drilling and production engineering. Then, it comparatively analyzes the applicable conditions of the two types of polymer gel. To expand the application range of polymer gels in response to the harsh formation environments (e.g., high temperature and high salinity), we reviewed strategies for increasing the high temperature resistance, high salt resistance, and rheological/mechanical strengths of polymer gels. This article provides theoretical and technical references for developing and optimizing polymer gels suitable for oil-gas drilling and production. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

26 pages, 1303 KiB

Open AccessReview

Comprehensive Review of Polymer and Polymer Gel Treatments for Natural Gas-Related Conformance Control

by Ali Al Brahim, Baojun Bai and Thomas Schuman

Gels 2022, 8(6), 353; https://doi.org/10.3390/gels8060353 - 5 Jun 2022

Cited by 10 | Viewed by 3410

Abstract

Conformance problems often exist in natural gas-related activities, resulting in excessive water production from natural gas production wells and/or excessive natural gas production from oil production wells. Several mechanical and chemical solutions were reported in the literature to mitigate the conformance problems. Among [...] Read more.

Conformance problems often exist in natural gas-related activities, resulting in excessive water production from natural gas production wells and/or excessive natural gas production from oil production wells. Several mechanical and chemical solutions were reported in the literature to mitigate the conformance problems. Among the chemical solutions, two classes of materials, namely polymer gels and water-soluble polymers, have been mostly reported. These systems have been mainly reviewed in several studies for their applications as water shutoff treatments for oil production wells. Natural gas production wells exhibit different characteristics and have different properties which could impact the performance of the chemical solutions. However, there has not been any work done on reviewing the applications of these systems for the challenging natural gas-related shutoff treatments. This study provides a comprehensive review of the laboratory evaluation and field applications of these systems used for water control in natural gas production wells and gas shutoff in oil production wells, respectively. The first part of the paper reviews the in-situ polymer gel systems, where both organically and inorganically crosslinked systems are discussed. The second part presents the water-soluble polymers with a focus on their disproportionate permeability reduction feature for controlling water in gas production wells. The review paper provides insights into the reservoir conditions, treatment design and intervention, and the success rate of the systems applied. Furthermore, the outcomes of the paper will provide knowledge regarding the limitations of the existing technologies, current challenges, and potential paths forwards. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Figure 1

15 pages, 284 KiB

Open AccessReview

Status and Prospect of Drilling Fluid Loss and Lost Circulation Control Technology in Fractured Formation

by Jingbin Yang, Jinsheng Sun, Yingrui Bai, Kaihe Lv, Guodong Zhang and Yuhong Li

Gels 2022, 8(5), 260; https://doi.org/10.3390/gels8050260 - 21 Apr 2022

Cited by 27 | Viewed by 5385

Abstract

Lost circulation in fractured formation is the first major technical problem that restricts improvements in the quality and efficiency of oil and gas drilling engineering. Improving the success rate of one-time lost circulation control is an urgent demand to ensure “safe, efficient and [...] Read more.

Lost circulation in fractured formation is the first major technical problem that restricts improvements in the quality and efficiency of oil and gas drilling engineering. Improving the success rate of one-time lost circulation control is an urgent demand to ensure “safe, efficient and economic” drilling in oilfields all over the world. In view of the current situation, where drilling fluid loss occurs and the plugging mechanism of fractured formation is not perfect, this paper systematically summarizes the drilling fluid loss mechanism and model of fractured formation. The mechanism and the main influencing factors to improve the formation’s pressure-bearing capacity, based on stress cage theory, fracture closure stress theory, fracture extension stress theory and chemical strengthening wellbore theory, are analyzed in detail. The properties and interaction mechanism of various types of lost circulation materials, such as bridging, high water loss, curable, liquid absorption and expansion and flexible gel, are introduced. The characteristics and distribution of drilling fluid loss in fractured formation are also clarified. Furthermore, it is proposed that lost circulation control technology for fractured formation should focus on the development of big data and intelligence, and adaptive and efficient intelligent lost circulation material should be continuously developed, which lays a theoretical foundation for improving the success rate of lost circulation control in fractured formation. Full article

(This article belongs to the Special Issue Gels for Oil Drilling and Enhanced Recovery)

► Show Figures

Graphical abstract

Journal Menu

Journal Browser

Gels for Oil Drilling and Enhanced Recovery

Share This Special Issue

Special Issue Editors

Special Issue Information

Keywords

Benefits of Publishing in a Special Issue

Related Special Issue

Published Papers (33 papers)

Research

Review

Further Information

Guidelines

MDPI Initiatives

Follow MDPI